Toledo, 1988 III

CONTENTS

FOREWORD...... V

OPENING SESSION WELCOMING REMARKS MR. GUZMÁN SOLANA...... 1 «THE FUTURE OF SPAIN´S OIL SECTOR» MR. VÍCTOR PÉREZ PITA...... 3

SESSION I: OIL MARKET OUTLOOK INTRODUCTORY REMARKS MR. BIJAN MOSSAVAR - RAHMANI ...... 7 «WORLD OIL MARKET OUTLOOK FOR THE 1990S» MR. JOHN PIERCE FERRITER ...... 13 «OIL MARKETS AND OIL PRICES: A COMPARATIVE ANALYSIS» MR. WILLIAM W. HOGAN ...... 25 «PROSPECTS FOR THE WORLD OIL INDUSTRY» MR. ALAN NAISMITH BINDER ...... 53

SESSION II: THE RELATIONSHIP BETWEEN OIL AND MONEY INTRODUCTORY REMARKS MRS. EIJA MALMIVIRTA ...... 67 «CRUDE OIL FORWARD AND FUTURE MARKETS: A COMPARISON OF BRENT AND WTI» MR. ROBERT J. WEINER ...... 73 «THE ROLE OF FUTURES IN A GLOBAL ENERGY MARKET» MR. ROBERT RYAN...... 83 IV

«A PRACTITIONER´S VIEW OF THE OIL AND MONEY MARKETS» MR. ERNST WEIL ...... 95

SESSION III: ENERGY IN WESTERN EUROPE IN THE RUN-UP TO 1992 INTRODUCTORY REMARKS MR. JOSÉ SIERRA ...... 101 «THE WEST EUROPEAN NATURAL GAS MARKET IN THE PERSPECTIVE OF INTEGRATION AND ELECTRICITY DEMAND: NEW CHALLENGES TO ENERGY POLICY» MR. OYSTEIN NORENG ...... 105 «ELECTRICITY IN EUROPE IN THE RUN-UP TO 1992» MR. LARRY RUFF...... 115 «ENERGY, ENVIRONMENT AND THE 1992 SINGLE EUROPEAN MARKET» MR. MICHAEL J. WRINGLESWORTH...... 127 «OIL IN WESTERN EUROPE IN THE RUN-UP TO 1992» MR. JUAN SANCHO ROF...... 135

CLOSING SESSION CONCLUSIONS MR. BIJAN MOSSAVAR-RAHMANI...... 165

LIST OF PARTICIPANTS ...... 175 V

FOREWORD

REPSOL, COLECCIÓN «ENSAYO»

La colección «Ensayo» de Repsol pretende facilitar los elementos de juicio necesarios para abordar una fértil reflexión sobre los temas de mayor importancia y trascendencia para el sector del petróleo y el gas natural, así como sobre otras materias de interés general. Los ensayos y ponencias de esta colección serán publicados indistin- tamente en inglés y español. En ellos se reflejan los puntos de vista de cada uno de sus autores pero no, necesariamente, los de Repsol, S.A. y su grupo de empresas.

REPSOL, «ESSAY» COLLECTION

The Repsol «Essay» collection aims to provide background material to facilitate reflection on key subjects of prime importance to the oil and gas industry as well as other subjects of general interest. Essays and papers in this collection will be published in both English and Spanish. They express the opinions of the authors concerned but not necesarily those of Repsol, S.A. and its group of companies. 1

WELCOMING REMARKS

GUZMÁN SOLANA

Good morning ladies and gentlemen. I would like first to welcome you to the city of Toledo, for the second time the meeting place of the REPSOL-Harvard seminar. I scarcely need say that it is a pleasure for all of us to host this seminar that promises to be as interesting as the previous ones. In the last seminar we talked about the restructur ing that is taking place in the Spanish oil industry as a consequence of our integration in the European Economic Community (EEC). We also announced the creation of REPSOL, which has constituted a fundamental step in the rationalization of the public sector of the Spanish oil industry.

Since then we have experienced some important changes. The adap- tation of the oil industry to the EEC requirements has continued, mainly through the deregulation of the market at retail level. As for REPSOL, the company was partially floated in May, with the result that 30 percent of the shares are now in private hands.

In general terms, we can describe 1989 as a quiet year for oil mar- kets, with an important decrease in volatility. Nevertheless, we have 2 Opening Session

witnessed a moderate increase in oil demand at the world level, with a parallel rise in crude oil prices. If this trend continues in the future, there will be, without doubt, more room for accommodation of pro- duction quotas within OPEC and restoration of discipline within this organization. During 1989 the reintegration process of the oil in- dustry has continued, with both nontraditional and traditional oil companies concentrating on their upstream business and with a very active market for oil reserves. At the same time we have also seen an important increase in United States oil imports, which many perceive, on the basis of past experience, as an early indicator of future higher prices. I am sure this demand/supply aspect of the oil industry will play an important part in our discussions.

We should also pay attention to an important new factor of change deriving from the accelerated events now taking place in Eastern Eu- rope. These repercussions will be felt not only in politics and econo- mics but also in the energy and oil sectors at he world level.

Apart from the traditional sessions about oil markets, we have also included in this seminar agenda a complete session dedicated to the evolution of the energy sector at the EEC level, an area in which we expect great changes as we approach the 1992 deadline for the inauguration of the European single market.

I would like to end by wishing you a pleasant stay in Toledo and ex- pressing the hope that your discussions will contribute to our greater understanding of the oil industry. Thank you for your attendance at this seminar. 3

«THE FUTURE OF SPAIN´S OIL SECTOR»

VÍCTOR PÉREZ PITA

Ladies and gentlemen, good morning. We are here in Toledo, far from our daily business, to share information and opinions on the oil market and its future. Let me introduce some basic thoughts before you start your discussions.

The Spanish Administration thinks that in the future evolution of the oil market, prices will be characterized by greater stability than in past years. We believe this will be the case because the current price is at an equilibrium level between buyers and sellers. Higher prices, in addition to producing imbalances in the most developed economies, would discourage consumption, something that has occurred in the past. On the other hand, substantially lower prices would generate undesirable imbalances in international trade and make it impossible for other energy sources to be substituted for oil —an objective, I should note, of most western economies, including Spain.

Another basic point I would like to raise is that oil market deregula- tion, especially the implementation of the deregulated European do- mestic energy market we are now living through, is a development 4 Opening Session

of the utmost importance. In my opinion this will not lead to any dra- matic changes in the EEC oil market, as that market already has been functioning at an acceptable level of competition. In Spain, however, given the transition from absolute monopoly we are now under- going, acceptance of the Community rules has already caused far-re- aching changes in the sector, and will continue to do so until the sys- tem complies with all those rules by early 1992.

As you know, this process will permit authorized oil operators to compete on the one hand with the refineries of the CAMPSA system in those products remaining in the so-called «national production distribution monopoly», and on the other hand to compete directly with refineries in those already-demonopolized products. This pro- cess of re-adaptation is being undertaken gradually in coordination with the EEC. At this moment we are awaiting one of the last Royal Decrees liberalizing bulk LPG selling directly to the final consumer. The overall liberalization of this retail trade, covering all types of con- sumer fuel oil, heating gas, and bottled or packed LPG, should be completed in the first months of next year.

With respect to prices, we intend that there will be a liberalization of the automotive fuel price system throughout the first half of next year. This process will be extended to other products during the re- mainder of the year. In the first quarter of this year we have already liberalized the price of fuel oil, our first experience with the process. It was accomplished with a maximum-price type of system, using a formula to establish a maximum price for each month. We intend to do something similar for the automotive fuel products. Finally, it is our intention to end with a completely free price system that we will institute when we believe the market is in a position to accept i with minimum disruption.

After abandoning fixed pricing powers in this field, the next step will be to decide on taxation. After the income tax on oil is removed in accordance with the situation in the other countries of the EEC, there will remain only a special tax, or «excise», and the corresponding va- lue added tax (VAT). «The future of Spain’s Oil Sector» 5

Another point with which we are concerned is tax harmonization with the EEC. The situation here is encouraging. If successful, the process will result in an increase in Spanish taxation of oil products. This increase will enhance its dual role as a highly efficient tax collec- tion tool and a factor in curtailing oil product consumption. Such cur- tailment is especially needed in countries such as Spain which have a high level of dependence on imported oil.

On the demand side, the higher fuel oil consumption in thermal po- wer plants forecast for the coming years in the Spanish system will offset in part the large shift to light that has been taking place since 1973. As a result of EEC environmental requirements, we believe there will be an increase in the demand for products with lower pol- lutant content. The reduction in the lead content of gasoline from 0.4 to 0.15 grams per litre that will be enforced after June 1991 will be an important factor in this change. We are beginning a process of reducing the tax on unleaded gasoline, to be applied next year, so as to avoid penalizing unleaded gasoline consumers as well as to shift consumers to unleaded gasoline consumption. This is in line with ac- tions taken by many EEC countries. All of these environmentally-in- duced changes have had a considerable role in determining the changes in the Spanish oil sector, which started its own adjustment years ago in the move to greater competitiveness.

As for the structure of the Spanish oil industry, it is generally uninte- grated beyond the refining and marketing stages. Spanish refiners began to meet the shift in demand toward light oil products by ad- ding reforming units to their refineries. Retirement of obsolescent ca- pacity has been less than the average in the EEC countries. As a re- sult, Spain is not experiencing the shortage in refining capacity that is true of the EEC as a whole. This could substantially change if the Common Market, as seems likely, concludes a free trade agreement with the Gulf Cooperation Council countries.

I would like also to underscore the effort Mr. Solana has alluded to, namely, the public sector´s integration of its activities —first with the Instituto Nacional de Hidrocarburos (National Hydrocarbon Institute) 6 Opening Session

and then the effort in launching REPSOL and increasing its activities in oil industry. Some Spanish companies have insured a part of their long-term supply by means of contracts or have reinforced their commercial activity by setting up joint ventures with multinational companies. CAMPSA itself has undertaken an unprecedented invest- ment effort in the marketing area, in the development of an integra- ted CAMPSA refining system, and in the logistical area as well. In the latter instance, CAMPSA´s cooperation with authorized groups de- monstrates pragmatism and economic rationality.

As my final point, I note that the policy objective of the government is to achieve a free market for oil products in 1992, permitting a competitive supply of such products. We believe the benchmarks in the attainment of this objective have been firmly established. The Spanish energy sector has faced the challenge of achieving the ne- cessary competitiveness as scheduled and has met that challenge. The sector is in far better condition to compete than it was several years ago. Nevertheless, it is essential to continue improvements re- garding optimum size and vertical integration as well as control of a significant part of crude oil processing. We believe it is also necessary to continue to invest in refining facilities so that the supply of pro- ducts with lower environmental impact will meet the increasing de- mand. 7

SESSION I

«OIL MARKET OUTLOOK»

INTRODUCTORY REMARKS

BIJAN MOSSAVAR-RAHMANI

Good morning. The first session of our two-day meeting focuses on the outlook for world oil markets. The three presentations this mor- ning will cover supply, demand, and price issues, and each of the speakers will provide a prognosis of the likely direction of the market, both short and longer term.

But before turning to the speakers, I should like to offer some intro- ductory comments. As we approach the decade of the 1990s, the oil market appears substantially stabilized. That view is shared by a broad spectrum covering industry, governments and international or- ganizations that follow the market, and is consistent with the Span- ish government´s outlook as described by Víctor Pérez Pita.

Although recent demand growth, at two or so percent, is stronger than had been anticipated, it still does not reflect a dramatic surge in global consumption. The conventional wisdom foresees a continua- tion of current trends on the demand side, with somewhat tempered growth in the industrial countries offset by healthier increases in the developing countries. But no surprises. 8 Session I

The supply side, too, seems to be stable: no sudden increase in out- put but no shortfalls either. OPEC production is running higher than that organization´s self-imposed ceiling, but neither the massive sup- ply surge that some had believed would occur after the conclusion of the Iran-Iraq war nor a general breakdown in OPEC discipline has materialized. Over time, supply availability is expected to keep up with demand. Stepped-up investments in exploration lead times in such areas are long —often five or more years.

But there seems to be enough spare capacity in the OPEC system, certainly in the Middle East, to tide us over until this new production comes on line.

Prices seem to be holding. There is some volatility, of course, in the 5 percent to 10 percent range above or below OPEC´s target of $18 a barrel, but such fluctuations are normal and manageable. All in all, the outlook for prices, like those for demand and for supply, is one of the stability and predictability, indeed, the conventional thinking is that prices will remain essentially constant in real terms over the course of the coming decade.

There are developments affecting the structure and organization of the market that may prove important as we look ahead, and these developments are going largely unnoticed and do not figure in the calculus. Still, these developments, too, by and large appear to bode well for the future. There is ongoing geographic integration of the market, with more OPEC countries going further downstream, the latest move being the announcement just a few days ago that Venezuela is acquiring the remaining 50 percent of CITCO. Other moves by OPEC countries into refining, marketing, and distribution in the consuming countries, coupled with the growing levels of in- vestments upstream by the international oil companies in foreing ex- ploration and production, would suggest that the market is coming closer together and becoming more geographically integrated.

Indeed, on the upstream side, there is a little talked-about but very significant move towards a «denationalization» of oil exploration and Introductory Remarks 9

production in a few OPEC and many non-OPEC countries, of which my piece of the industry is beneficiary. The nationalization, expropria- tion, take-over and otherwise do-it-yourself trends of the 1970s by producing countries now seem to have been reversed, and we are seeing a growing number of countries make a concerted effort to open their upstream sectors to international companies, to new play- ers as well as to the traditional majors. Fiscal and operating terms and conditiones are improving, sometimes dramatically, in many coun- tries. Significantly, in some countries, notably in Argentina, the gov- erment has moved to release exploration acreage that had been set aside for the national oil company. In a few instances there even is a sell off of producing fields. All this is in recognition of the important technological and financial wherewithal of international companies and the failure of bureaucratically-burdened and capital-restricted state companies to make sufficient headway on their own. Admit- tedly, the new relationships are more balanced than the old, and per- haps a more durable, lasting equilibrium in setting in.

The international oil industry itself, meanwhile, is undergoing some restructuring, although that seems to be more in the form of assets sales and assets swaps, and there is little in this reshuffling that would appear to threaten the stability of the market or the outlook for the 1990s.

Finally, newer financial instruments have begun to play an important part in our overall business. The futures market and the various fi- nancial techniques for hedging and speculation that we will hear about later this afternoon have not proved to be the destabilizing force that some had predicted in the 1970s. So here, too, very few surprises seem to be lurking that might threaten the conventional view of an essentially calm and predictable market as we look to 1990 and beyond.

The only red flag on the horizon is the dramatic increase in the United States´ dependence on oil imports. US imports have been ris- ing steadily both as a consequence of growing consumption as well as fairly significant reduction in domestic oil production. What this 10 Session I

increased dependence will trigger eventually in terms of a US policy response is still very unclear. Incidentally, the US government is now going through a process of developing a consensus national energy policy; it is doubtful that any dramatic policy prescriptions will result from this exercise.

The purpose of our first session is both to review —but also to chal- lenge— the conventional world oil market view. We will start with Ambassador John Ferriter, who will present the International Energy Agency´s world oil outlook. That view, I assume, will reflect accu- rately the mainstream thinking in industry and governments as well as in his own organization.

But before hearing from John, and to provoke and stimulate the fol- low-up discussion, I would like to question the robustness of the con- ventional view. If we think back 10 years —if this meeting had been held in 1979— we would have had a very different view of the 1980s than what in fact came to pass. The fall of 1979 was a period of turmoil and change in the global political and economic scene, a turmoil that was translating into great volatility in the oil market. The then conventional view was one of unabated demand growth, con- tinued restrictions on supply availability, political instability in the Middle East, and with these, rising oil prices —a far cry from what we actually witnessed in the 1980s. If we were so wrong in 1979 look- ing at the 1980s, why should we think we are likely to be correct in our assessment in 1989 as we peer into the next decade? Are things likely to be so different this time? Are we in a position to make bet- ter predictions? Do we have improved data or analytical tools? Have some fundamental changes occurred in the market to render it more stable, more predictable?

The oil market traditionally has been a cyclical market. Now the pro- ponents of conventional wisdom argue that fundamental changes have occurred that are shifting us away from cyclicality. In this view, the historical cycles will not be repeated. Perhaps we can all agree that peaks and troughs of new cycles will not be as sharp and the timing will be different. Still, I, for one, am a believer in repetition in Introductory Remarks 11

history —in cyclicality, if you will. Memories in the oil business are very short; hopefully we can extend those memories as we reflect on the themes of our meeting over the next two days. It is particularly appropriate, sitting as we are facing the old and beautiful city of Toledo and pondering the forces that are at work in our business, that we do take a longer-term perspective.

Our second speaker, Professor William Hogan, will talk about his work at Harvard University on world oil demand as well as on spe- cific research that Harvard has been conducting in collaboration with REPSOL and a group of Spanish academics on the energy scene in Spain. In his description of his work, he will, I hope, challenge the conventional wisdom about demand, as he has done before. Those of you who were here last year, and others who are familiar with Bill´s work, remember that he has challenged the view that the out- look for demand is one of essentially flat or nominal growth. I think we will hear some provocative thoughts from Bill on the market out- look in general and on the demand picture in particular.

Surprises might indeed occur on the demand side. Is it likely that we will see surprises on the supply side —interrumptions in supply, or conversely, availability of major new sources of hydrocarbon produc- tion? We have heard recently about substantial Soviet discoveries of natural gas. Could these supply sources have an impact on the mar- ket? One area of uncertainty and surprise that Guzmán Solana point- ed to in his welcoming address is the dramatic upheaval and change underway in Eastern Europe. How might some of the changes, and the opening up of these economies, affect the patterns of oil trade, oil consumption, oil production? Perhaps these political and eco- nomic forces may cause surprise that we cannot anticipate or take into account as we gaze into our crystal balls.

Could the green movement and the growing concerns about envi- ronmental quality trigger a surprise on the demand side —or the sup- ply side— and therefore on the outlook for the world oil market? Are we better equipped as companies, as governments, as international organizations, to deal with such surprises? Or are we likely to have 12 Session I

been reduced to complacency and are therefore unprepared for sud- den changes when and as they occur?

We will hear finally from Alan Binder on one major international oil company´s outlook of the future. He will present us with the Shell view, which I assume will cover a range of possible outcomes or sce- narios, perhaps obfuscating the issues but underscoring the uncer- tainties.

With those brief introductory thoughts, I would like to proceed to the first speaker.

BIJAN MOSSAVAR-RAHMANI

Bijan Mossavar-Rahmani is President, Apache International, Inc. in Denver, Colorado.

Mr. Mossavar-Rahmani holds degrees from Princeton and Harvard Univer- sities. He was a Visiting Research Fellow at Rockefeller Foundation between 1978 and 1980. Prior to joining Apache International, Mr. Mossavar-Rah- mani was Assistant Director for International Energy Studies, Energy and En- vironmental Policy Center, Harvard University.

A former delegate to OPEC Ministerial Conferences, Mr. Mossavar-Rahmani has consulted, written, and lectured widely on international oil and gas mar- kets and on the energy policies, economics, and politics of OPEC countries. His books include OPEC AND THE WORLD OIL OUTLOOK, ENERGY POLICY IN IRAN, WORLD NATURAL GAS OUTLOOK, and THE OPEC NATURAL GAS DILEMMA. 13

«WORLD OIL MARKET OUTLOOK FOR THE 1990S»

JOHN PIERCE FERRITER

INTRODUCTION

Good morning. It is a pleasure to address this distinguished group, and particularly to be associated with my alma mater, Harvard Uni- versity.

I have been asked to outline the views of the International Energy Association (IEA) on the world oil market outlook for the next ten to fifteen years. These parameters fit nicely, since in the IEA we have re- cently completed our projections of the World Energy Outlook for 2005. My comments will indicate our belief that if you survived the eighties, the nineties might again show that the oil and natural gas business is not such a bad one in which to be.

Let´s look first at the short-term outlook since this will set the stage for our long-term assessment.

SHORT TERM

Oil consumption growth is now continuing along a trend line of 1.5 to 2 percent annually in the OECD area, and between 3.5 and 4 14 Session I

percent in the non OECD world. This trend is supported by some- times fluctuating and geographically uneven —but nevertheless per- severing— economic growth worldwide. Additonally, an unpre- dictable but persistent series of «other factors», such as industrial accidents, have also helped tighten the market and keep the margin of demand moving upwards just ahead of supply rates, which also continue to rise. This market dynamic could change in coming months, if economic growth pauses and the upward movement of oil demand thus slows somewhat. Under these conditions, what might we expect of those producing the marginal barrel of oil?

Many see a price softening, soon. Other observers —just as knowl- edgeable— see the precedent of trend-line demand growth and «other factors» as likely to continue delaying any significant market weakness. Thus, without the slightest fear of contradiction, we can report that between now and the first quarter of 1990, oil markets will either weaken significantly —or they will not. This equivocal con- clusion is, however, not without some merit. It forces us to consider what the producers of the marginal barrel might do in each of the two instances.

First, if prices soften really significantly, the OPEC ministerial meeting scheduled for later this month is likely to be pre-occupied more with the disciplining of quotas than it is with their enlargement and reap- portionment. Those upcoming sessions would then be similar to other yearend meetings of the Organization we have witnessed in the recent past. The goal would be simply to generate de facto output restraint, with the aim of having just enough physical and psychological impact on the market to permit those of us who are consumers to nudge the margin of demand back up to the point of relative equilibrium we have been experiencing throughout most of this year.

In the second instance, prices do not weaken significantly. In this case OPEC behavior could again become quite interesting to consumers as various proposals for quota redistribution are debated. The next OPEC meeting could even be remarkable if a re-apportioned quota system «World Oil Market Outlook for the 1990s» 15

were actually to be accepted. Admittedly, any such reallocation might be small, and at the outset only geared to legitimize the activities of second-echelon overproducers like Kuwait and the UAE, and to ac- knowledge that some other memberws, like Algeria and Libya, are simply no longer able to increase their production. Such a precedent- setting move, however, could prepare the way for and even more pro- found series of reallocations when Iraq and Iran next year find them- selves with significantly greater oil export capacity in place. Saudi Arabia would then be confronted with the need to defend its own five million barrel per day (mbd) quota, which is fully two million greater than each of the former belligerents in the Gulf War.

The ominous lesson for oil consumers in all of this, however, is that in contemplating fundamental market share re-apportionment, OPEC is simultaneously contemplating the likelihood of a return to a seller´s market for oil. However, a return to a seller´s market will probably not depend so much upon their actions. It is rather the actions of consumers worldwide —not just within the OECD— that will determine the speed and the degree to which the major produc- ers of the marginal barrel of the 1990s are able to accommodate each others´ market share aspirations. The less they are called upon to compete, the closer we will be to a re-establisment of a seller´s market.

Thus, while consumers must certainly welcome this apparent will- ingness by OPEC producers to adjust and increase their output to meet the future requirements of the market. It is also important for them to appreciate that the market will not necessarily have the type of buyer/seller balance that has prevailed over the past half- decade.

LONG TERM

How does the IEA view the long-term, the next fifteen years? The fol- lowing analysis is based upon the IEA´s World Energy Outlook to 2005. This is not a forecast, but a projection based upon certain assuptions 16 Session I

regarding crude oil prices and economic activity. We examined mul- tiple scenarios, and the one I reference today is a reasonable assess- ment of the likely evolution of energy markets. (I recognize that in 1979 people were forecasting something that doesn´t compute in 1989. Now, in 1989, what we are saying about 1999, 2000, 2005, etc., may look in those years like some Brave New World that never came to pass. Nevertheless, we have to start from somewhere, and that is what we are giving you today.) This scenario assumes that crude oil prices (in constant 1987 United States dollars) rise to $18 by 1990, and then rise gradually to about $30 by 2000 and re- main at that level thereafter. Economic activity is assumed to expand at an average rate of about 2.7 percent per annum for the OECD, the same rate for centrally planned economies (CPEs), and 3.8 per- cent for the developing countries over the period to 2005. (I recog- nize that the term CPE is becoming increasingly outmoded. Perhaps we should just say «the other guys»).

We assume that crude oil prices, in real terms, begin to rise as excess production capacity outside the Gulf producing region is reduced. As this occurs, supply and price will depend on the extent to which Mid- dle East production and ultimately capacity are increased. The $30 dollar per barrel price is about equivalent to the price level that pre- vailed, in real terms, in the mid-1970s.

Demand In this central scenario, world oil demand would be expected to rise at an average rate of about 1.6 percent per annum over the period, with the rate of growth being higher over the medium term and lower over the latter part of the period. Oil demand is expected to rise most in the developing countries (2.9 percent per annum, largely because of rapid population growth, urbanization, greater transport needs, and accelerating industrialization, particularly of heavy, rela- tively energy-intensive industries), followed by the CPEs (2.0 percent per annum, although who knows what is going to happen there), and least in the OECD countries (0.8 percent per annum). As a result, the non-OECD countries´ share of world oil consumption could rise from «World Oil Market Outlook for the 1990s» 17

45 percent in 1988 to about 52 percent in 2005; concommitently, OECD countries´ share could fall from 55 percent to 48 percent.

The rise in OECD oil demand is expected to come mainly from the transport sector (road and air transport) and the petrochemical indus- try. Oil transport demand is expected to grow at an average rate of about 2 percent per annum until 1995 and at a rate of about 1.3 per- cent thereafter to 2005. The deceleration over time in the rate of growth of oil demand for transport purposes is attributable to the higher oil prices assumed for the 1990s, the projected slowdown in the rate of growth of population, and saturation effects. Petrochemi- cal demand is expected to increase at an average rate of about 1.3 percent per annum over the projection period. Demand for middle distillates (other than transport) is expected to stagnate of perhaps even sligthly decline, while heavy fuel product demand is expected to decline at an average rate of about 3 percent per annum. The whiten- ing of the oil barrel is therefore expected to continue over the projec- tion period.

Oil intensity (i. e., oil use per unit of real GDP) is expected to con- tinue to decline in OECD countries, though at a somewhat slower rate than that which followed the 1973 and 1979 oil price shocks. For this scenario, overall OECD oil intensity is expected to decline at an average rate of about 2 percent per annum, as a result of im- proving overall energy efficiency and continued substitution away from oil to other energy forms. The rate of decline in oil intensity is expected to be slower outside the OECD.

In turbulent Eastern Europe, oil intensity is expected to decline at a rate of 0.7 percent per annum. Oil intensity has declined there since 1980 as a result of the decline in overall energy intensity and also from the high penetration rate of natural gas in overall energy con- sumption. We anticipate that the rate of growth of natural gas con- sumption would decelerate because of leveling of the very substan- cial investments in Soviet natural gas production and distribution. This is turn will reduce the rate of substitution away from oil in the Soviet Union and Eastern Europe. 18 Session I

Oil intensity in developing countries is projected to decline at a rate of 0.9 percent per annum despite an anticipated increase in overall energy intensity. The projected decline in oil intensity is predicated in part on continued strong inroads by natural gas, and to a lesser extent coal, in meeting incremental total energy re- quirements. Overall energy intensity is expected to remain high because of increased urbanization, greater transport needs, accel- erating industrial developments and economic pressures which, along with limited financial resources, tend to reduce the flexibility of developing countries to take maximum advantage of improve- ments in energy production, distribution, and consumption tech- nologies.

This scenario is based on a continuation of current government en- ergy policies and a continuation of current trends in environmental protection. In the absence of unforeseen events, continuation of cur- rent environmental projection trends would not be expected to have a major impact on energy availability or on fuel mix. This is because we assume continued use of addon an clean technologies as the main mechanisms for pollution control. These tend to affect energy demand and fuel mix less than environmental policies or technologi- cal developments targeted to achieve large energy efficiency im- provements and fuel substitution.

Let me make an aside at this point. You have all followed closely what is going on in the global climate debate. At the recent meet- ings in the Netherlands, there was agreement on the need to stabi- lize the level of emissions affecting the heat balance, but the spe- cific level and the date were both left undecided. There is a significant ground swell of public opinion towards some kind of global climate convention. This may be where the 1989 projections could look silly in 1999 because governments worldwide would have made a massive effort at reducing emissions of «greenhouse

gases» —particularly CO2— and therefore would have undertaken major efforts to reduce fossil fuel consumption. We are not there yet, but it is certainly one of the big unknowns in anyone´s projec- tions. «World Oil Market Outlook for the 1990s» 19

To sum up on demand, oil will remain the principal component of world primary energy requirements, but, while the volume of its use will increase, its percentage share of total energy consumption will decline. Oil use will be concentrated more and more in transport fu- els in the OECD, but in energy-intensive industrialization as well in developing areas. Heavy fuel oil use in electricity and the industrial sector will continue to decline relative to other energy sources. More specifically, and assuming gradually rising prices through the coming decade, we project oil´s share of the total world energy mar- ket to drop from its currents 40 percent to about 35 percent. Its vol- ume usage, however, should rise from somewhat over 3 billion met- ric tons annually now to about 4 billion around the turn of the century.

Supply Simultaneous with the rise in crude oil prices in real terms, excess production and/or export capacity outside of the Persian Gulf region seems destined to decline. The US «lower 48», the Soviet Union, the North Sea, China, Mexico —all these areas demonstrate a pattern of declining prospects during the 1990s. As this occurs, supply and price will depend more upon the extent to which Middle East production, and ultimately capacity, is increased. I believe that significant increas- es will take place, and this brings us to a second fundamental princi- ple which should influence both short-and long-term views of the oil scene. It is that «OPEC sells to the market» and will continue to do so. During the 1990s, oil will continue to be produced and traded in a still more commercially sophisticated «high tech» manner than was the case in the 1970s and early 1980s. This means not only that elec- tronic trading will assist the day-to-day operations of the market, but that production and capacity expansion will go forward at a rate which will permit real price increases to take place.

We estimate world excess production capacity for crude oil to have been between six and eight million barrels per day before the recent production spurt. Today it may be between four and six million. Outside of Venezuela, almost all of this is in the Persian Gulf, where 20 Session I

market share perceptions have sharpened as the region faces recon- struction following the Iran-Iraq War. I have already commented on the prospects for OPEC quota reallocation and potential shifts in the market fulcrum between buyer and seller which relate thereto. It is that very atmosphere that will stimulate investment ahead of the curve of growing demand in order to assure the maintenance of market share —possibly a re-apportioned one. In sum, we think there will be plenty of crude oil available to meet the oil demand of the 1990s. But this likelihood, in itself, in no way resolves the consumer´s problems, even though he is resigning himself to the fact that he is going to be paying somewhat more for energy because of his own appetite for it.

What are consumer countries´ other problems? Rapidly rising envi- ronmental concerns could quite soon constrain use certain types of oil and other energy sources in the OECD. This issue could well be the topic of a separate speech. During the 1990s, the expected lack of improvements in energy intensity in the non-OECD world could further complicate these environmental and supply factors. Urban- ization and industrialization, the most obvious trappings of economic development, will inevitably have an impact on the environment.

Just how this evolving demand problem will share itself between the planet´s major communities of nations —West, East, and South— is of concern. For now, we must admit we simply do not know. We are certainly studying it. One initial, disquieting indication is that the exportable surpluses of all energy forms from the world´s major devel- oping regions outside the Middle East are declining as their own economies and energy consumption grow. Included here are Africa, Latin America, East Asia, and the CPEs.

The fact that the share of OECD countries in world energy and oil consumption will probably pass from somewhat over 50 % to some- what under 50 percent during the 1990s is fundamental to under- standing the evolution of energy markets in the coming years.

Oil production outside the Middle East is expected to expand grad- ually over time —about 5 mbd between now and 2005, but with a «World Oil Market Outlook for the 1990s» 21

regional shift away from the OECD towards non-Middle East developing countries. These, as noted, are likely to experience ab- solute declines in the energy surpluses they have available for export. Thus, with increasing world oil demand and only «modest» increases in non-Middle East supplies —more and more of which will be kept at home— world dependence on supplies from the Gulf will increase, perhaps to 34-35 percent of the world total by the end of the century.

Other Factors in the World Oil Balance OPEC The following comments represent my personal views. The 1990s will probably see a more pragmatic OPEC, particularly as the call on its oil moves towards 28 mbd as we project in our central sce- nario. The economics of OPEC, but no its politics, should become progressively more simple as countries at or near peak capacity are forced into the position of «camp followers» (rather than retaining their «spanner in the works» status). Saudi Arabia, Iran, Iraq, Kuwait, UAE, and Venezuela —the high reserve countries— will be calling the shots. There will be the inevitable difference of opinion; how- ever, they will be dividing a progressively larger pie which should make matters easier for them.

We should expect OPEC to play to the market. There is no doubt that painful lessons have been learnt on both sides of the OPEC fence over the last sixteen years. The OPEC «core» countries know that their key interest is to stay in business over the long term, and that while «jacked up» prices offer higher revenues in the short run, it will not be long before they generate new competition and lower prices, and a general revenue squeeze.

Our analysis based on a stable OPEC world where there are no ma- jor disruptions that impinge upon the oil market in the way that it was affected by events in the 1970s. There will inevitably be minor hiccups, but as the Exxon Valdez spill demonstrated, these are to come from a wider range of sources than political differences and «force majeure» on the part of the oil producers. 22 Session I

It would be improper and futile to speculate on the likelihood of any future disruption to oil supplies. However, in the present climate and even if we move towards a seller´s market, it appears that they are more likely to be of a short-term nature. From the IEA´s perspective, it is most important to recognize the possibility that supply disrup- tions might occur at some indeterminate point in the future. We must be ready to face them head on. This is why we at the IEA are constantly seeking to improve our emergency preparednes mecha- nisms to ensure that the impact of any future disruption is kept as in- significant as possible.

Other Fuels Rising world oil demand will remain the key determi- nant of the global energy balance in the 1990s. It will certainly have effects upon others forms of primary energy which will continue to «follow» oil. Natural gas should nearly double worldwide during the coming decade, most pronouncedly in the developing countries where its use could triple. However, no true world market for nat- ural gas is yet foreseen. Coal will continue average rates of growth in the OECD, but with power generation becoming the predomi- nant factor as other uses stagnate or decline. The centrally planned economies´ consumption should be flat, but developing countries´ use of coal will probably double during the coming decade. This would actually be somewhat less than during the past decade. Lower oil prices would keep heavy fuel oil in competition longer with both coal and natural gas. OECD use of hydropower will not be able to develop as fast as the growth in electricity demand. Sim- ilar hydro restrictions prevail in the centrally planned economies, but they do not prevail in developing countries, where considerable room for growth exists.

Finally, nuclear power. It no longer enjoys undisputed cost advan- tages over alternative sources of electricity production. The environ- mental debate will be critical in affecting its future in the OECD. The centrally planned economies will press ahead and register about half of future additons to world nuclear power facilities during the next decade. Nuclear power will play an insignificant role among the de- veloping countries in the 1990s. «World Oil Market Outlook for the 1990s» 23

CONCLUSIONS

I will close by summarizing the principal points of my speech:

— Several elements of the current short-term oil market outlook may be valid indicators of what the long term has in store.

— First, worldwide, not just OECD, consumption is likely to con- tinue firming prices, in spite of output increases by producers.

— Oil producers may, therefore, occasionally surpass margins of demand and soften prices. They may be doing this now as they position themseleves for their forthcoming meetings, but funda- mental consumption growth will soon re-establish the earlier firming trend.

— In this context, however, OPEC is practicing increasingly sophis- ticated market politics.

— Consumers can only welcome the apparent willingness by OPEC to adjust and increase its output to meet their future require- ments, but the coming twelve months could test continued via- bility of the buyer´s market which has prevailed for the past sev- eral years.

— Oil will remain the principal component of world primary energy requirements, but while the volume of its use will increase, its percentage share of total energy consumption will decline.

— Oil use will focus more and more upon transportation fuels, but along with natural gas, in energy-intensive industrialization as well as in developing areas. Oil´s use in electricity should de- cline.

— During the 1990s, developing countries will experience persis- tentely higher energy intensities that those among the OECD countries. 24 Session I

— While environmental concerns among OECD countries are already constraining use of certain types of energy, it is the eco- nomic growth and energy intensities of developing countries that may further complicate global consumption, environmental and supply problems, as their exportable energy surpluses dwin- dle —except in the Gulf.

— The share of OECD countries in energy consumption versus the rest of the world will pass from somewhat over to somewhat un- der 50 % sometime during the 1990s. This change in the global balance is fundamental to understanding the evolution of energy in the coming years.

JOHN PIERCE FERRITER

John Pierce Ferriter is Deputy Executive Director of the International Energy Agency (IEA) in Paris. Ambassador Ferriter came to the 21-nation organiza- tion after twenty-five years with the United States Foreing Service.

During his diplomatic career Ambassador Ferriter served in several African countries and in Paris with the US Mission to the Organization for Economic Cooperation and Development (OECD). He also held positions with the State Department´s Economic Bureau in Washington. In his most recent as- signment in the Department of State, Ferriter was Deputy Assistant Secretary of State for International Energy, Resources, and Food Policy.

Ambassador Ferriter was born in Boston, Massachusetts, in 1938. He earned academic degrees from Queens College of the City of New York (BA Econo- mics, 1960); Fordham University School of Law (LLB, 1963); and the Ken- nedy School of Government, Harvard University (MPA, 1973). 25

«OIL MARKETS AND OIL PRICES: A COMPARATIVE ANALYSIS»

WILLIAM W. HOGAN

I begin with an overview of our comparative analysis of oil markets and then move to a study of the Spanish oil market now underway with a group of Spanish scholars and REPSOL officials.

In the early 1980s our Harvard oil project addressed energy security problems and the changing structure of the world oil market. We were not preparing analyses of world oil markets and price projec- tions per se; many others were working on this problem, and our emphasis was elsewhere. But in the wake of fall in oil prices and other changes in world markets, many of the usual sources of im- portant studies about the oil markets were no longer available. Oil companies in particular stopped publishing their projections.

For purposes of our policy analysis, therefore, we had to prepare our own oil market analyses and projections. We developed an oil mar- ket model which we continue to update. Today I will summarize our conclusions from the most recent analyses. I will mention compar- isons not only with what has been happening in the market, but also relative to alternative energy modelling analyses. In particular, I will 26 Session I

draw on the studies of the Energy Modeling Forum of Stanford University which is conducting an extensive evaluation of oil market models.

I will summarize trends in world retail prices, but will spend most of my time discussing energy demand, oil demand, and the situation in Spain. We have been working over the last several months with a team from REPSOL, modeling energy and oil demand in Spain. I will report on the results and how they compare with our previous analyses of other countries.

Let me begin with the conclusions, and then fill in the supporting analysis. I remind you of Bijan Mossavar-Rahmani´s introduction and John Ferriter´s description of the evolution of ideas on the develop- ment of market trends. First there was the old conventional wisdom of the period from 1979 through the early 80s. On the one hand, growth in demand was seen as inevitable; on the other, the OPEC could constrain supply indefinitely. With these trends, a supplier´s market and higher prices would prevail throughout the 1980s and beyond. We know, of course, that these conditions did not result.

The upper right graph in Figure 1 shows the familiar story; the sharp increases in price during the late 1970s, followed by a gradual dec- line, and then a precipitous drop of the mid-1980s. The dotted line is the US Department of Energy´s (DOE´s) projection of last year, which is essentially the same for this year. You will note that this projection is consistent with the John Ferriter´s summary of the IEA oil price pro- jections. This dotted line projection is the new conventional wisdom.

The old conventional wisdom for oil reminds me of the initial Ameri- can debate about the future of nuclear power: it was going to be too cheap to meter. This turned out to be far from true, but the belief dominated early projections. Yet this idea survives in the characteri- zation of a new source of energy in the United States —conserva- tion, or the reduction in oil and total energy use. The current think- ing embedded in the forecasts is that this is too cheap to meter: conservation will happen no matter what; prices won´t affect the «Oil Markets and Oil Prices: A Comparative Analysis» 27

conservation trend. This phenomenon will lead to a decreased use of oil per dollar of GNP.

With low oil demand, the large non-OPEC sources of oil supply will continue to drown OPEC, and we will have soft prices through the 1990s. I should note that John Ferriter didn´t say precisely this; he said that non-OPEC production was going to decline, but that OPEC was going to provide whatever incremental production would be needed.

The graph on the lower right of Figure 1 summarizes this new con- ventional wisdom, at least for the demand side, which is an impor- tant part of the story. The graph shows the decline in the historical value of oil per dollar of GNP, on the order of a 2 percent per year decline, which the Department of Energy projects to continue well into the next century.

Our studies with the Harvard Oil Market Simulation Models (HOMS) focus on the analysis of this decline in oil use. Our conclusions are shown in the solid line continuation of the historical record on the graph. The downward trend in oil consumption per dollar of GNP is an integral part of the DOE projection. It is an essential requirement in order to produce the future of soft oil prices —but it is unsupport- ed by the data. Several years ago we looked at the DOE model, try- ing to reconstruct their analysis. We finally decided that the only way the low prices could be reproduced was by changing the parameters of the historically estimated demand model in order to produce this oil conservation trend projection and the attendant soft market pre- diction.

We raised this issue at a conference at which the DOE presented their model and their analysis. The DOE analysts agreed with our conclusions; they thought everyone knew that this demand was not based on an historical analysis of the data but represented an exoge- nous assumption, namely they assumed that oil consumption relative to the economy would decline through the end of the century, es- sentially independent of the effect of oil prices. 28 Session I

However, if we take the opposite approach and do not change the parameters from the historical estimates of the models, but rather fit the models to the historical data, we find two interesting results. One is that the models fit the data quite well. It is not difficult to explain the major components of the gyrations and variations that have taken place over the last two decades. Second, we don´t see this downward trend in oil use. To the contrary, what we get is the re- versal shown in the HOMS projection, where oil demand starts growing a bit more rapidly than GNP, in response to the lower prices. This is a theme I want to develop by outlining the evidence we have to support our findings.

Our findings differ from the new conventional wisdom because they are based on the application of basic economic principies. Estimating these simple economic models with the available data gives a very different projection.

But there is a second point that complicates the analysis. The second point stresses the fog of uncertainty: we don´t know what is going to happen. John Ferriter´s analysis assumes no major disruptions in the world market, especially in the Persian Gulf. Under the assumption, the projection he provides is quite plausible. But is that a relevant as- sumption, or is it likely that there will be disturbances and disrup- tions? I expect surprises; as the market gets tighter, the vulnerability to these disturbances and disruptions increases.

I don´t know exactly what will happen, but I see the market is tight- ening faster than is implied by the conventional wisdom; then an unrelated event could cause a great deal of instability. Hence, I see the oil market moving in cycles rather than in trends. Production is easy to change, but demand is not. Given a shock, there are lags in the system that result in cycles. Contrary to the view of a stable market through the 1990s and gradual price increases, for me the biggest surprise of all would be stability. And given where we are in the market today, I expect surprises to push in the direction of price increases. Of course, I could plot a scenario in which oil prices fall to $5 a barrel. This is physically possible: the oil is there and the «Oil Markets and Oil Prices: A Comparative Analysis» 29

marginal production costs could support it. But to me the biggest surprise would be to return here in Toledo in 1999 to review a gen- eral stability and gradual increase of prices over the intervening ten years.

RECENT TRENDS

I turn now to Figure 2, which provides a natural link to the previous discussion. First an apology. The figure is too complicated —it has too much information on it— but it addresses several important points. On the left axis is OPEC production, on the right axis is the price of oil. The dotted line is what you saw before, to remind you of what happened to those prices. The bar graph is OPEC production, and finally the heavy line, which is used by the Department of En- ergy and others as a reference point, is a measure of OPEC´S use of its capacity.

The argument has been made that when OPEC production gets to about 80 percent of capacity, there is a shift from a buyer´s to a sel- ler´s market, with associated price firmness. When OPEC production crosses from below to above on that heavy line, therefore, we should be moving from a world in which prices are tending to drop in real terms to one in which they are stabilizing and tending to rise. This is the essence of the model embedded in many world oil market analy- ses. And as you can see, in the 1980s production was below the line, and prices at that time were falling. Now OPEC production is start- ing to come back up to the production reference line.

The illustrative projection in the same Figure assumes that free mar- ket demand for oil grows at three percent per year (at the same rate, in round numbers, as the total economy). At the same line, non- OPEC production declines as a rate of 600,000 barrels a day (a bit more rapid than has actually been happening, but not bad as a first order approximation given low prices and the decline in exploration). Putting these two constructs together gives an incremental demand for OPEC oil of two million barrels per day per year. 30 Session I

If these trends unfold, how long does it take to go from the region of market softness and declining prices to the region of relative sta- bility and the beginning of rising prices? As we see in Figure 2, it doesn´t take very long; in fact, it takes only until about now. (The slide was prepared in 1988.) Recently we have seen a firmness of prices; what is going to happen in the next few years? The answer is clear. If oil demand keeps growing at the assumed rate and non- OPEC production continues to decline, the demand for OPEC oil will rise steadily. The pressure will grow for higher prices.

Something may happen. The demand growth may not occur, or non-OPEC production may be larger. Or OPEC may produce more, and prices may decline. Which of these things will happen we cannot be sure. It could be that this historically-based analysis is simply incorrect, that OPEC is willing to produce enormous amounts of oil —enormous even by their standards— and that we have an OPEC leadership that has learned a particular lesson and is willing to pro- duce enough oil to keep low prices. They could. They certainly have the oil. But the outcome would be inconsistente with past action; and I would be surprised.

Flipping to the other side of the coin, the central issue is the projection of oil demand. What is happening to oil demand as a result of conser- vation? Figure 3 shows the data for the United States, Japan, Spain, and the rest of the OECD countries. Here, with a shorter time horizon, is the same picture we saw before, but with the data now broken out for a few individual countries. For most countries there is a persistent declining trend in the use of oil per unit of GDP dating from the mid- 1970s. In Spain, by way of contrast, the summary measure continued to increase for several more years before starting to decline.

The question is wheter this recent oil use decrease has begun to abate or whether the previous trend will continue. In one view, the recent trend to renewed oil demand growth is merely a slight blip, and the decline rate of 2 percent per year will be resumed for an in- definite period. This view which is at the core of the new conven- tional wisdom; but it is becoming harder to support. By contrast, the «Oil Markets and Oil Prices: A Comparative Analysis» 31

reversal towards demand growth is consistent with what would be expected given the experience of low prices over the last few years. However, the change in oil demand per dollar of GDP is a bit less than would be predicted by our model and the historical analysis of the data. Earler we projected that there would be a demand turn- around about now, and there has been; but we also said that the turnaround would be faster and larger.

At the time we first made this projection, in the mid-80s, others dis- agreed strongly. For example, I summarized this analysis in Tokio a few years ago, and the renewed demand growth was viewed as im- possible. By now, an analysis of Japanese data shows this has in fact occurred, and quite rapidly —to their surprise, but not to ours.

We looked to see how oil prices might affect demand. One hypoth- esis is that when oil prices fell in recent years, customers didn´t see a drop in prices because countries raised taxes in order to maintain the delivered prices of gasoline and other petroleum products. By this hypothesis those continued high prices sustained some of the oil conservation so demand didn´t turn around as rapidly as our analysis of crude oil prices would predict. Tha explanation would be consis- tent with our model and would allow us to interpret the recent events as even stronger confirmation of the earlier projections.

To test this hypotheses, we assembled data from many countries, as shown in Figures 4 and 5. The test shows that customer retail prices fell about as would be predicted from crude oil price behavior. There may have been a few months´ lag, but the lag was not for a long pe- riod of time. So this popular conjecture is not correct. We have no complete explanation of what has been happening in the last few years, and we are continuing to pursue the question.

ENERGY DEMAND MODELS

For the remainder I will focus on the components of the dynamic en- ergy demand models. Any analysis of oil demand, particularly on the 32 Session I

scale of world market, faces great difficulties. For example, looking at oil demand alone ignores substitution incentives —e.g., to natural gas or to nuclear power— and thus produces an incomplete analysis. Another difficulty is in getting good price data across all countries. And doing a detailed analysis of individual countries also runs into difficulties; it is a complicated process to look at the different sectors and understand how they all relate.

In pursuing these difficulties, we have followed several paths. We have done (i) comparative long-run analyses across countries in the aggregate; (ii) aggregate analyses of the OECD and a few other countries to look at the dynamics; and (iii) detailed all-energy analys- es of individual countries in order to see how this compares with the simple «oil only» models. These detailed country analytic studies have been focused on Japan and the United States: the detailed analysis of aggregate energy demand allow for substitution across all products and provide a good explanation of historical movements consistent with the view that oil demand should be rising rapidly in the future. Over this past year, working with a team that includes Antonio Gomis, Antonio Martín, Marino Real, and Figueroa Sánchez, we have also been extending this analysis and applying the method- ology to the situation in Spain. Our team has a number of prelimi- nary results to give you today.

The basic pattern of the Spanish analysis includes a disaggregation of the economy into inputs of capital and labor, electric and non-elec- tric power, and transport oil. A second disaggregation divides the electric and non-electric uses into coal, gas, heavy oil and light oil. An econometric model explains the interactions between the different sectors with a consistent set of interfuel substitutions.

The Spanish economy experienced the familiar, rapid increases in oil consumption found in other in the OECD countries that lasted until about 1890, and then a decline in absolute terms, followed by the recent resumption of growth, as shown in Figure 6. The oil con- sumption measure used here is a typical econometric accounting. It is presented in trillion Btu´s, a conversion that makes it consistent with «Oil Markets and Oil Prices: A Comparative Analysis» 33

the data for other countries. More importantly, it also reflects in a single measure the shift towards light oils and other high valued fu- els. This shift contributes to the upturn in the plot of equivalent oil consumption in Figure 6.

The oil price calculation is similar to that applied to other coun- tries. The record, however, is different for Spain. The plot of de- livered oil prices shows the real price drop that occurred in the early post-Franco era, when there was an acceleration of inflation. My own conjecture is that administered energy prices did not fol- low inflation during this period, which meant a decline in the real price.

Figures 7 and 8 show the record of price volatility in the United States and Spain; this volatility is an important part of the story. There were declines in real transport and electricity prices until the 1970s, when both began to fluctuate, but in different ways. As can be seen, the component prices of the non-electric sector —light oil and heavy oil— moved quite rapidly, whereas natural gas prices, which were regulated, remained stable. Such large movements in prices and quantities can complicate economic analysis, but for sta- tistical analysis this volatility helps the comparison.

When the HOMS demand model was applied to these data, it pro- vided useful explanations of the historical movements. Figure 9 shows the results for the United States in the electric, non-electric and transport sectors. The dashed lines are the simple continuation of the pre-1973 trend; the broken lines show what would have hap- pened if consumption in each of the sectors had followed GNP by maintaining the consumption GNP ratio of 1973. The solid lines and circles show how well the model fits the historical data. Figure 10 shows that the same is true for Japan.

Returning to Spain, Figure 11 shows the quantity data on energy consumption for the same sector breakdown used in the price analy- sis shown in Figure 8. Consumption in the non-electric sector shows the familiar path of rapid growth, then a gradual decline, and then a 34 Session I

turnaround. Transport oils follow a roughly similar pattern, while the electric sector maintains steady growth.

The right hand chart on Figure 11 shows the individual components of energy consumption in the non-electric sector. This reveals an in- teresting story: great growth in the Spanish consumption of light and heavy oils, followed by a sharp turnaround for the latter while the former undergoes only a slight drop and then resumes growth. These data are for industrial consumption, they do not include the oil used for electricity generation.

Now look at the data in terms not of total consumption, but inten- sity of use. This is shown in Figure 12 for Spain and in Figure 13 for the United States. The comparisons are revealing. The intensity of energy use in the non-electric sector did not drop in Spain as it did in the United States, but rose instead. There was a small dip immedi- ately after 1980, but the rising trend then resumed. Intensity in the electric and transport sectors also behaved differently; relatively flat in the US, rising strongly in Spain.

Even more interesting is the change among the components within the Spanish non-electric sector, shown in the right hand chart on Figure 12. The dramatic reduction in intensity of coal use is striking. This complicates the analysis —in fact it required special treatment in the statistical estimation. I concluded that coal use must have noth- ing to do with economic motives; it was not a price matter. Perhaps this is an administrative decision to manage coal use. But once coal is separated from the rest of the data, the model fits for light oil, heavy oil and natural gas.

We estimated the demand model and obtained aggregate demand elasticities, the technical parameters which give the percentage change in consumption as a function of percentage change in price. Elasticity is an important tool in econometric modeling. To give an example, if you have an own-price elasticity of 0.5, then if there is a 10 percent increase in price you get a 5 percent reduction in de- mand. Figure 14 compares our findings for Spain with those for the «Oil Markets and Oil Prices: A Comparative Analysis» 35

United States and Japan, where we have done the comparable elas- ticity analysis. The Spanish results are within the range of uncer- tainty. One important conclusion is that the elasticities are much higher than is usually recognized. These are long-run elasticities, where we try to capture both the aggregate demand changes and interfuel substitution, and where a lot of movement is possible.

I am happy to say that my colleagues at REPSOL are pleased with the results of this analysis: the results are economically sensible and consistent with the analyses for different countries, even though the Spanish experience has been quite different. Although the Spanish economy has evolved differently and has different price profiles, this same structural model fits the history in the US, Japan, and Spain. In terms of the aggregate Spanish data, the demand model explains the complicated trends. As Figure 15 shows, the actual consumption —the line of dots— is quite different from the pre-1973 trends. It is also quite different from what it would have been if energy intensity had stayed where it was in 1973. There are, to be sure, fluctuations; not quite the gyrations we have seen in some other countries, but still important changes. Again, as can be seen, the model results shown in the heavy line fit the historical data quite well.

The implication, of course, is that we have an explanation for Span- ish petroleum consumption, because once we have completed the analysis of the electric sector, the detailed model will provide a tool for projections in the oil market. It should be noted that model does not include a decline in oil intensity of 2 percent year relative to GNP, through the end of the century, independent of prices. With prices at current levels you would see an increase in Spanish oil intensity over time.

The latter is what I would expect to see in Spain —an increase in oil intensity, although not as rapidly as happened before 1980. In part, that pre-1980 experience reflected the elimination of coal from the industrial market, which can happen only once. The econometric model I summarized here provides the foundation for what must now be done, which is to make the projections for Spain. We have 36 Session I

yet to do the projection model, including the fuels for electricity, which involves additional work in assembling the data. But we have learned more about the world market by reflecting on what is hap- pening in Spain, and I hope that REPSOL has also learned something about the interaction of the economic forces in Spain in comparison with the other major energy markets.

CONCLUSION

Let me conclude by emphasizing again the point with which I began. The current conventional wisdom is based largely on the assumption that either oil intensity will remain steady in the world market even though prices are relatively low, or there will be substantial increases in OPEC production over the next several years with no significant increases in price. The first assumption may be true. One of the dif- ficulties and limitations of the statistical analysis of the past is that it is vulnerable to the assertion that the world has changed. If you say the future is going to be different from the past, then obviously, sta- tistical analysis provides little insight. However, we cannot see such a trend in the historical data. It is an assumption that is inconsistent with the past. And it is an assumption that is central to the conven- tional wisdom of low demand and estimated soft prices.

If this assumption is not true, we will see a stimulus to the growth of oil demand, the turnaround we expect from the HOMS model. Now the market is in the lull before that turnaround that will put great pressure on OPEC. Or it may be that OPEC has learned a lesson. It may be that its members´ memories are longer. It may be that they can manage the process. It may be that they will exercises self disci- pline by not raising prices in the face of a highly tempting opportu- nity to do so. It may be that there will be no sudden surprises or dis- ruptions in the wold oil market. But I reiterate —for me, this kind of stability would be the biggest surprise of all. «Oil Markets and Oil Prices: A Comparative Analysis» 37

Figure 1 Oil Markets and Energy Prices in the 1990s

Oil Price Old Conventional Wisdom 50 Inevitable Growth in Demand 40 OPEC Constrained Supply 30 Higher Prices Through the 1980s DOE 20

New Conventional Wisdom 10 Conservation Too Cheap to Meter NOPEC Drowning OPEC 0 75 85 95 05 Soft Prices Through the 1990s Year

Oil/GNP Economic Principles and the Fog of Uncertainty 16 Markets Respond to Incentives 14 Cycles More Than Trends 12 HOMS Stability Would be the Biggest Surprise 1

0.8 DOE 0.6 0.4 75 85 95 05 Year 38 Session I

Figure 2 If Oil Demand Follows GNP OPEC Demand will grow rapidly

HIPOTHETICAL OPEC OIL PRODUCTION

DOE Threshold Production Historical Oil Price

OPEC Production 40 40

20 20 Price 1987s per barrel OPEC Production MMBD OPEC Production OPEC - Free Market Demand - NonOPEC Production [+2 mmbd]+ [+1.4 (+3%)] - [-0.6 (-2.5%)]

0 0

1973 19761979 1982 1985 1988 1991 1994 1997 2000 YEAR

Note: Data for OPEC Oil demand DOE-EIA International Petroleum Statistics, 6/88. Production Threshold from DOE International Energy Outlook, 1985-1987. Hypothetical projection for illustration «Oil Markets and Oil Prices: A Comparative Analysis» 39

Figure 3 Has OECD Oil Demand Conservation Stopped?

Oil Consumption Comparison

10

8

Spain 6

US

OIL/GDP 4 Rest OLCD

2 Japan

0

1965 1970 1975 1980 1985 1990

Note: EEPC Demand Analysis data Year 40 Session I

Figure 4 Have productFigure prices 4 followedHave crude product oil costs?prices followed crude oil costs?

Retail Gasoline Prices

1.2

1

Japan 0.8

0.6 Spain

Rest OECD 0.4 Real Gasoline Prices (S/L)

0.2 US

US Crude 0

1965 1970 1975 1980 1985 1990 Year

Note: EEPC Demand Analysis data «Oil Markets and Oil Prices: A Comparative Analysis» 41

Figure 5 Relative product prices followed crude oil

Relative Gasoline Prices

2

1.6

1.2 Spain US

Japan

Price Index 0.8 Rest OECD

0.4 US Crude

0

1965 1970 1975 1980 1985 1990 Year Note: EEPC. Demand Analysis data 42 Session I

Figure 6 Sapin«s oil demand growth changed abruptly

Spain Oil Demand and Price

2.000 900

Oil Consumption

1.500

600

1.000 Oil Price

QUANTITY (TBTUS) 300

500 PRICE (1980 Ptas/MMBTU)

0 0

1960 1965 1970 1975 1980 1985 1990 Year

Note: EEPC-Repsol Demand Analysis for Spanish data «Oil Markets and Oil Prices: A Comparative Analysis» 43

Figure 7 Price volatility marked the energy decade

U.S. Aggregate U.S. NonElectric

22 10

20 9

18 Electric 8

16 7 14 Heavy Oil 6 Light Oil 12 5 10 Transport 4 8 PRICE ($ 1985/MMBTU) PRICE ($ 1985/MMBTU) 3 6 Natural Gas NonElectric 2 4 Other 2 1

0 0

1960 1968 1976 1984 1960 1968 1976 1984 Year Year

Note: EEPC Demand Analysis for US four sector, six product (45-6P) dynamic model. 44 Session I

Figure 8 Volatility marked Spain«s price history

Spain Aggregate Spain NonElectric

2.250 1.000

2.000 900

1.750 800 Electric 700 Light Oil 1.500 600 1.250 Transport 500 1.000 400 750 Coal 300 Heavy Oil PRICE ($ 1980/MMBTU) PRICE ($ 1980/MMBTU) 500 NonElectric 200

250 100 Natural Gas

0 0

1960 1970 1980 1990 1960 1970 1980 1990 Year Year

Note: EEPC Demand Analysis for US four sector, six product (45-6P) dynamic model. «Oil Markets and Oil Prices: A Comparative Analysis» 45

Figure 9 We can explain the Agregate U.S. Energy Data

Electric NonElectric Transport

16 60 30

14 50 25 12 40 20 10

8 30 15

6 20 QUANTITY (Quads) 10 QUANTITY (Quads) QUANTITY (Quads) 4 10 5 2

0 0 0

1960 1970 1980 1960 1970 1980 1960 1970 1980 Year Year Year Model Pre 73 Trend GNP Alone Actual

Note: EEPC Demand Analysis for Japan four sector, six product (4S-6P) dynamic model. 46 Session I

Figure 10 We can explain the Agregate Japan Energy Data

Electric NonElectric Transport

5 15 5

4 12 4

3 9 3

2 6 2 QUANTITY (Quads) QUANTITY (Quads) QUANTITY (Quads)

1 3 1

0 0 0

1960 1970 1980 1960 1970 1980 1960 1970 1980 Year Year Year Model Pre 73 Trend GNP Alone Actual

Note: EEPC Demand Analysis for Japan four sector, six product (4S-6P) dynamic model at 15% adjustment rate. «Oil Markets and Oil Prices: A Comparative Analysis» 47

Figure 11 Sapin«s Energy Demand Growth broke from trend

Aggregate NonElectric Components

1.400 600 Light Oil NonElectric 1.200 500

1.000 400 Coal 800 Transport Heavy Oil 300 600 QUANTITY (TBTUs) QUANTITY (TBTUs) Electric 200 400

100 200 Natural Gas

0 0

1960 1970 1980 1990 1960 1970 1980 1990 Year Year

Note: EEPC-Repsol Demand Analysis for Spanish four sector, six product (4S-6P) dynamic model. 48 Session I

Figure 12 Input-output ratios describe Spain«s energy demand adjustments

Aggregate NonElectric Components

9 9 NonElectric Coal 8 8

7 7

6 6

5 5 Light Oil Transport 4 4

3 3 Heavy Oil

Electric Btu Input per Btu Output 2 2 1.000 Btu per Unit 1980 Ptas GDP

1 1

0 0 Natural Gas

1960 1970 1980 1990 1960 1970 1980 1990 Year Year

Note: EEPC-Repsol Demand Analysis for Spanish four sector, six product (4S-6P) dynamic model. «Oil Markets and Oil Prices: A Comparative Analysis» 49

Figure 13 Input-output ratios describe US energy demand adjustments

Aggregate NonElectric components

14 0.6

Natural Gas 12 0.5

10 0.4

8 NonElectric 0.3 Light Oil 6

0.2 Other 4 Transport 1.000 Btu per $1975 GNP Btu Input per Btu Output Heavy Oil 0.1 2 Electric 0 0

1960 1968 1976 1984 1960 1968 1976 1984 Year Year

Note: EEPC Demand Analysis for US four sector, six product (4S-6P) dynamic model. 50 Session I

Figure 14 Comparing Aggregate Energy Demand Elasticities

Price Elasticities

2.25

2

1.75

1.5

1.25

1 Elasticity

0.75

0.5

0.25

0

Electric NonElectric Transport El-NonEl NonEl-El UNITED STATES SPAIN JAPAN

Note: Demand Analysis for four sector dynamic models, U.S. and Japan Data for 1960-1984, Spanish Data for 1960-1987, ML estimation. «Oil Markets and Oil Prices: A Comparative Analysis» 51

Figure 15 We can explain Spain’s Agregate Energy Data

Electric NonElectric Transport

1.000 3.200 3.200

800 2.400 2.400

600

1.600 1.600

400 QUANTITY (TBTUs) QUANTITY (TBTUs) QUANTITY (TBTUs) 800 800 200

0 0 0

1960 1970 1980 1960 1970 1980 1960 1970 1980 Year Year Year Model Pre 73 Trend GNP Alone Actual

Note: Demand Analysis for Spanish four sector dynamic model, Data for 1960-1987, ML estimation. 52 Session I

WILLIAM W. HOGAN

William W. Hogan is Thornton Bradshaw Professor of Public Policy and Management at the John F. Kennedy School of Government, Harvard Uni- versity, where he also serves as Chairman of the Public Policy Program and as Acting Director of the Energy and Environmental Policy Center.

Dr. Hogar is a Director of Putnam, Hayes and Bartlett, Inc. He received his undergraduate degree from the Air Force Academy and his Ph. D. from UCLA. Dr. Hogan has served on the faculty of Stanford University where he founded the Energy Modeling Forum. He is a Past President of the Interna- tional Association for Energy Economics (IAEE). He has held positions dealing with energy policy analysis in the Federal Energy Administration, including that of Deputy Assistant Administrator for Data and Analysis. He is involved in various research activities in the development and application of energy and environmental policy models. His consulting activities include strategic planning and risk analysis. His teaching interests focus on the theory and ap- plication of analytic methods for public policy programs. 53

«PROSPECTS FOR THE WORLD OIL INDUSTRY»

ALAN NAISMITH BINDER

I should like thank the organizers of the REPSOL-Harvard Seminar for the opportunity to discuss matters of common interest with you. The other speakers this morning have talked about volatility. This no- tion that the oil industry is in a state of flux is widely held and is far from new. It seems evident to me, however, that the industrial world —and certainly the oil industry— are entering a completely new phase. Before I attempt to validate this, I should like to give muy own industry a pat on the back for being so successful in adapting to the sudden and violent changes in the environment since the mid-1970s. Quite quickly major oil companies such as Shell, which were used to owning crude oil from the wellhead to the retail customer and using our own tankers and refineries, had to get used to the idea that most of our crude oil would have to be bought on the open market. Fur- thermore, to aggravate what could be called a process of disintegra- tion, Wall Street refiners and commodity brokers entered the crude oil and product trading game. This led to a situation which required considerable powers of adaptation. As we know, the oil industry adapted quickly, and its return on capital remained sufficiently at- tractive to retain the interest of sophisticated international investors, 54 Session I

many of whom are represented here. Have you been disappointed, ladies and gentlemen?

Figure 1 shows the record of price volatility in the world oil market during this century. Before 1905 there was little volatility, for those were the days when American trusts were effectively running the world´s oil business. Then the trust busters came along, and you can see the greater volatility culminating in the years of World War I, shown in the very sharp changes between 1915 and 1920. The even more pronounced volatility in the decade following the war caused great suffering in the oil industry. The extreme price lows caused by the Great Depression brought about the creation of the Texas Rail- road Commission which effectively restrained production and con- trolled prices. To my great surprise and joy, I understand it is still alive and well and is quite prepared to give OPEC its advice if it is asked (and maybe even if it isn´t asked).

World War II once again brought price volatility, but between 1950 and 1973 there was scarcely any change in prices. Why was this? During this time the seven major oil companies active in the Persian Gulf worked very closely with the local governments and controlled the production of oil. So, although there was tremendous competi- tion at the retail end, there really wasn´t much at the crude oil level. After nationalization, all of that changed completely. As I have said, we in the oil industry had to get used to this new situation promptly, which we did. What is the picture today? Non-OPEC countries pro- duce 26 to 27 million barrels per day (mbd), i.e., 54 percent of the requirements of the world outside communist area. (Figure 2.) Other agencies and authorities give different figures, but we include syn- thetic fuels, ethanol, shale oil, and oil from coal in our calculations.

We at Shell are forecasting a small increase in non-OPEC production over the years 1989 and 1990. This is a controversial matter even within Shell. The longer-term outlook for non-OPEC production is, of course, a bit of an unknown. In my view every nerve will be strained and every technological gimmick will be employed by the non-OPEC countries to get out all the oil from areas that are already known. «Prospects for the World Oil Industry» 55

Production from places like Alaska and the UK North Sea will decline, but to some extent this decline will be made up by technological ef- fort and by new discoveries and extensions to production in such countries as Syria, North Yemen, Gabon and so on.

In my opinion, 27 million barrels a day for non-OPEC production for the foreseeable future is «given». I know that others believe that the decline in the United States, in Alaska and certainly in the United Kingdom portion of the North Sea, is going to be greater, oil there being too expensive to produce, and that there will be a significant, even if gentle, decline beginning about the mid-1990s. We´ll wait and see. This leaves OPEC with the remaining market. If we remove from the calculations the domestic needs of countries like the USA and the UK, it is apparent that OPEC will continue to dominate the trading scene, since they account for significantly more than 60 per- cent of the internationally traded crude oil in the world outside the communist areas. OPEC thus can call the shots, provided OPEC speaks with one voice.

The large multi-national oil companies continue to dominate the downstream, in refinery capacity and product sales. (See Figure 3.) Despite all the efforts made by producing countries to expand their refining and marketing activities, OPEC still has only a small share of this market. The OPEC downstream participation is significant and still growing, but I think it will take a very long time before there will be sufficient reintegration, through their nationalized oil entities, to dominate the downstream in a way that would enable the stable days of the 1950s and 1960s to return. (I should emphasize that this is a personal view, and you will hear opinions to the contrary.) At this time, therefore, the producing countries need the oil majors and oth- er outlets, and the oil majors need the producing countries to satisfy their requeriments for crude oil. For example, according to my infor- mation Saudi Arabia produces currently about 5 to 6 mbd and has a secured downstream outlet of perhaps 20 percent of that with the Texaco deal and various barter arrangements. On the other hand, the Shell Group needs 5 to 6 million barrels per day on what we call a «secure» basis (i.e., oil that Shell companies own in Nigeria, the 56 Session I

North Sea and elsewhere) as well as what has to be purchased. Equity oil in Shell´s cases is about 1.5 million barrels per day, so we buy at least 3.5 million barrels per day. This dependence on purchased crude is not atypical of certain other major oil companies, although the Shell Group of companies probably «owns» a smaller percentage of its oil than its major competitors.

This state of affairs gives rise to a free market in the trading of crude oil and indeed favors the conclusion that this trade is likely to remain highly volatile (in the way that all commodities are) for many years to come. There is little or no possibility of OPEC countries securing enough downstream assets to reintegrate the oil industry, nor is there at the moment any possibility of the major oil companies or consuming countries securing upstream supplies to the extent neces- sary or sufficient to accomplish the same state of affairs.

This balance should be conducive to a relatively stable market for crude oil and its derivatives. However, as I mentioned at the begining of this address, there is some evidence that a step-change in interna- tional economic affairs has taken place. This change is due to two fundamental factors: the economic failure of the communist system and the over-stretched nature of the US economy. I do not subscribe to the fascinating Hegelian theory delineated by Mr. Fukuyama which proposes that we are at «The End of History», but I do believe that the Soviet Union and the Peoples Republic of China and their allies are not currently prepared to wage economic, let alone military, war against the West. By the same token I believe that current account deficits do matter. Countries like the United States and the United Kingdom can prolong the reckoning, but prolonging the current ac- counts deficit will eventually force considerable economic reform —as Mr. Micawber found out to his cost in the debtor´s prison.

The other major factor affecting the oil industry is the environmental movement. There are increasingly more of us in the world doing in- creasingly more environmentally unfriendly things. Although there is a great deal of middle class snobbery about wanting clean air as long as someone else pays for it and a great deal of technical misinformation, «Prospects for the World Oil Industry» 57

we all recognize the desirability of reducing the emission of carbon dioxide, oxides of nitrogen and other nasty chemicals into the at- mosphere. The end result of this pressure will undoubtedly be a ten- dency to prefer natural gas over oil, which in turn will be preferred over coal. Moreover, depending upon historical background, I expect a continued push towards use of nuclear energy wherever possible, since it appears to be the only environmentally clean fuel available on a significant scale —unlike solar energy, wind power and so on. If we insist upon moving around at an ever increased rate in cars, planes and trains, we shall have to use liquid hydrocarbons to do this, until a really efficient electrical battery is invented. This means that in the future oil will continue to be used as the raw material to produce transportation fuels, leaving the rest of the field (power generation, etc.) free for natural gas, nuclear, solar, etc.

Shell does not believe in single line estimates. Every year we think of two or more possible economic scenarios, which are not predictions but rather possible future economic worlds that are internally logical. From these scenarios certain conclusions emerge about energy sup- ply and demand and the raw materials needed for these worlds. I shall not give you the details of these two worlds, (a) «global Mer- cantilism», and (b) the «Self-sustaining World», since the collection of all the data and the subsequent analysis cost a great deal of money, but in qualitative terms we are talking about (a) a world which is fragmented, and where the main trading blocs —Japan, the USA and the EEC— are rubbing shoulders with each other in a highly competitive environment; and (b) another world that recognizes the interdependence of the human race, where there is a higher atten- tion to the environmental matters, where the world is sustained in some sort of manageable manner. I leave it to you to determine which sort of world you would like. I am certain that neither of these two worlds represents what will actually happen, but just thinking about them may help in the future, whatever your business, to make better decisions for the benefit of your shareholders.

From the oil industry point of view there is a significant difference between these two worlds in the call on crude oil after 2000. In the 58 Session I

Global Mercantilism scenario, by the year 2000 demand outside communist areas is 56.9 mbd, rising by 2010 to 60.5 mbd; whereas in the Sustainable World scenario it is 57.6 mbd, falling by 2010 to 50.8 mbd. Both cases show a similar call on exports from centrally planned economies and non-OPEC nations, but the Sustainable World case means that OPEC will be called upon to supply crude oil at significantly below its potential capacity, i.e., OPEC would not be in the «driver´s seat» for long, if at all. In Global Mercantilism OPEC gets back into the driver´s seat around the year 2000 and can stay there, depending, as always, on its internal discipline.

Another significant factor likely to affect the oil industry over the coming years is the shortage of complex refining capacity. Figure 4 summarizes the current situation, but do not take the absolute num- bers it shows too literally. The graph is a simple means of demon- strating that capacity, simply defined, is normally 80 to 85 percent utilized. With respect to the figures for conversion capacity, there are many ways of converting crude oil in refining , so Figure 4 is meant to be schematic. On the one hand, refining margins are not large enough to justify reinvestment, but without it the market will get very tight, as indeed it is today, just like the tanker market. It is very difficult to build refineries in environmentally sensitive countries like the United States, so I expect a push towards investment in places such as the Caribbean Islands or the Pacific. I do not see the money for these investments coming from OPEC countries, and this sug- gests that international oil companies will have a role to play.

Before discussing the short term, let me summarize the principal fac- tors that will influence the oil industry over the next decade or so. As a result of political and economic pressure on the Soviet Union and the United States during the last forty years, pressure which has led to a certain disenchantment if not political exhaustion, combined wit growing power and confidence in the EEC and Japan, we can see a step-change in global economic development taking place. This should result in three main trading blocs —denominated in currency terms as Japanese yen, European ECUs and American dollars. There may be a fourth group, which will be the ruble bloc. «Prospects for the World Oil Industry» 59

Apart from political and economic factors, people throughout the world have become aware of the importance of the environment. Some of the talk is not too solidly based, but a realization of the lim- ited nature of global resources has, I think, finally been borne in on the world.

The need to make these trading blocs grow internally and do recipro- cal deals will tend to favor economic growth, albeit on a fluctuating basis, which in turn will be modified by environmental considerations. These latter will depend very much on what sort of people are lead- ing governments over the next twenty years. In any case, focusing on the future for hydro-carbons, a good future for natural gas seems assured. Hence, heavy investment in pipelines and LNG transporta- tion appears highly likely. OPEC will probably get back into the dri- ver´s seat only if the market tightens up and lessens their internecine quarrels. Non-OPEC production, owing to every nerve being strained to enhance current production to create new fields, will remain ap- proximately at constant 26 to 27 mbd, for a few years at any rate. (This figure does not include exports from communist areas.)

Over the short term, we can expect fairly high growth to be main- tained, especially in the Far East. The oil industry, and Shell in par- ticular, have tended to be conservative in their outlook on con- sumption. Last year I was (rightly) chided by a stock broker for giving certain supply and demand figures which reflected lowish demand. Let me give you one view of the very short term. (Figure 5.) Looking at the world outside the communist area, a supply/de- mand balance of 51.2 mbd will rise about 2 percent, to 52.2. mbd. In the United States there will be moderate growth; the big growth will be in Japan and other Asian countries. We expect trends to continue.

When it comes to supply, we assume that there will be greater re- straint by OPEC than is currently being seen. They will have to cut their production in 1990, according to our projections, if they wish to keep a reasonably high price level. As I mentioned, the non-OPEC supply is more or less constant, and even with lower OPEC production 60 Session I

there is a considerable amount of stock buildup. Measured against a rising demand this is not too serious; the world can certainly accom- modate it.

In 1990 OPEC may give the appearance of being difficult to manage, but it is not in quite so much disarray as press statements would in- dicate. There is some doubt about what OPEC´s actual comfortable production potential is. Some of the member countries are producing today near their maximum, and even Saudi Arabia, to quote one par- ticular example, would have to invest very large sums of money in gas-gathering facilities if it were greatly to expand its production po- tential of light Arabian crude. As I mentioned earlier, there is a short- age of refinery capacity, particularly conversion capacity, and be- cause of the profile of the market, certain light sweet grades of crude will tend to be favored. Hence in the trading world the spread be- tween sweet and sour crudes will increase somewhat. In the longer term, because of the decline in low sulphur crude availability, refiner- ies will be forced to copy with higher sulphur crudes, with concomi- tant expenditure needed to isolate the extracted sulphur and render it environmentally harmless. There is, however, some cushion. I agree that about 26 to 27 mbd is about as much as they can com- fortably produce in the short term. This suggests a cushion of three to four mbd. The market is nevertheless getting a shade more un- comfortable, and it depends, moreover, on what kind of crude oil one is talking about.

There are difficulties with oil production in the Soviet Union. The decline in US production remains significant but difficult to predict precisely. These are but two factors which will bear considerably upon the short term. Perhaps most significant will be the straint that has been placed on refining and petrochemical manufacturing capacity over the last few years, which suggests that accidents may happen at an uncomfortably high rate. With the justified public interest in pollution and security, it is to be expected that production and refining units will be out of action for maintenance and careful checking rather longer than has hitherto been the case. «Prospects for the World Oil Industry» 61

Although oil consumption is not directly connected to economic growth, it is nevertheless a function of it. Thus any economic turn- down could presage a sharp reduction in crude oil demand. This would inevitable have its effect on prices, which are determined by the trading fraternity. So, despide current firm levels of crude oil prices, I think it unjustifiable to be more precise for the year 1990 than to indicate that volatility will remain the order of the day and that prices could fluctuate between $10 and $20 a barrel. Although the experience of a few years ago is still relatively fresh in producers´ mind, I do not think the price would remain at the lower level for too long. More likely, it would hover towards the top end of the range, as it is doing now, for a longer period.

So, ladies and gentlemen, I foresee a roller-coaster state of affairs for the foreseeable future which will test the resilience of the world´s oil producing, transportation, refining, and trading systems. I believe these systems, as before, will pass the test.

ALAN NAISMITH BINDER,OBE

Alan Naismith Binder has been President of Shell International Trading Com- pany since 1987.

Mr. Binder was born in 1931 and educated at Bedford School and Magdalen College, Oxford, where he majored in chemistry. After several years as a schoolmaster at Eton, in 1957 Mr. Binder joined Shell in London. He moved to Argentina in 1958 and became General Manager of Shell Peru in 1961. He subsequently worked in Colombia, the UK, New York, and Cambodia, before returning to London in the chemicals business in 1974 as General Manager of the Polymer division. In 1979 he became General Manager of the Industrial Chemicals division, and in 1982 President of Shell Chemical In- ternational Trading. In 1984 he became a Director of Shell International Pe- troleum Company and Regional Coordinator, Middle East for the Royal Dutch/Shell Group of companies. 62 Session I

Figure 1 Year-to-year percentage change in price of U.S. crude oil 1901-85

(%) (%) 80 80

60 60

40 40

20 20

0 0

-20 -20

-40 -40

-60 -60 1905 10 15 20 25 30 35 40 45 50 55 60 65 70 75 80 85 «Prospects for the World Oil Industry» 63

Figure 2 Non-OPEC crude/NGL production (million b/d)

Forecast

1989 1989 1989 1989 Year 1990 1990 1990 1990 Year I II III IV 1989 I II III IV 1990

USA 9.4 9.3 9.1 9.2 9.3 9.3 9.1 9.0 8.9 9.1 Canada 1.8 1.7 1.8 1.8 1.8 1.8 1.8 1.8 1.8 1.8 México 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.7 2.6 2.7 UK N. Sea 2.0 1.7 2.0 2.2 2.0 2.3 2.0 1.9 2.2 2.1 Norway N. Sea 1.5 1.6 1.6 1.6 1.5 1.8 1.7 1.8 1.7 1.7 Egypt 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 Oman 0.6 0.6 0.6 0.7 0.6 0.7 0.7 0.7 0.7 0.7 Malaysia 0.6 0.5 0.6 0.6 0.6 0.6 0.6 0.6 0.6 0.6 Australia 0.6 0.5 0.6 0.6 0.6 0.7 0.7 0.7 0.7 0.7 Argentina 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 0.5 Brazil 0.6 0.6 0.6 0.7 0.6 0.8 0.8 0.8 0.8 0.8 India 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 Synfuels 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 0.7 Other non-OPEC 3.3 3.2 3.3 3.3 3.2 3.3 3.4 3.5 3.5 3.4

TOTAL NON-OPEC 25.9 25.3 25.7 26.0 25.7 26.7 26.3 26.2 26.2 26.4 64 Session I

Figure 3 Downstream interests of major companies (excluding joint ventures and processing) Million b/d 5

Product Sales

4

Refinery Capacity

3

2 ** *

1

0

o l P C l n c il n s o P A o e o a B b a c F S P o c h r x x o b o C V K S v x o m l m D Te M e r E a a t r P h A t e C A P i To

d

u

a * Star Enterprise: joint Saudi/Texaco US East Coast deal. S ** Overseas interests «Prospects for the World Oil Industry» 65

Figure 4 World Primary Distillation Capacity, 1988 (excluding USSR, Eastern Europe and China) Million/ tonnes/ year North Europe East/ South Middle Africa America (incl. Turkey Australasia America East 1.000 & Cyprus (incl. Indian (incl. Mexico) (excl. Turkey Sub-continent) & Cyprus) 913

Primary Capacity & utilisation (%) 711

Conversion capacity (Catcracker equivalents) 559

70% 500 475

75% 326 90% 228 195 82% 134 96 98 73% 67 15 66 Session I

Figure 5 Industry supply and demand balance World outside Communist areas (million b/d)

Forecast

1989 1989 1989 1989 Year 1990 1990 1990 1990 Year DEMAND I II III IV 1989 I II III IV 1990

USA 16.8 15.9 16.0 16.9 16.4 16.8 16.1 16.3 16.9 16.5 OECD Europe 12.1 11.3 11.4 12.5 11.8 12.4 11.4 11.6 12.4 11.9 Japan 5.4 4.4 4.6 5.4 5.0 5.9 4.6 4.7 5.6 5.2 Others (incl. RF&L) 17.9 18.0 17.9 18.2 18.0 18.4 18.5 18.5 18.6 18.6

WOCA DEMAND 52.2 49.6 49.9 53.0 51.2 53.5 50.6 51.1 53.5 52.2

SUPPLY

OPEC - Crude 20.3 21.2 22.2 22.9 21.6 21.3 21.3 21.6 22.4 21.7 - NGL 1.9 1.9 1.9 2.0 1.9 1.9 1.9 1.9 1.9 1.9 Non - OPEC 26.0 25.5 25.8 26.2 26.0 26.9 26.5 26.4 26.4 26.5 Exports ex. E. Bloc. 2.3 2.6 2.6 2.5 2.5 1.9 2.2 2.4 2.2 2.2 Stock draft/(Build) 1.7 (1.6) (2.6) (0.6) (0.8) 1.5 (1.3) (1.2) 0.6 (0.1)

TOTAL SUPPLY 52.2 49.6 49.9 53.0 51.2 53.5 50.6 51.1 53.5 52.2 67

SESSION II

«THE RELATIONSHIP BETWEEN OIL AND MONEY»

INTRODUCTORY REMARKS

EIJA MALMIVIRTA

Welcome to the afternoon session. Permit me to start in first by in- troducing myself. I am Eija Malmivirta from NESTE, the National Oil Company of Finland, where I am the Executive Vice President, responsible for our international oil trade. So in practice I am a very fundamentalist oil trader and supply person, not a technical trader.

It is a very interesting role that I have been given here, to chair and be the moderator for the topic of relationships between oil and money markets. Of course, oil has always been intimately related to money, so the title could cover quite a lot of things; but I think the aim is re- ally to discuss the new markets that have developed during the 80s, when the oil market started to use the techniques of the money mar- kets and oil became a commodity of interest to investors as well as oil companies. One can state that during the past ten years in the oil in- dustry, market trading has experienced the greatest change. Nowa- days, to really be able to work and be profitable in that environment one has to command totally new skills and in a very wide area. This requires a lot of knowledge that previously did not really belong to the oil executive´s tool kit. It has been a tough learning job for me, and, I suppose, for many others in this room as well. 68 Session II

FROM SHARES TO LONG-TERM PRICING

In discussing the «relationships between oil and money markets», let me briefly remind you of some of the developments in the oil mar- kets that have occurred over the last decade or so. Before the futures markets in oil had developed, investors´ money flowed into oil stocks, and the money market watched the performance of those stocks closely to determine the direction of the money flow. Now oil itself, as a commodity, has become the object of investors´ interest. This has led to the development of sophisticated systems, many borrowed directly from the money markets, through which investment houses can trade in oil and oil related instruments. During the next phase in this development oil will increasingly be looked at as a financial asset. The deals will be done several years ahead of actual production, while the oil is still in the ground.

VOLATILITY

Prior to the inauguration of the futures markets, the oil industry made its trading and supply decisions on the basis of perceived global supply and demand, actual and projected. The major political upheavals of the late 1970s and the economic recession of the early 1980s generated wide fluctuations in crude oil prices. This was the reason why forward markets in Brent and West Texas Intermediate (WTI) crude oil became prominent during the 1981-1983 period.

SPOT, FORWARD, FUTURES MARKETS

Two of the speakers in the first session referred to the technical trad- ing and electronic trading in futures markets in the 1970s. How short is our memory? Actually, in the 1970s we didn´t have such trading. The NYMEX contract in WTI crude started only in 1983, with first year volumen of approximately 1500 contracts per year (adjusted to an annual basis). The Brent contract in this current form has been op- erating for some eighteen months. Now trading volume in WTI and Introductory Remarks 69

Brent crudes is at a daily rate of 65 million and 6.5 million barrels, re- spectively. On average this is more than the total daily world con- sumption and on some days double that consumption. It is some- thing that can no longer be ignored.

EVALUATION OF INCREASINGLY COMPLEX INSTRUMENTS

The oil markets had become too volatile to base business decisions on a simple view of the market´s direction. Coping with the price risk has become a major challenge. The development of effective futures markets was a major step in meeting that challenge. Since then the development of futures and over the counter options con- tracts as an extension of the straight futures contract has changed the role of the oil company trader from one of a price forecaster to that of a risk manager. The use of these tools has provided a host of opportunities to manage risk or make profits. In fact, with the news of a Far East, Dubai futures market being established, the risk manager´s job is becoming global in terms of location and trading hours.

The new market also brought new players into the game, greatly di- versifying the participants. In the 1970s only the oil companies and oil traders were involved. Nowadays we also have consumers, banks and investment funds. (We are not sure whether any doctors or den- tists are still involved I suppose some of them got their fingers burnt so badly they have withdrawn.) Recently there was an interesting description of the London futures market showing the makeup of the players (they actually call them players in this game). On the London Exchange, for example, 50 percent are traders, some 16 percent are refiners, some 10 percent producers, along with other groups.

A whole new vocabulary has emerged. Many participants in the oil markets are involved in «hedges», «arbitrage trades», «floors and caps», etc. In the options market we have a veritable menagerie of «condors», «butterflies», and our old friends, the bull and bear spreads. 70 Session II

CONTROVERSY: FUNDAMENTALS VS. PSYCHOLOGICAL TRENDS

There has been much controversy about the benefit of this type of mar- ket to the oil industry. A recent study by the Harvard co-sponsors of our meeting here today praised the oil futures markets for their efficiency as providers of information. It should be pointed out, however, that these markets react with great volatility to news headlines and rumors that are not necessarily relevant to supply circumstances. It can be said that there are actually two markets determining the price of oil: the physical, fun- damental market reflecting the demand/supply balance, and a psycho- logical market played in futures that reflects the hopes and fears of its players. Proponents argue that the market provides information about the likely path of future oil prices, that it increases the flexibility of the buyer-seller supply relationship, that ir relieves pressure on the spot mar- kets, and that it makes spot prices informationally more efficient —all al- lowing market participant to hedge against the risk of new price shocks.

Many oil industry observers have questioned these claims. They say that the futures market is excessively volatile, unstable, and unrelated to fundamental market conditions in the oil industry. Critics have argued that futures markets have destabilized the spot markets and brought additional risk into the buyer-supplier relationships. Accord- ing to Mr. Nazer, the Saudi Oil Minister, the oil futures market could be considered as «legalized gambling». I hope this is an issue that will be discussed here. What are the pros and cons, and what would be best for the oil market?

Whatever the truth, the fact is that these markets are a very strong force in the price forming mechanism. Volatility today is so great that no one can take the risk of such price swings, and hedging is there- fore a must for oil companies.

A WHOLE RANGE OF NEW CREATIVE INSTRUMENTS

There is a possibility nowadays for what I would call «strategic price management». There is the possibility for long term price hedging Introductory Remarks 71

through so-called price swaps or commodity swaps by which you can fix your price for up to five years in the future. In a sense, oil can be considered a financial asset because you can fix the price in the ground, and if you have a fixed price for it you can use it as an asset. This new type of transaction has involved some of the newer players in the markets —the large banks as well as some of the long estab- lished traders and securities houses. The markets are still quite thin, however, with only ten to fifteen players. The concept (borrowed di- rectly form the foreign exchange and interest rate markets) relies on the current prices and pricing trends to generate far forward prices. The successful long term price swap provides the correct assessment of the price trend, the ability to finance long term, and the willing- ness of both parties to conclude the deal at the set price. For the first time it is possible to apply strategic risk management and hedge long-term price exposure.

The changes that have taken place have moved the oil markets to a much closer resemblance to the money markets, with technical analysis living side by side with fundamental supply/demand projec- tions. The oil markets watch the American Petroleum Institute statis- tics the way the money markets watch the US trade figures.

Summing up, all of us must admit that the oil and money markets nowadays are getting closer and closer to each other; and the oil market has been borrowing from the money market on an almost monthly basis, learning new techniques and ways to do business. We oil people will have to learn the financial engineering techniques. We at NESTE think we are seeing an increasing integration of the two markets and expect that the trend we have followed during the past six years will be continued.

We have three presentation here today. The first, by Dr. Robert Weiner, Energy and Evironmental Policy Center, Harvard University, will cover the forward markets, especially the Brent market and its ef- ficiency. Then Mr. Robert Ryan, Manager, Risk Analysis, of the New York Mercantile Exchange (NYMEX) will present us the current and new contracts of the NYMEX futures market, and how these will fit 72 Session II

into the present and future oil environment. Mr. Ernst Weil, Chair- man and CEO of Phibro Energy AG, will follow with the view of the practical man. He is certainly one of the most experienced partici- pants (I am not saying players) in this market, so he should be inter- esting to hear.

EIJA MALMIVIRTA

Eija Malmivirta has been the Executive Vice President for Trading and Supply of Neste Oy, the National Oil Company of Finland, since 1988.

Mrs. Malmivirta received a Master of Sciences (Engineering) from the Hel- sinki University of Technology in 1967 and has participated in several Execu- tive Postgraduate programs. She joined the commercial planning department of Neste Oy in 1969, became Manager for Crude Oil and Petroleum Pro- ducts Imports in 1971 and marketing Manager for Petroleum Products Im- ports in 1977. In 1981, she became the General manager for International Trade, in 1985 the Vice Presidente for International Trade, and in 1986 the Senior Vice President for Trading and Supply.

Mrs. Malmivirta is on the board of several organizations, including the Fin- nish-Arabic Trade Association, the Finland-Iraq Association, and the Board of Supervisors of the Finnish Foreign Trade Association. 73

«CRUDE OIL FORWARD AND FUTURES MARKETS: A COMPARISON OF BRENT AND WTI»

ROBERT J. WEINER

«The growth of trading in crude oil and refined products has been perhaps the most important feature and manifestation of structural change in the world oil market over the last 10 years.» Saudi Arabian Oil Minister Hisham Nazer, 1989

This discussion will focus on the North Sea, particularly on the Brent forward market, using the futures market as a benchmark against which to compare it. As part of a growing worldwide trend towards the use of markets there has been a great growth in trading crude oil and refined products. The quotation above was made at the recent London conference on growth in trading. The context of the quotation is that the Saudi Oil Minister was not very happy about the past decade´s growth in trading, but that growth is a fact of life that people in the oil market are learning to live with. As you may recall, it is a rel- atively recent development: the worlds of oil and money are much more intertwined than they were ten years ago, when the majors —the multinational oil companies— controlled almost all the oil moving in international trade. Now that vertical integration has been replaced by vertical dis-integration and only some partial re-integration, crude oil and product trading both have become major phenomena. 74 Session II

The project I shall describe was motivated by this growth in trading and, in part, by the results of this conference two years ago. The de- tails of this part of the project can be found in the monograph Oil and Money: Coping with Price Risk through Financial Markets (Har- vard International Energy Studies, 1989), hereafter referred to simply as the monograph. In the first Harvard-REPSOL conference, the dis- cussions had a lot to do with the tremendous risk and price volatility that was facing the petroleum industry, and it was observed that lit- tle or nothing was said about it or investigated by researchers. So when Bill Hogan and Bijan Mossavar-Rahmani returned from that conference they suggested organizing a project to look into this. Thus was the oil and money project born two years ago.

There is very little research on trading by economists. Kathryn Dominguez and I are both economists, so we will give the econo- mist´s perspective on trading. To use Eija Malmivirta´s terminology, economists are all fundamentalists. If they believe anything, they be- lieve in fundamentals; they do not believe in technical analysis.

I will focus on the crude oil market —the area of our research. As we have heard, the forward markets have developed in crude oil as well as in petroleum products around the world. From the economic viewpoint it is interesting to note that although these markets are very large, the are not monitored or regulated; prices are not instan- taneously available, as they are in the futures market. Transactions are private: when you make a deal with someone, you are not obliged to tell anyone the terms. Before the 1980s the forward mar- ket (which it was not yet called) was one of long-term contracts. Oil companies had contracts with a producing company or producing country for several years, and the terms were renegotiated periodi- cally. The forward contracts were term contracts, as opposed to the forward one-shot or spot contracts that I am talking about.

The impetus for the forward contracts in the markets we see now —Brent (the best known) and at least a half dozen others in which there is more limited trading— came from the oil industry. This is in contrast to the futures market, where the impetus came from the «Crude Oil Forward and Futures Markets: A Comparison of Brent and Wti» 75

financial community. The forward markets have thus always been at least somewhat more acceptable to the oil industry than the financial markets´s innovation of futures trading because of the invented-here rather than the not-invented-here syndrome.

Our interest was in how well these markets work compared with markets in which trading is done on an organized exhange. We chose the Brent market as a case study simply because it is by far the largest and most well-developed of the forward markets. If it turns out that this market doesn´t work all that well, it would be very un- likely that any of the smaller, thinner markets would work well either.

Now why should anyone other than academics care whether these markets work well at all? I can think of three groups who, at least in principle, should have some interest. The most obvious group is the oil companies, including virtually all of the larger and many of the smaller ones. Companies that are either already hedging or would like to do so would have an interest in knowing whether the market works well enough for their hedging strategies to be effective. I will not discuss how well hedging strategies have worked. Kathryn Domínguez has covered that in the piece in the monograph, and I urge you to look at it. A second, broader group includes any buyer or seller whose crude price is tied to the priced in these markets. And for those who follow how crude oil is priced, much of the crude that moves in international trade is based on either Brent, WTI, or some in- dex of these crudes that are traded on forward and futures markets. The final group comprises governments that use these prices. Some governments use them for their regulatory and tax policies. Here I think particularly of those governments with North Sea territories —the UK and Norwegian governments. They don´t literally take these prices and make them their tax reference prices, but they do base their reference prices and regulatory prices on these markets. Thus they should have some concern as to whether the markets on which they base their fiscal policies in the petroleum sector work well.

A second reason for our being interested in this market is that we at Harvard have had a tradition for about ten years of thinking about 76 Session II

energy security and oil supply disruptions. The Brent market experi- enced a serious disruption during early 1986, when the price fell from about $30 per barrel to $10 per barrel in only a few months, and this is really the only instance of a paper barrel market´s experi- ence with disruptions. At the time of the disruptions of the 1970s there were no such markets, so we don´t have any direct evidence on how they would function in a crisis. The best we can do is to use the indirect evidence provided by the Brent disruption of 1986 to try to help us predict how paper barrel markets might behave in future dis- ruptions. Many in the oil industry and governments are very skepti- cal about the performance of these markets during a disruption and assume that they will collapse, or become otherwise useless, even if they are still functioning.

The final reason for undertaking the project concerns regulatory pol- icy. Comparison of the unregulated forward markets with regulated futures markets will, we hope, help us get some idea of what the ef- fect of increased regulation might be. As you know, the futures mar- kets have received some very negative publicity in the last couple of years, ranging from the alleged role of futures in the worldwide stock market crash of 1987 to the recent accusations of shenanigans, shady trading, or illegal trading practices on the floor of some of the Chicago exchanges and more recently the New York Mercantile Ex- change. This has led to the call for more regulation in the US and the UK, where the Financial Services Act of 1988 contains some moni- toring and regulatory authority, although relatively light, over the Brent market.

Economists tend to use past events as a laboratory. We look at the 1986 crash as a laboratory for future behavior during disruptions. We look at the performance of forward unregulated markets as a laboratory in comparison with the regulated markets to see whether regulation might make a difference. Since we get a lot of mileage out of the comparison of forward with future markets, I would like to re- view briefly some of the institutional differences on which we base our comparison, using the differences between the markets in Brent and WTI crude. This comparison is summarized in Table 1. «Crude Oil Forward and Futures Markets: A Comparison of Brent and Wti» 77

First, the nature of the product. West Texas Intermediate and the Brent blend of crudes are very similar, but they are not identical. Their characteristics are sufficiently similar to make the comparison workable.

Table 1 Comparison of crude oil forward and futures markets

WTI futures Brent forward Nature of product Very similar Nature of players Very similar; Japanese trading houses (shosha) have been large players in forward market Nature of trading NYMEX floor Telephone, telex Price information Open outcry; inmedia- Private; available only tely available through surveys of tra- ders Clearinghouse, margins Positions «marked-to- No clearinghouse; no market» every day by margins clearinghouse Delivery risk No delivery risk; deliv- No protection against ery guaranteed by default clearinghouse Experience with market No serious problems Serious defaults in early functioning problems 1986 Liquidity Liquid Illiquid; market very thin Regulation Exchange regulation, No regulation U.S. federal regulation

Second, the nature of the players. Again, they are quite similar. We paid special attention to Japanese companies for two reasons. For one thing, the Japanese Shosha (General Trading Company) has an almost legendary ability to make money in trading. For another, the Japanese provided much of the financing for the study. Academics may inhabit an ivory tower, but a Robert Solow once said, we follow the election results.

Third, the nature of the trading. This is very different. The organized futures market trades on the floor on the New York Mercantile 78 Session II

Exchange, whereas the Brent market is one in which trading takes place through telephone and telex; all of the deals are bilateral.

Fourth, the way price information is conveyed to the market. Here, too, there is a great difference. In the so-called open outcry system of the futures markets, price information is instantaneously available to anyone on the floor and anyone who is connected to electronic media. In contrast, the terms in the Brent market are private; the only way they become known is through surveys conducted by compa- nies who specialize in this function. They call up petroleum traders and ask, «What deals have you done today». (This is a good oppor- tunity for me to thank Petroleum Argus, without whose data we would just as ignorant as everyone else of the terms of the trades that go on in the Brent system.)

Fifth, the existence of a clearinghouse and margins. The futures mar- ket has a clearinghouse through which everyone´s position in «marked to market» at the end of every day. This means that for all practical purposes the value of your futures contract is zero at the end of the day. Your daily gains or losses depende on whether you have a long or short position and whether the price has gone up or down. The gains and losses are closed out and credited to or debited from your account, leaving your futures contract worth nothing. In the forward market there is no clearinghouse, nor are there any mar- gins. Thus a contract can have a large positive or negative value if the price has moved a lost since the contract was signed.

Sixth, delivery risk. This is closely related to the preceding point. In the futures market there is no delivery risk; delivery is guaranteed by the clearinghouse, which interposes itself in every transaction. The forward market provides no protection against default. It is only the reputations of the companies, supported very loosely by United Kingdom contract law, that prevents people from defaulting. Both types of market have price risks, but only the forward market has delivery risk. If this were to get too great during a price shock, there could be a disruption (defined here as a change in the way normal practices are usually done; firms not complying with their «Crude Oil Forward and Futures Markets: A Comparison of Brent and Wti» 79

contractual obligations). This is one of the reasons we are interested in this market.

Seventh, experience with market functioning problems. The crude contract on the New York Mercantile Exchange has never had any serious fuctioning problems to my knowledge, whereas the Brent market experienced the serious defaults in 1986 which I have already referred to. These defaults led at the time to widespread predictions, in the petroleum trade press, of the impeding demise of the market. Indeed, the market did shrink quite a bit during 1986, but the demise did not take place.

Eighth, liquidity. This is a big issue with trading people who partici- pate in these markets. The New York Mercantile Exchange is relativ- ely liquid as such markets go, although some of the big companies complain that it is not liquid enough for them. The Brent market is definitely less liquid; it is quite a thin market, with a relatively small number of transactions per day. This makes it less likely to work well, according to conventional wisdom.

Finally, regulation. I have already alluded to the contrast here. The futures market has both government regulation and regulation im- posed by the exchange for people who want to participate. In con- trast, the Brent market has only the traditions of the contract to pro- tect participators.

Since this is not an academic conference I shall not give you the de- tails of our analysis. If you would like to know them, I urge you to read the monograph. But I will discuss our conclusions, the most sur- prising of which, at least to me, was that Brent market prices are ef- ficient in the sense that is used by the financial community: efficiency with regard to information. This is especially surprising considering the price secrecy and the way in which prices are transmitted to the market. From a practical point of view, efficiency means the forward price today, that is quoted on the wire, in Platt´s, or whatever, for two months forward on the Brent is the best predictor of what the actual spot price of Brent will be two months in the future. This 80 Session II

means that if you want to guess what the price of Brent is going to be two months hence, and if you look in the newspaper and see what the traders in the market have decided what that value is go- ing to be, on average they will be right. Depending on what hap- pens, of course, that guess could be a very bad one, but compared with other forecasting services, on average it is right.

Our second finding concerned the default period in early 1986. We found that the defaults resulted in a contraction of the market by a factor of about two, but not the complete collapse expected in the trade press. There was one headline at the time that read «traders´ binge turns into a wake,» and there was much discussion of how a dead Brent market could be resuscitated. In fact, if you look at trad- ing during the time, it fell markedly, but at no time did it come any- where near disappearing.

We looked to see where the 50 percent decline in trading was com- ing from, and found that much of it was due to a decline in trading by non-Japanese trading companies, on other words not the Shosha. By trading companies I mean those that have no production or refin- ing capacity; they are in the trading business only to make money. It was these non-Japanese trading companies that were responsible for much of the defaulting that took place.

We looked to see whether a default risk premium existed in the market. This term is another way of saying that a price contains some element of an insurance fee. One would expect this to be present under the circumstances. I take a risk by trading with you in a mar- ket that is not a futures market, as delivery is not guaranteed, so I need some kind of insurance against failure to live up to the contract —to make or take delivery, depending on who does not live up to the implied obligation. Through the usual process of statistical analysis, we were able to isolate a default risk premium.

From this we were able to draw two conclusions. Yes, people realize there is default risk. But when we compared the default risk before the time of actual default in 1986 with the default risk after that «Crude Oil Forward and Futures Markets: A Comparison of Brent and Wti» 81

debacle, we were unable to isolate any statistical differences. If our conclusions are correct, people who play this market realize that there is a default risk and thus implicitly include an insurance fee in their prices. When the defaults took place they still had the insurance premium. This implies that an insurance premium in this type of mar- ket can be a good substitute for a futures market, and all the argu- ments for futures markets as the safe way to go because they are much better than informal forward markets are not necessarily true. There is more than one way to get the job done. If you have an in- formal market in which there is no protection against default except reputation, you pay something for that. We tried to find a larger de- fault premium in may different ways and never found any.

My final subject is: Where do we go from here? The analysis I have been describing was finished and the monograph written last spring. We are continuing our work, and the question we asked ourself was «¿a dónde vamos?» We decided to switch our focus a bit from the performance of the market to the trading process itself. By this I mean, we want to see who makes money and who loses money on the trading market («who» refers to the types of companies). The in- dividual companies are not identified by petroleum market surveys, otherwise they would never give the surveyors the data that the re- ported in order that people can know what the Brent prices are. Pe- troleum Argus classifies companies into different types: producers, refiners, integrated companies, traders, Wall Street banks, and sev- eral others.

We have just constructed the hypothetical accounts for these com- panies. They correspond exactly to the types of accounts that com- panies or anyone —doctors and dentists— have to keep with their brokers if they are playing the futures market. Every time a transac- tion occurs and the price moves for or against you, you get a credit or debit on your account. We are trying to see which types of com- panies make money and which lose money in this market.

For each type of company we are building two accounts. One is the holding account, which represents the day-to-day changes. We´re 82 Session II

interested in finding out how good a company is at forecasting what the price will be one day later. Is it buying when the market is rising or is it buying when the market is falling? In the former, the holding account will have profits posted, in the latter, losses. The second type of account we call the search account. Such an account can only ex- ist for markets that are not organized, which is to say, there is no trading floor. The transactions take place with people calling each other on the phone and talking about deals, then confirming via telexes. Thus there is no one price. Every deal is negotiated bilater- ally, based on whatever information companies have and how good they are at finding deals. On a given day there may be twenty con- tracts in twomonth forward Brent, some at higher prices than others.

We are looking to see which types of companies are paying the hi- ghest prices and which the lowest within a given day. Then we will try to see if some companies are better than others at searching for good deals. We are constructing the accounts to see whether any companies are systematically making money within a given day, as opposed to making money from one day to the next.

At this time we have only preliminary results. Perhaps I´ll be able to tell you about our complete findings and conclusions at next year´s REPSOL seminar. Muchas gracias.

ROBERT J. WEINER

Robert J. Weiner is Assistant Professor of Economics at Brandeis University where he teaches finance, industrial organization, international business, and statistics. He is concurrently Research Fellow in the International Energy Pro- gram at the Energy and Evironmental Policy Center, John F. Kennedy School of Government, Harvard University.

Dr. Weiner received his bachelor´s degree in applied mathematics, and mas- ter´s and doctoral degrees in business economics, all from Harvard Univer- sity. His work focuses on the international petroleum market. He has publis- hed numerous articles on aspects of natural resource economics and has coauthored two books, OIL SHOCK and OIL AND MONEY. 83

«THE ROLE OF FUTURES IN A GLOBAL ENERGY MARKET»

ROBERT RYAN

The world continues to move toward what appears to be a seamless market. Decontrol and liberalization of local and regional markets is underway in many areas of the world. Nations, companies and indi- viduals alike now look beyond national boundaries to minimize costs and maximize revenue. Governments are showing increasing resis- tance to price stabilization and control programs that subsidize inef- ficiencies in native industry. And consumers are no longer willing to underwrite these inefficiencies, since they realize they ultimately bear the direct and indirect costs of all such efforts and receive a small share of the benefits. As goverments internationalize their economies, competitive pressures intensify and relationships among world markets tighten.

We in the west have believed that a fully integrated global market makes economic sense and that it fuels the competition that eventu- ally leads to the most efficient allocation of resources. Beliefs aside, however, the development of sophisticated trading and communica- tions techniques and networks in truly fusing the world into a very tiny place in which business gets done quickly, regardless of bound- aries, making truly global markets an objective reality. 84 Session II

There are many tangible examples of such evolving markets. The global energy market, because it represents such a huge share of to- tal world commerce, serves as a dramatic example of this market in- tegration. In the context of this conference, we will examine the oil market.

Market pricing of oil and related energy products has been estab- lished as the most efficient arbiter between supply and demand on a global scale. We have seen many new participants enter the oil busi- ness, using new products and services to manage the price risk asso- ciated with market pricing of energy. Examples include the establish- ment of exchange-traded futures and options (not only at the NYMEX but also at the IPE and recently the ROFFEX), forward mar- kets, over-the-counter (OTC) options markets, and most recently, off-exchange instruments such as swaps and trigger pricing arrange- ments that contain many options-like features.

In the decade of the 1980s, global energy markets have seen the de- velopment of new tactics for dealing with newly created and everin- creasing competition. Producers move downstream; traders move upstream; banks act as principals; and cross-border partnerships are formed. New financing techniques emerge, and risk management expands.

This world is very different from that of a decade ago when OPEC set the price of oil unilaterally; suppliers and consuming nations exert- ed little influence. OPEC´s high prices caused an expensive cycle of substitution, conservation, an non-OPEC exploration that reduced OPEC demand and, ultimately led to the decentralization of the mar- ket —the global diffusion of buyers and sellers— that ended its abil- ity to set prices.

Recently there has been much discussion, especially from OPEC, about «stabilizing» the market to the mutual benefit of buyers and sellers, and about mutual dependencies —producer to consumer and consumer to producer. In London last month, Saudi Oil Minister Hisham Nazer spoke at length on these relationships and espoused a «The Role of Futures in a Global Energy Market» 85

single important truism about energy today. He said simply, «Too high a price merely sets the stage for too low a price.» To avoid both extremes, efforts should be made to stabilize the industry by balanc- ing supply and demand, although not through price manipulation.

OPEC´s target price seems to be somewhere between the 15 to 20 dollars we´ve seen over the last twelve months, a range considerably narrower than the 30 + to – 10 dollars of a few years earlier. Many believe this is a price range low enough to promote consumption, high enough to encourage exploration and development, and steady enough to enjoy credibility among producers and consumers. This may or may not be true. Time will tell.

Even though there seems to be a spirit of cooperation, no one is pre- dicting the demise of spot trading or an end to price volatility. As long as competition exists among market participants, there will be volatility that competitors need to manage. Stability, although bene- ficial to long-term planning, does not imply the end of uncertainty for either the near-term or longer-term future.

This competition is one of the few constants in the world. Buyers´ and sellers´ interests are not the same: the former will seek a high price for the commodity, the latter, a low price. The market —objec- tive and impersonal— reconciles these opposing interests. But mar- kets are not without risk: continued deregulation of major markets will accelerate global risk management. We believe demand for risk management will continue to increase from already significant levels.

NYMEX´S ROLE IN GLOBAL RISK MANAGEMENT

Trading crude oil, heating oil, unleaded gasoline, residual fuel oil and propane futures, and crude oil, heating oil, and gasoline options, the New York Mercantile Exchange operates and maintains the largest oil-price risk-management forum in the world. From January to No- vember of this year, over 154,000 energy futures and options con- tracts were traded at NYMEX on a daily basis. As each contract is for 86 Session II

one thousand barrels, this is equivalent to 154.3 million barrels of crude oil and refined products a day. The greatest single day´s vol- ume at the Exchange was 292,178 contracts, on December 17, 1987. That´s a 292.2 million barrel equivalence. The highest monthly volume was recorded in June of this year —3.8 million contracts, or 3.8 billion barrels. Last year, a total of 34.3 million energy futures and options contracts were traded on NYMEX —equal to 34 billion barrels of crude oil and refined products.

Most of this trading is done by United States-based firms, but partic- ipation in NYMEX is global in scope. Our marketing surveys of the 25 largest long and short position holders at the exchange have shown participation by non-US firms of more than 30 percent. Non-US par- ticipants include companies from Europe, South America, the Middle East, the Far East, and Canada.

Most of this trading does not result in delivery, since futures and op- tions are primarily financial risk-management tools. When delivery does take place, one particular type, Exchange of Futures for Physi- cals (EFPs), predominates, and demonstrates the increasing role of non-US participants at NYMEX. An EFP is a multi-dimensional tool in which two parties exchange cash and futures market positions, and thus establish or close out hedge positions.

For those who are not familiar with the term, a «hedge» is nothing more than taking an offsetting risk in a futures or options market agains the risk that you already bear in your cash market. For exam- ple, you are buying crude oil for a refinery, you don´t have the crude oil. Rather, you are pricing at some date in the future, and you don´t know that price at the present. You can buy the futures contract and, to a certain extent, capture any of the price change that may be detrimental to your future profitability. When you unwind the hedge, you sell back your futures and realize the financial gain from that transaction, applying it to the actual physical transaction in which you buy the oil. In the best of all possible worlds you make a little money on the hedge because of what is known as a «basis change;» and in the second best of all possible worlds you break «The Role of Futures in a Global Energy Market» 87

even. In most cases, the hedge allows you to stay at least ahead of the game.

In calling the EFP a «multi-dimensional tool» I refer to the fact that in an EFP all terms of the agreement are negotiable. The exchange of futures for physicals allows you to specify the timing, the place, the quality, and the petroleum commodity you will actually take or make delivery on, as opposed to going though with a contract-specified delivery of a light sweet crude oil, the par of which is West Texas In- termediate in Cushing, Oklahoma. But of what value is standard de- livery in Cushing, Oklahoma, to a European or Far Eastern refiner? If they can somehow index a transaction against that price, however, make their delivery in the Shetland Islands or at Singapore and use the EFP mechanism to effect that delivery, they have increasted the utility of the futures contract to their firm. EFPs are very powerful, and they are used very often.

Perhaps the greatest benefit of EFPs is that they offer both sides of the transaction independent control over how to manage risks. Once buyers and sellers initiate an EFP, it´s their own decision —and independent of their partner— how to close out that position. EFPs also can be used in a marketing role. By hedging in the futures mar- ket before finding a trading partner in the physical market, one can establish an acceptable price for oil, then use the EFP to move phys- ical crude while closing out a futures market commitment. This of- fers both sides protection in global markets and delivery in local markets. Moreover, since EFPs are off-exchange agreements, and because neither party is required to hold a futures position to initially contract one, EFPs allow foreign firms to hedge and trade on NYMEX during their own local business hours, even when NYMEX is not open.

EFP volumes have risen dramatically in recent years. In 1986 EFP ac- tivity in our crude oil market amounted to just over 250,000 con- tracts. Last year, crude oil EFPs totalled more than 600,000 contracts and accounted for the vast majority (well over 90 percent) of total deliveries. 88 Session II

OTHER FORUMS

We have also witnessed a proliferation of others markets and tools to address rising demand for management of price risk. The newest en- trant to the futures market is in Europe where the Rotterdam Energy Futures Exchange recently began trading with what many observers call «better than expected» volume. In Japan, press accounts have reported the formation of a special panel of oil industry and govern- ment representatives to study energy futures trading. Special panels are often the first step toward implementation in Japan and are widely viewed as a promise of action to come.

In other global energy futures markets, Brent trading in London re- mains firm and the Singapore Monetary Exchange (SIMEX) has indi- cated that it is developing a crude contract to complement its resid- ual contract.

Futures trading is a logical complement to an increasingly competi- tive global marketplace, providing an open forum for discovering price. It offers an unambiguous, fully transparent price reference, giving the industry an ability to make informed decisions on produc- tion, acquisition and distribution. It provides an effective means of managing the volatility and uncertainty the industry faces in physical market deals. It consolidates market liquidity: all information bearing on the relative value of oil has an opportunity to enter the market and be reflected in price. And because superior information often conveys a monetary reward, there is a direct incentive to buy or sell when one possesses superior intelligence in the information sense, i. e., having certain as opposed to ambiguous information. In this fash- ion, price reflects the best knowledge. Finally, it provides financial protection against counterparty credit risk, via the clearinghouse structure.

Let me give an example. When the Brent market crashed, we had enormous volatility. The interesting thing was that we increased our margins to aroun $4,000 + per contract. (The margin is the perfor- mance bond traders must post in order to trade the contract. It «The Role of Futures in a Global Energy Market» 89

serves as a guarantee that they will honor all financial commitments. Margins are critical to the trading of futures.) We found that our vol- ume was increasing incredibly and our open interest —the number of contracts outstanding— was increasing incredibly as well. We haven´t performed any analysis, but this suggests to us that the clear- inghouse mechanism, the delivery, the whole structure had enor- mous value to market participants during an especially turbulent time. That is when our markets got their biggest boost in terms of in- creased liquidity.

Firms found (and again this is anecdotal) that they could become very comfortable with the idea that they could realize their gains on a daily basis, that the money would be there, and that the exchange clearinghouse was there to guarantee performance. So they used the contracts more often even though we effectively doubled our mar- gins. People talk about futures and options being highly leveraged transactions. This is true, but not always. When crude oil prices went down to $10 and less in early April 1986, we had $4,000 up just to trade what is known as non-spot contracts, which trade with price limits. If you were delivering or you were trading what is known as a spot contract (that is, the contract is ready to expire) and putting up margins of $6,000 or $7,000, you are talking about 60 or 70 percent of the face value of the contract.

Alternatives exist, including forwards and off-exchange instruments; but these markets have neither the financial soundness, trading con- trols, nor the liquidity of NYMEX. This limits their overall utility. How- ever, products such as swaps, OTC options and trigger pricing con- tinue to emerge; and, like the world growth in futures markets, their development indicates demand for risk management and an increas- ing level of sophistication within the energy industry.

INTEGRATION OF INDUSTRY

Certainly a fundamental source of NYMEX success has been its wil- lingness to address the needs of its commercial participants. NYMEX 90 Session II

has a well-earned reputation for working in partnership with the oil industry. And few would argue that we have not successfully inte- grated futures and oil. In cooperation with industry participants, NYMEX develops contracts which meet the hedging requirements of an energy industry increasingly exposed to price risk, an industry where trading skills and sophistication also continue to evolve and expand. These services provide the industry with risk-management tools that enhance the effectiveness of sales and purchase transac- tions, inventory management, and trading operations.

Historically, commercial interests have played a major role in our en- ergy markets. There are three ways to measure industry participation at NYMEX. The first is the actual trading volume. In 1988 about 60 percent of trading volume at NYMEX was accounted for by com- mercial energy participants. That is the equivalent of about 20 billion barrels of oil. The second yardstick is open interest, or the number of outstanding contracts or performance commitments in our market. About two thirds of our open interest is held by the energy industry, currently about 400 million barrels at any given time. Finally, partici- pation can be measured by capital at risk. Bob Levin, NYMEX Direc- tor of Research, estimates that in 1988 at least 6 to 7 billion dollars was put at risk on NYMEX, with 5 to 6 billion coming from commer- cials. Keep in mind that the whole process is a zero sum process, where collective gains equal collective losses.

One of the ways in which NYMEX assures that its efforts comply with industry objectives is through the existence of industry advisory panels. Unique to the futures industry, these standing committees —for crude, products, options, and new products— are comprised primarily of industry members.

The crude oil advisory panel made several key revision in our crude contract with respect to the manner and type of deliverable crudes. Committee recommendations developed during the summer of 1989 were adopted in August by the NYMEX Board of Directors and are pending US federal approval, which we expect shortly. We believe this illustrates the strong degree of collaboration between our Exchange «The Role of Futures in a Global Energy Market» 91

and the industry and shows how the committee facilitates the bal- ancing of specific commercial needs with a contract designed for general international financial use.

The committee structure will be invaluable as NYMEX continues de- velopment of a major new crude contract. The specifics —whether the contract will be Pacific or Atlantic Basin, cash or physical delivery, seet or sour— have yet to be determined, but the Board of Directors is fully committed to development of this contract. The industry´s in- put is crucial, and we believe by this time next year we will be well along in the process of making it available.

In the highly competitive, highly dynamic energy industry, new products and changes in existing products are meaningless, espe- cially to firms outside the United States, without access to NYMEX markets. Here too, NYMEX is working with the industry to enhance access.

GLOBALIZATION

The question facing the Exchange is how to best export NYMEX liq- uidity, transparency and integrity outside of normal business hours to our international participants, who, in growing numbers, are de- manding it. There are three possible options that would facilitate en- hanced access. NYMEX could extend trading hours, it could enter into partnerships with other exchanges overseas, or it could develop an electronic trading system. Presently we are aggressively pursuing the third option, electronic trading.

Why tis option? By offering computer-assisted order execution be- yond traditional open-outcry hours, NYMEX will be making signifi- cant advances in meeting the increased international demand for ac- cess to our markets. Electronic trading systems have become fundamental to the strategic plans of most of the world´s largest fu- tures and options exchanges because of their value in facilitating ex- pansion of liquidity across time zones. 92 Session II

Earlier this year, NYMEX had pursued electronic trading through ne- gotiations to join the GLOBEX system, which is being developed by the Chicago Mercantile Exchange and Reuters. Those negotiations were suspended by the CME in May, however.

Believing that electronic trading represents a viable mechanism for exporting NYMEX contracts into markets where energy risk-manage- ment is likely to grow, the Exchange began to develop its own pro- prietary electronic system. NYMEX recently began a pilot program in which NYMEX members will test the automated trading system. Feedback from members using test trading machines will provide valuable insights for the ultimate design configuration of a NYMEX system, a design that is customized for NYMEX energy products and trading methods. The system being tested is the ATS/2, developed by the International Commodities Clearing House (ICCH). ICCH and its subsidiaries provide services for futures and options markets in London, Paris, Hong Kong, Australia, New Zealand, and Ireland.

BASIS RISK

Before closing, I want to stress the importance of one aspect of fu- tures trading. In today´s increasingly competitive markets, one of the critical components of any hedging strategy employing futures or options is basis risk. To the extent that an exposure can be hedged, the performance of the hedge will depend on the basis, that is, the difference between the futures price and the respective cash-market price of the commodity being hedged.

If we define hedging as the assumption of a futures or options risk opposite a cash-market risk, then the performance of the hedge de- pends on gains in the one position offsetting losses in the other. A major airline that buys NYMEX heating oil futures to protect against a rise in the price of jet fuel, for example, is subject to a risk that the prices do not move exactly together over time. In addition, the com- modity being hedged is not necessarily the same commodity speci- fied in the futures contract, and the delivery may differ, as well. To «The Role of Futures in a Global Energy Market» 93

the extent that they do not, hedge results can benefit or suffer. Like- wise, a European firm hedging Brent crude purchases with NYMEX light sweet crude must be sensitive to, and prepare for, shifts in the relationship between Brent and NYMEX crude. While world crude prices tend to move ever more closely together as a result of global- ization and integration of markets, basis risk remains.

The reason we continue to witness a proliferation of small regional trading markets is in some measure related to a desire to have a risk management tool that precisely fits cash market practices of the re- gion. This is nothing more than a desire to eliminate basis risk. But smaller markets mean fewer participants making fewer trades; in- evitably, liquidity suffers. Ultimately, we may discover that basis and no liquidity is significantly less beneficial than managing basis on ex- tremely liquid markets.

As an interesting comparison, in the United States the mortgage- backed obligations market is immense and dwarfs the bond market. The bond market, however, has the most liquid futures market in the world, and very often investment banks that take on exposure by underwriting a mortgage obligation issue will hedge that exposure with the Treasury bond market, even though the Treasuries and the mortgage-backed obligations tend to diverge at random, sometimes radically so. But there is a much more liquid market in the Treasury bond futures and options than in anything comparable for risk man- agement in the mortgage-backed market, so people continue to use and find utility in it.

The vast number of NYMEX participants and the volume of activity done on NYMEX far exceed those of any other market, providing a virtual guarantee that there will be a buyer or a seller with whom to make a deal. This superior liquidity produces tangible benefits. Bid and offer spreads tend to be lower on NYMEX. The fractions add sig- nificantly to reducing the cost of risk management vis-a-vis other, less efficient markets. This is a pronounced advantage; it can be more economical for a European firm to hedge transactions on NYMEX that on a local market. 94 Session II

In order to fully define basis exposure, participants have come to understand the importance of careful study of underlying fundamen- tals. In NYMEX hedging, successful participation depends on under- standing how our delivery mechanism works and on identifying those seasonal factors that might affect the basis. It also requires an appreciation of the impact of regional factors, such as the relation- ship between northern Europe fundamentals and those of the US Gulf Coast. And it requires an understanding of the US physical market in general. Energy futures and the oil industry continue to be joined together as a very realistic solution to numerous economic, fi- nancial, diverse market and technological developments that directly affect our industries. Cooperation or not, stability or not, the 1990s will continue to see worldwide competitive pressures and a concur- rent demand for accessible, efficient risk management tools.

ROBERT RYAN

Robert Ryan is Manager of Risk Analysis and Research at the New York Mer- cantile Exchange. He was the principal designer of the Exchange´s energy options and risk-assessment models. He graduated from Pennsylvania State University. 95

«A PRACTITIONER´S VIEW OF THE OIL AND MONEY MARKETS»

ERNST WEIL

I would like to thank the organizers of this conference for inviting me. After I received the program and booklet about last year´s meet- ing, I thought I had better get out my Harvard tie and try to remem- ber how it was, and try to be a bit academic. But I decided there would be enough of that: I would let the others do the academic work and I would just speak as I am —a businessman who tries to use all the knowledge that has been provided by the Merc and oth- ers. It is also very healthy to use the grey cells in the more structured manner than a trading company perhaps forces one to do.

I suppose that I have been invited in order to present a practitioner´s view of the oil and money markets —not the oil market per se but the relationship between the oil and money markets in terms of the pricing of crude oil and oil products. Being very outspoken, I shall also present our reasons why this relationship must exist, and ways that it could and perhaps already is being used. I will refer primarily to the long terms swaps that are not handled by the Merc, which could no yet be studied —at least on the oil side— by the academics because they are so very new. 96 Session II

Money markets and their basic instruments have existed for a much longer time than the industrial use of oil. Money, as cash or as credit, is the absolutely necessary raw material for all economic endeavors, and it is not surprising that in our capitalist economic system it is used by all segments of the economy, from production to marketing. People have always money instruments. The started with bronze and silver coins, then went to letters of credit, loans, bonds, equity shares, etc. Now we have futures, options, and permutations of many of these things.

Why, then, are people in the industry surprised that in today´s world, where distances are of absolutely no importance, the price of oil, whether it is produced in the desert or the middle of the ocean, should become closely tied to a trading exchange in New York? This is not surprising; it is absolutely normal. It took a very long time to commoditize oil, but I have found that our industry, which is the most important in the world, seems to prefer primitive trial and error methods for finding the right level of production and the right way of pricing its products. I am convinced that the discovery of the money markets in the larger sense is one of the better results of the pragmatic approach.

All here know the history of the oil market intimately, but let me just mention a few of the events of the last thirty years that have led to today´s discussion on the marriage of the oil and money markets. Some shorthand phrases will identify these events quickly: the na- tionalization of oil production, the founding of OPEC, the Suez war, the closing of the Suez Canal, the coming of the very large crude car- riers (VLCC´s), the Club or Rome report, the crisis of 1973, the Iran- ian crisis and revolution of 1979, the consequences of the overpric- ing of oil after that, the logical evolution of alternate energy sources and energy conservation, the development of large OPEC and non- OPEC fields, the glut of 1986, and today —what has really brought us to this table— the quotational pricing of crude oil in lieu of fixed pricing. All of us here in this room are active in one or another aspect of the oil industry. I contend that if you analyze your thoughts about the future of the oil market, you will probably find that they have «A Practitioner´s View of the Oil and Money Markets» 97

changed from worry about the availability of oil to worry about the price movement of crude oil. That is logical. Any industry, including ours, must have a stable environment in order to develop. I. know that everyone loves this word «stability», but stability of all factors influencing things at any one time is practically impossible. There is the stability of supply, political stability, currency stability, price sta- bility, market stability, and many others. Each of them plays an im- portant role, but which one is the most important for the industry? Which one is the cornestone? At this moment it is my contention that in order to prepare for the future, as in the past, our industry pri- marily needs financial stability.

As was mentioned in the first session, any investment in the oil in- dustry today is a macro investment. These investments from hun- dreds of millions of dollar to billions of dollars, whether it is range for production or for refinery. The lead time for such an investment is years, and the payback time is even longer. If one believes in re- alpolitik, one concludes that if oil is needed and oil exists, it will come to the market under any circumstances —if not through price mecha- nism as in 1979, then through political or military force. So I don´t worry about availiability.

If one accepts this premise, long-or even medium-term planning must be based primarily on the economic parameters of the marco investment, and therefore on a fixed price of either the feedstock or the product. Here we have arrived at the money market. Mr. Nazer has already been quoted here; I will refer to him, too. At the Oil and Money Conference in London, Mr. Nazer slapped the Wall Street re- finers, and specifically my company, on the wrist, holding us respon- sible for the volatility of the oil price. To be frank, I understand his point of view, since OPEC nations had their most successful period during the time of fixed oil pricing. Even then, in a most responsible manner, they kept their contract prices below the volatile spot price. But in the end, the fixed pricing of crude oil did not work. I think no one believes today that even during some great crisis (which can happen at any time) anything but «quotational» pricing is realistic. And here once more we have the money market. 98 Session II

Let me say a few words about how these markets are being used and how they could be used. I will not go into the technical details, be- cause that has been done. I believe that it can be proven that the ex- istence of these markets is a blessing for the oil world and its not by itself the cause of volatility. These financial types of instruments can be used as insurance and, therefore, make possible investments which need guarantedd cash flows in order to assure financing. In other words, the combination of oil and money markets, wisely ap- plied, creates stability in the further development of the industry even though it does absolutely nothing for the daily volatility of the price. Strangely enough, no one minds if the producers, users or traders hedge a cargo of oil during the time it takes to move it to the refinery, or hedge products until they arrive at the place of con- sumption. This seems to be socially acceptable. Why, then, should it not make just as much sense to tie down the price of crude oil for the way-out future when investing a large amount of capital in a project that makes economic sense only at a defined, today-related price of either oil or products in order to assure the cash flow? Since we know that the spot price of oil will fluctutate based on market forces, we must, in order to guarantee cash flows, accept oil price swaps very similar to interest rate or currency swaps, which today are a matter of course. In my view this certainly creates economic stability despite the short-term price volatility.

We can cite many examples, either theoretical or from our accounts, of short-term or long-term price swaps that are acceptable —that must be acceptable to everyone since they make economic and po- litical sense. Moreover, in this free world there is no way to stop speculators from trying to use oil-based instruments as their newest game. It is an «in thing» to do; it is the «flavor or the month».

Nevertheless, I am convinced that an ever-larger percentage of the contracts traded on the Merc or the International Petroleum Ex- change (IPE) are still used to hedge physical cargoes either directly or in roundabout ways. However, oil price swaps based on investments or cash flow needs are going to increase tremendously. I question whether the Merc is ready for this either in size or with its regulations. «A Practitioner´s View of the Oil and Money Markets» 99

I think the Brent market is ready for it, although it is not large enough. This, however, is more easily acceptable because how does one ask for margins on something six years out where there are no quotations in cash? (Here we are getting technical). This is a prob- lem, but it will be solved. It happens in the currency and interest rate swaps. For us, the company taking the risk side, this is a business like any other. It is based on option theory; it is based on historical corre- lations; it is based on mathematical formulae. I hope we have the right people to figure all these things out, because that is what it is all based on.

In Figure 1 you will find New York crude oil and bond and stock monthly volatility. This is to show you how urgently the oil needs have to tie in with the financial instruments; for as you can see, the volatility of the oil price is much greater than the volatility of the fi- nancial instruments usually used to be, whether bonds or stocks (if you forget the 1987 crash).

I hope these thoughts, together with the more structured presenta- tions of my colleagues, have given you enough inspiration to keep our charming moderator busy for the remainder of the session.

ERNST WEIL

Ernst Weil is Chairman and Chief Executive Officer of Phibro Energy, AG, in Zug, Switzerland. He is also a member of the Board of Directors of Salomon, Inc.

Mr. Weil, born in 1929 in Zurich, Switzerland, studied economics at the Uni- versity of Zurich and received an AMP Certificate from the Harvard Business School. He joined Philipp Brothers as a trader and manager in 1972. Upon the merger of Philipp Brothers with Salomon Brothers in 1982, he became head of non-American oil business, Phibro Energy, Inc 100 Session II

Figure 1 Nymex Crude Oil & BondsFigure & Stocks 1 Monthly Volatility Nymex Crude Oil &(Jan Bonds 85 to & Apr Stocks 89) Monthly Volatility (Jan 85 to Apr 89)

NYMEX CRUDE OIL MONTHLY VOLATILITY BOND MONTHLY VOLATILITY STOCK MONTHLY VOLATILITY 120 120

100 100

80 80

60 60 PERCENT PERCENT

40 40

20 20

0 0 1985 1986 1987 1988 MEAN: 34.12 MAX: 105.68 MIN: 9.06 STO: 20.92 LAST: 44.97 MEAN: 12.93 MAC: 24.87 MIN: 6.96 STO: 4.51 LAST: 8.60 MEAN: 17.02 MAX: 85.50 MIN: 8.54 STO: 11.98 LAST: 9.60

PHIBRO ENERGY, INC. 101

SESSION III «ENERGY IN WESTERN EUROPE IN THE RUN-UP TO 1992»

INTRODUCTORY REMARKS

JOSÉ SIERRA

This session is devoted to Energy in Western Europe in the run-up to 1992. Obviously, this subject is a vast and complex one. It is also an area where much definition is still needed and many uncertainties ex- ist. Energy in Western Europe in general, and in the European Com- munity in particular, is not only subject to the normal challenges pre- sent in the energy world, as we were discussing yesterday, but now the decision makers in government and industry in the European Community have to face the new challenges that will arise from the completion of the European Community single market in 1992.

Before yielding the floor to our speakers, I would like to mention a few key points to keep in mind while addressing the theme of our sessions. First, energy issues cannot be ignored in the internal Euro- pean market, because today more than ever energy is a key factor for all economic activity. Second, the internal market must not be supported as a sort of religious dogma. It must be not a goal in itself, but rather one of the means to try to achieve a less expansive and more secure foundation for the European energy economy. The third point is that there is room for improvement in the energy in- dustry in the European Community: there are still irrationalities in the 102 Session III

production, transport, distribution and consumption of energy. (Each of these irrationalities is, of course, more relevant for some energy sources than for others.)

Finally it must be recognized that the implementation of an internal energy market among the European Community of twelve nations is a very complex and delicate exercise, for at least three reasons. For one, the specifics of energy make it difficult to apply normal rules or codes of competition in practice. A good example or this, which we will have an opportunity to discuss in this session, are the difficulties that the Commission, the Council of Ministers of the Community, and industry face in attempting to reach agreement on how to in- crease exchanges of electricity or natural gas; these issues involve such difficult matters as third party access and common carrier status. A second reason for complexity stems from the fact that govern- ments tend to approach some key energy issues, such as taxation of energy products, environmental concerns, and energy infrastruc- tures, as horizontal policies in the internal market, not as energy pol- icy issues. Horizontal policies on taxation, environment or regional development are formulated without it being possible to guarantee that the effects of those policies on energy policy are duly taken into account. The third reason lies in the concept of security of supply and self sufficiency, the question being whether this issue should be tack- led at a national level or a European level.

All this leads me to ask whether it is possible to have an internal energy market without a common European energy policy. This question the Commission and the Council of Ministers of the European Commu- nity will have to resolve before 1992. I have posed one question; let me ask some others. Should energy conservation be encouraged without high energy prices? How will the balance, yet to be reached, between energy and evironment affect the future roles of fossil fuels and nuclear energy? What is the effective role to be played by tech- nology in this context? Will we be able to develop a neutral taxation policy for energy products in such a way that neutrality will be inter- fered with only for energy policy purposes, as encouraging some uses and discouraging others? Finally, will the ongoing developments Introductory Remarks 103

in Eastern Europe solw down the progress towards a European inter- nal market and social and economic cohesion in Europe, or will it ac- celerate the consolidation of the European Community?

Fortunately, as moderator my role is not to try to answer all these questions but simply to keep the dialogue moving. I am convinced our speakers and the subsequent discussion will supply much infor- mation and many helpful suggestions.

JOSÉ SIERRA

José Sierra was born on April 4th, 1938 in Badajoz (Spain).

Since September 1st, 1989 is Director for Coal and Hydrocarbons at the Ge- neral Direction for Energy of the European Communities in Brussels.

Before, he worked as Vice President and Executive Officer of the Empresa Nacional Adaro de Investigaciones Mineras (1980-1983) and as Executive President of Carboex (1980-1986).

José Sierra is Mining Engineer and Mining Doctor from the Madrid School of Mines. He has given many conferences and published numerous articles. 105

«THE WEST EUROPEAN NATURAL GAS MARKET IN THE PERSPECTIVE OF INTEGRATION AND ELECTRICITY DEMAND: NEW CHALLENGES TO ENERGY POLICY»

ØYSTEIN NORENG

I would like to thank you for the invitation to come here. It is a plea- sure to be back in Spain again. In have been to Spain several times in the last few years, and I must say that I have lost part of my heart here. That is why I have to come back and find it.

My topic is natural gas, but I will also stress the issues of European integration and electricity. In my view it is impossible to look at the natural gas market without looking also at the electricity sector, be- cause they are related and have something very important in com- mon: the two fuels are expensive to transport and difficult to store. It is even more difficult to store a kilowatt hour of electricity than to store a cubic meter of natural gas. The rigidities of transportation mean that both are highly capital intensive, hence institutional issues become important.

Author’s note: This paper was written before the collapse of the Berlin Wall and the subsequent breakdown of the Russian-dominated East European system. Many of these issues which relate to energy in Western Europe will assume even greater importance as Europe begins to assume new political and economic configurations. 106 Session III

Western Europe is going to confront a number of very interesting challenges over the next few years, in the 1990s. First, we will get a single market for goods and services. According to all we know from economic theory, this should spur economic growth. I think most studies have underestimated the potential for the growth this devel- opment will bring. We have a market opening up to more than 300 million —probably closer to 400 million— people.

As a Norwegian traveling in Europe, I see the gradual harmonization of consumer tastes. Spain is no longer so very different from Norway. This offers a truly fantastic potential for specialization and conse- quent productivity gains. I think the stage is set for some kind of Eu- ropean economic miracle.

The dramatic events in East Germany and most of Eastern Europe that we are witnessing are, in my view, the most important things that have happened to the world since 1945. Western Europe as a concept is defined against the concept of Eastern Europe. But Eastern Europe is no longer there; it cannot be defined any more. Conse- quently, when we cannot define Eastern Europe, we can no longer define Western Europe in the traditional sense.

For example, there is the big question of how to make room for Ger- many in the House of Europe that Mr. Gorbachev has been talking about. This could either halt the whole process or accelerate it. I think we are confronting a situation where we have an historical chance of unifying Europe, and one question that emerges is what will happen to energy demand in that part of the world? I wrote this presentation before the Berlin Wall came down, a development which I regret I did not foresee. We don´t know what the effect will be on the insti- tutional setup of Western Europe. In my view the German issue is one of the most important obstacles to making a common market in energy. I think it is going to be difficult to resolve.

The issues are as much institutional and legal as they are technical and economic, because Western Europe has today a large part of the power generation capacity that has to be used. As part of the projected «The West European Natural Gas Market» 107

economic growth, we are probably going to experience a very rapid increase in electricity demand, especially in the countries of southern Europe where growth is going to be the highest. You know that this is the case in Spain, and I see it in Italy as well. Complicating this in- crease in demand is the environmental issue which means that it is uncertain whether there will be much more power generation with coal.

If you compare Western Europe with the other major OECD regions of North America and Japan, the striking thing is that natural gas has a low degree of penetration —that is, a low market share— in the Western European energy market despite a high population density and a strong concentration of industry, factors that usually encour- age the distribution and use of natural gas. The problem is partly a result of the subsidization of coal, and partly the fact that Western Europe is not well endowed with natural gas resources. Thus future expansion in the use of natural gas will have to depend heavily on imports, to a large extent from the Soviet Union and Algeria, and even from Norway (which you may not view as constituting an im- port).

My point is that the electricity problem offers a new opportunity for natural gas. The necessary conditions are competitive prices and flexi- ble contracts. In my view there is a looming crisis for oil. We have seen that the relationship between economic growth and energy de- mand is cyclical. For some years after 1979 and the second price shock, we thought that the relationship had been decoupled, that is, we could make economic progress while making large energy savings. Now we have seen, over the past eighteen months, that we are coming back to the historical trend, but from a different level. To some extent, at least, the decline in energy intensity in the OECD countries masked a relocation of heavy, energy-intensive industries to developing countries, regions for which we have poorer statistics on energy use.

Over the past few years we have had remarkable technical progress in using natural gas for power generation. We can now have good 108 Session III

thermal efficiency in smaller plants, at least in those with combined cycle generation. In cogeneration the overall efficiency can be 70 to 80 percent if steam is included and can be sold. These turbines are not capital intensive; their capital cost is about half that of an equiv- alent coal-fired turbine. Operating costs are also lower, and the lead times are very much shorter. I think natural gas in this use could be- come very profitable.

The major obstacle is the organization of the electric and natural gas industries. In most of Europe, much more than in the United States, electricity has been seen as a public service best offered by nation- ally-owned companies or by companies under very strict govern- mental control. Historically, we have hand four major integrated mo- nopolies in Western Europe: ENEL in Italy, Gaz de France and Electricité de France in France, and the Central Electricity Generating Board in Britain. The important thing to note is that the choice of in- stitutions has determined the choice of generation and supply pat- terns, something we tend to forget. Large nationalized enterprises that can get capital over the budget have a propensity to choose capital-intensive solutions, which are also consonant with capital at low interest rates, long planning horizons and large markets. These are the kind of enterprises that can plan for nuclear power.

If we privatize or decentralize nuclear power —if, for example, we have private or local companies that have to raise capital in the mar- ket— nuclear power will be a much less attractive option, for the risks are very high and the costs are uncertain. There is an unknown risk in nuclear plant operations, and there is also an external risk: an- other major nuclear plant accident anywhere in the world could lead to strong public pressure for closure —in the extreme case, closure even of existing plants. In contrast, with non-nuclear generation a private or local company would have more flexibility, and it could choose natural gas or oil turbines.

Currently, Western Europe enjoys a large surplus capacity in power generation that should be able to cope with demand, even at peak load, for several years. There is an inventory of nuclear, hydro and «The West European Natural Gas Market» 109

thermal power stations that are underutilized or idle. Much of the surplus capacity is in capital-intensive plant that is best suited for continuous operation to meet the base load. Today this capacity is also used for peak load purposes, with discontinuous operation. There is relatively little specific peak capacity installed. In most of the indi- vidual countries, presently installed power generation capacity would be sufficient to cope with rising electricity demand, but by the late 1990s reserve margins could be uncomfortably small in several coun- tries. As demand rises the installed base capacity will be increasingly used for base load and thus will be less available for peak load pur- poses. In some countries, especially those with high demand growth rates, there is a risk of insufficient peak capacity in the late 1990s.

This suggests that electricity supplies could become a serious prob- lem for energy policy in Western Europe in the late 1990s. Here, as elsewhere in the industrial countries, there is a propensity for con- sumers to shift an increasing share of their final energy demand to electricity, with the result that electricity demand is likely to in- crease much more quickly than overall energy demand. If Western Europe enters a period of sustained economic growth in the 1990s, with economic integration, larger markets, enhanced specialization, and productivity gains, demand could increase by 35 percent or more between 1986 and 2000. The prospect of stronger growth in the service sector than in manufacturing further enhances the changes of strong growth in electricity demand.

The risk of insufficient generating capacity is much less for Western Europe as a whole, however, than for some individual countries, a condition which raises the issue of electricity trade. Today the Euro- pean market is fragmented, with obstacles to trade existing between countries and sometimes even within countries. A more efficient use of the installed generation capacity, whether nuclear, hydro or ther- mal, will require the lifting at least some of those obstacles, if not the introduction of free trade in electricity. It would require, for instance, that French nuclear capacity be used for base load throughout West- ern Europe and the French importation of electricity for its own peak needs. I think this is gradually coming. 110 Session III

The opportunities for trading electricity will determine the investment requirements of the electricity sector. To the extent that electricity can be traded freely within and among countries, there will be little need for expanding base load capacity in Western Europe until the turn of the century. This would mean that there would not be a good case, from the overall West European perspective, for investing in capital-intensive nuclear power or large-scale, coal-fired thermal plants. In contrast, there would be a case for investing in some addi- tional flexible peak capacity with less capital intensity and for the en- hanced use of existing hydro capacity, some of which is in smaller plants that need better grid connections or improved water storage facilities. The future power generation patterns of Western Europe will be subject to economic constraints and eventually to environ- mental restrictions. Currently, nuclear power and coal each represent about onethird of the electricity generated, with the balance coming from hydro, oil and natural gas. The conventional outlook is that coal-based thermal power will take a large share of the incremental generation needs, with some expansion of nuclear and hydro power as well. Such a development requires, however, that no restrictions be put on the use of fuels by the electricity industry, i. e., that envi- ronmental concerns do not translate into policies to curb emissions. A reduced role for coal in power generation, through emission taxes or direct restrictions, could open new markets for natural gas as a rela- tively clean fuel and one that is attractive for power generation be- cause of the high thermal efficiency in gas turbines with compara- tively low capital costs. Even more important is that investment in coal-based thermal power plants and in coal-handling infrastructure, such as ports, in now far behind the schedule required for coal to oc- cupy the role in power generation that is foreseen by conventional wisdom. This underlines the risk of tight electricity supplies in West- ern Europe in the late 1990s and gives natural gas a fresh opportu- nity.

The alternative to meeting Western Europe´s electricity requirements in 2000 without using any more natural gas than in 1986 is to burn more fuel oil in power plants. This will be the most realistic option if electricity demand experiences high growth rates. There is, however, «The West European Natural Gas Market» 111

a considerable price risk involved. If power generation on the basis of coal is stabilized or even reduced from 1986 levels, the electricity sec- tor could become a major market for natural gas.

The problem is that the time patterns of electricity demand fluctua- tion tend to coincide with those of natural gas demand. Hence the eventual incremental demand for natural gas by the electricity sector will take place when natural gas demand from other segments of the market is at its highest. Consequently, an enhanced use of natural gas in the electricity sector will require either extensive storage facil- ities or additional pipeline capacity both of which are costly and will be fully utilized for only part of the time. In the latter case, flexible contracts will also be necessary. To some extent the problem can be overcome by using more natural gas for base electricity generation as natural gas is used in peak power generation, so that the relative variations in volume requirements will diminish. The incremental use of electrictiy in the summer season for air conditioning purposes in southern Europe will also facilitate the use of natural gas in power generation in these countries. In this perspective, natural gas has the potential of becoming a major fuel in the West European electricity industry.

The present organization of the electricity and natural gas industries of Western Europe varies significantly between countries, but com- mon circumstances are market imperfections, obstacles to competi- tion, intermediary monopolies and captive markets for local high- cost energy producers. If the present structure is reatined, even with some eventual minor modifications, there is a strong risk that rising electricity demand will lead to much higher prices for consumers and to higher monopoly profits. And to the extent that the electricity in- dustry will choose natural gas as an input fuel, some of the monop- oly profit is likely to be transferred to the natural gas industry.

In a more competitive regime where there are fewer obstacles to competition and public regulation of the transmission monopolies, the various segments of power generation capacity already installed would be able to find more optimal outlets than is true today. The 112 Session III

results would be less need to invest in new plant and lower prices for consumers. With a more competitive regime, natural gas would also be an economically more attractive fuel for the electricity industry. There are thus strong arguments for deregulating and privatizing electricity and natural gas trades in Western Europe. The counter-ar- guments essentially has to do with supply diversification. Private electricity companies, financing new investment through the capital markets, generally operate with a higher discount rate than do pub- licity owned electricity companies that finance their investment through the public budgets. Hence private investors could have a strong preference for gas-thermal plants with low capital costs and short lead times, whereas the public sector could view capital-inten- sive nuclear power with long lead times more favorably. In a dereg- ulated natural gas industry, incremental demand would be taken to a large extent by the most price-elastic supplier. By contrast, within the present order, with intermediary or final monopolies acting as monopsonies (single buyers) in relation to foreign suppliers, there are better possibilities of diversifying deliveries and avoiding an excessive dependence upon one single supplier.

In this scenario, deregulation and eventual privatization of the West European electricity and natural gas industries could favor the use of natural gas in power generation. At the same time it would give the Soviet Union a dominant share of the West European natural gas market, at least as long as the present organization of the Soviet economy gives Soviet natural gas and edge over competitors in export markets. This could become a serious issue if environmental restrictions lead to a large-scale replacement of coal by natural gas in electricity generation. By contrast, maintaining the present order could mean a less competitive position for natural gas in power gen- eration, but also a more diversified supply pattern for natural gas with comparatively larger market shares for Algeria and Norway.

The economic integration of the European community and the es- tablishment of an internal market are likely to present serious issues of energy policy. The present regimes for trading electricity and natural gas are hardly compatible with the principies of free trade and equal «The West European Natural Gas Market» 113

opportunities for competition. On the other hand, complete deregu- lation of the electricity and natural gas trades could lead to consider- able supply risks, especially since Western Europe is becoming in- creasingly dependent upon natural gas imports as domestic reserves are depleted. It could, however, be argued that with the inclusion of Norway and the large Norwegian natural gas reserves, the supply risk of deregulating natural gas trade would diminish somewhat. This would also depend upon eventual changes by Norway in the organi- zation of natural gas sales and measures to favor West European nat- ural gas over foreign natural gas.

To sum up, the discussion of the future regime for electricity and nat- ural gas trades in Western Europe should focus not only on the short- term price effects for consumers, but also on long-term investment preferences and supply patterns. Finally, environmental issues and the issue of the organization of the energy industry should be seen as a complex set of problems. Any environmentally motivated restrictions on the use of fuels in power generation will have effects on the mar- kets for the various fuels, but these effects will differ according to the structure of the industry concerned. Correspondingly, any proposal for instituional change affecting electricity and natural gas trades should also consider the effects of eventual fuel use restrictions, motivated by environmental concerns. For Western Europe the dilemma is that nei- ther the present order of highly imperfect markets nor complete deregulation seems to be without serious risks and inconveniences.

The answer may be an intermediary order, with a mix of competition and monopoly, but with a stronger measure of competition than is the case today. Possible compromise outcomes could be to retain the present company structure, but with more price transparency and some common carriage obligations; or to let local or regional distrib- utors of electricity and natural gas conjointly own the transmission companies. From this perspective, the final distributors who are in di- rect touch with consumers would control the transmission system and the transportation costs, whereas in the present regime the local distributors, are, to a large extent, the hostages of powerful and profitable transportation monopolies. 114 Session III

ØYSTEIN NORENG

Ø. Noreng was born on October, 1st, 1942. He is Doctor in Political Science (1972).

Mr. Oreng works as professor in the Norwegian School of Management at Sanvika. In the seventies he was in Statoil’s Department of Marketing as re- searcher and planning manager.

Between 1986 and 1987 he was Visting Research Fellow in the Energy and Environment Policy Center (Harvard Institute).

Among his books in English are Oil Politics in the 1980s, The Oil Industry and Government Strategy in the North Sea an Petroleum Economic Deve- lopment. 115

«ELECTRICITY IN EUROPE IN THE RUN-UP TO 1992»

LARRY RUFF

INTRODUCTION

I want to thank Bill Hogan and REPSOL for inviting me here today to substitute for Max Wilkinson. Max has been writing about the priva- tization of the UK electricity market and was recently promoted to be the editor of the Financial Times weekend edition; he may be one of the few people whose career has been advanced by being associated with electricity privatization in England.

Professor Noreng has already discussed the European aspects of elec- tricity so I will not deal with that directly. As we all know, the EEC is pushing very hard for trade liberalization in general, and liberalization of energy and electricity trade in particular. Electricity will probably be one of the last of the areas in which we see real trade liberaliza- tion in Europe: there are strong political factors running against it; the national mopolies naturally protect their position; national coal and nuclear industries demand protection; and the regional fiefdoms in the electricity business will not easily give up their positions. So there are strong conservative forces resisting liberalization of trade in electricity. 116 Session III

However, there also strong forces pushing in the opposite direction. The general economic trends towards liberalization, new technology in generation, metering and system control, new market concepts and information systems, and the examples of liberalization in the US and UK are changing things very fast. Until a few years ago the en- gineers could make a good case that it was impossible to imagine an electricity system working without them in control of everything. But that is changing rapidly. So I would suggest: do not be electricity lib- eralization probably should come and perhaps will come sooner than most people think.

My focus today will be on what has been happening in the US and in Britain over the last few years. Of particular interest is the fact that the US and the UK, with really quite different political systems, have both taken steps that are leading them on convergent paths to a more competitive, decentralized electricity sector. Different systems and political organizations over a wide range are consistent with lib- eralization of the electricity trade.

COMPETITIVE GENERATION IN THE UNITED STATES

Let me deal first with the United States, beginning with some back- ground. In the US the electricity business has hundred of privately owned utilities, most of them vertically integrated with regional fran- chises, and not a lost of trade among them. There are a number of power pools, some of them as large as the entire system in England and Wales —some 50 gigawatts or so— in which there is extensive trade, at least in short-term energy, but not a real competitive mar- ket in electricity, and in particular no real competition at the retail level; even most large customers cannot buy from anyone other than their local utility.

As a result of the oil problems in the 1970s the US electricity indus- try embarked on a large program of construction with a heavy nu- clear emphasis. As oil prices went up, regulated electricity prices did not go up as fast, and there was a shift of demand from oil and other «Electricity in Europe in the Run-up to 1992» 117

fuels into electricity. For a time, electricity demand continued to grow fast, so utilities made commitments to nuclear plants and started building them. Then, in the 1980s, the cost of the new investments rolled through into higher electricity prices just as the prices of com- peting fuels came down. Demand growth fell and utilities found themselves sitting on large excess capacity and escalating nuclear costs. They were in some difficulty.

One of the legislative responses to energy problems in the 1970s in the US was the Public Utility Regulatory Policies Act —PURPA. The main purpose of PURPA was to improve the utility regulatory process in the fifty states, but its most important effects by far resulted from a little-noticed provision requiring utilities to buy power from certain independent «qualifying facilities». Power from QFs defined as either cogenerators that use the discharged steam form some beneficial use or small plants using renewable resources, had to be bought at the utilities´ «avoided cost» —the cost they would otherwise incur if they did not buy from the QF.

The market responded to PURPA by offering thousands of megawatts of QF power. The prices offered by some utilities, usually under state regulatory pressure, were so attractive that a great excess supply of QF power was offered; QF developers were giving away steam, in some cases to what appeared to be phony uses, in order to qualify as QFs. This excess supply led to development of methods for rationing QF contracts, particularly through competitive bidding systems.

Eventually, the restrictive definition of QFs was seen to be counter- productive, and independent power producers (IPPs) were encourag- ed under more general definitions. The end result has been that most new generation in the United States is now being provided by IPPs. Utilities have largely gotten out of the generation business, at least in the short term, and are planning to buy most of their new generation from IPPS. Some utilities are even breaking themselves up, spinning off their traditional generation departments into IPP subsidiaries that sell power to other utilities, while at the same time planning to meet 118 Session III

most of the parent utility’s power needs through purchases from others.

The development of competitive generation has dramatically changed and probably improved utility planning concepts and methods. Utilities have improved their operations, change their way of thinking about what kinds of power plants to build, and looked more carefully at alternatives to new power plant contruction, such as refurbishing old plants; plants that were routinely retired after thirty-five or forty years of service are now being reconditioned to operate over a total lifetime of up to sixty years. The size of new plants has been reduced, and most of these are the new gas com- bined-cycle plants that Professor Noreng mentioned or smaller coal fired plants using fluidized bed technology. The trend towards sepa- rating generation from distribution has clearly had a major effect on the way utilities go about their business.

It is still uncertain how far the trend toward restructuring and trade liberalization will go in the US, with transmission access being a major issue. Most of the competition so far has been for the construction of generation within a utility’s service area, using only the buying util- ity’s transmission and distribution system. Clearly, if competition could be extended so that a utility in one area could be supplied by a generating plant in another area, it would open the market a good deal more. This is developing only slowly because the utilities are protecting themselves by restricting access to their transmission system. Nevertheless, it is developing as some utilities push hard for access to their neighbors´ transmission systems and others look at the possibility of using their own transmission system as a revenue-gen- erating asset.

PRIVATIZATION IN THE UNITED KINGDOM

Turning to the UK, the government there has attempted to leap-frog what is going on in the US and is going far beyond it in concept, starting from a very different background. In contrast to the hundreds «Electricity in Europe in the Run-up to 1992» 119

of independent private utilities in the United States, in Britain (that is, in England and Wales, which is all that is being discussed here) there is one nationalized utility, the Central Electricity Generating Board (CEGB). The CEGB owns virtually all the generation in the country and owns the national high tension grid. The twelve regional Area Boards that run the local distribution systems buy from the CEGB un- der a bulk supply tariff that covers whatever costs the CEGB decides to incur, passing the cost onto their customers. This situation is not all that much different from some other European countries or even from the US situation in the «good old days».

In early 1988, the Thatcher government published a white paper proposing an entirely different structure for this industry. The original plan was to break the CEGB up into some fifteen different compa- nies: two generating companies, one owning 70 percent of the gen- eration capacity, including all the nuclear plants, and the other own- ing 30 percent; twelve distribution companies (distcos) created from the Area Boards; and an independent National Grid Company (NGC) which will own and operate the national transmission grid.

Originally the distcos were to have no regional franchise, the notion being that any customers anywhere in the country would be free to buy from any supplier, including the two generators, the 12 distcos or independents brokers. More recently, the distcos have been granted a limited frachise to serve the smaller (below 1 MW) cus- tomers in their region, phased out over eight years. All one needs to get into the business of selling to customers is a license imposing cer- tain rules but expected to be available quite freely, so there will be a host of middlemen in a position to buy power and sell it to any cus- tomer. This retail competition is a dramatic innovation in electricity system operation and goes far beyond anything tried or contem- plated anywhere, including the US.

Some of the developments in the UK over the past year are signifi- cant for the future of electricity trade liberalization elsewhere. One is that announcement of this plan stimulated huge interest on the part of IPPs in building power plants in Britain. QF developers in the US, 120 Session III

finding their market closing down there, got on the first plane to London with blueprints in their pockets to build gas combined-cycle plants; they have been spending the last year trying to get folks to sign the kind of take-or-pay contracts that have been so profitable in the US. This inmediate interest shows that any country that makes it known that an independent can get in and sell electricity will find no shortage of people who are very good at financing, building, and op- erating power plants; qualified entrepreneurs will show up at the door ready to do business if the price is right.

The lessons to be learned from the UK on process issues are less pos- itive. The process has gone quite badly in many ways, largely be- cause the government has not managed it very well. Although they had an interesting and basically correct concept as to how this com- petitive industry might work, there is a big gap between saying in theory that something might work and actually working out all the necessary institutional, technical and contractual details. The industry itself has been a nationalized industry, and has suddenly been thrust into the position of having to contract for electricity supplies, for nuclear plants, for transmission and for other system services. Not only is there little experience in this area anywhere in the world, but there is very little commercial experience or capability in the UK indus- try. So it has not gone very smoothly.

Still, his process had led to a gradual recognition of the basic eco- nomics of the electricity sector in Britain. One of the things that has gradually been recognized is that the CEGB has over the years con- structed a systems that is grossly overbuilt in base-load plant. The CEGB system has big coal plants on the margin all the time, with peakers seldom running; they have far too much plant that is too ex- pensive and a system that runs uneconomically.

The second thing that has surprised the industry is the extent to which competition is going to be real in the reorganized system. When the government said they wanted competition, everyone thought of competition at the generation level, where it was generally recognized that it would take years to build enough new generation «Electricity in Europe in the Run-up to 1992» 121

plants to establish effective competition. What nobody realized was that competition could develop at the retail level inmediately follow- ing privatization. With the efficient spot market described below, and fourteen players with excess capacity, prices would fall to marginal running costs within weeks. Since the original plan was that the dist- cos would contract long term for all the capacity at prices reflecting accounting costs or historic costs, the distcos would have been in fi- nancial difficulty very quickly.

It also became clear that the nuclear power program in fact very un- economic. The government gradually recognized that no one would take the nuclear plants even for free if they had to take on all the back-end obligations and risks associated with decommissioning and fuel reprocessing and the like. So the government decided in Sep- tember to withdraw the magnox reactors from the privatization be- cause they were near the end of their life, and withdrew the rest of the nuclear plants a few monts later. The nuclear plants will be set up in a government-owned corporation, which will be outside the priva- tization and will sell power into the market at market price.

Despite all these problems, there have been significant intellectual advances in understanging how one might operate a competitive electricity system. Perhaps the most significant innovation is the in- dependent gird company that will own and operate the national transmission grid and run the central dispatch operation. The grid company will operate as a market maker, buying and selling electric- ity and determining prices in that process, buy not playing any active role in determining when to build power plants or what kind of power plants to build.

The national economic dispatch system will take offers to generate electricity at various prices (supposedly reflecting the operating costs of the various plants) and will then dispatch the plants, using the lowest running-cost plants available to meet the national demand. The system price for each half-hour will be the running cost of the highest-running-cost plant on the system at any time, plus a capac- ity-related element that will become very high when the system is 122 Session III

under stress. The total system price will be paid directly by the sys- tem to all generators when they are available; anybody taking en- ergy will pay the system for it directly, at the full system price plus an «uplift» to cover the cost of reserves and system services. Any con- tracts between generators, customers or middlemen will be side deals that have no effect on system operations.

There are, naturally, serious concerns about whether such an un- precedented system can work. It is the traditional ethos of an elec- tricity system that somebody must have the obligation to supply, to be sure there is adequate capacity to keep the lights on. In the UK, the distcos were originally to have such an obligation, which was as- sumed to require them to contract long-term for firm supplies. But when anybody is free to get a license, buy energy off the system at the marginal price and take away customers, any distco that con- tracts to meet its obligation to supply may find itself with no cus- tomers and stranded contracts —an untenable situation.

One proposal for solving this problem was to establish a separate ca- pacity market and require that anybody who buys energy off the system have a «capacity ticket» —proof that it has capacity under contract somewhere— with a significant penalty for any energy taken without a ticket. There would be a market in these tickets so that anybody who wanted to build a power plant would sell both ca- pacity tickets and energy; the price of tickets would be bid to the point to where it would cover the capital cost of power plants. This interesting idea was opposed by the generators, who feared (cor- rectly) that it would loosen their control over the capacity market. The current system, as described above, provides an administered price for capacity, as opposed to a market price that would be deter- mined in a separate capacity market.

The principal problem confronting this electricity spot market is that there will be only two generating companies selling into it. Intially, one company was to have 70 percent of the national generation ca- pacity, so that it would have the deep pockets necessary to support the nuclear program. The nuclear program has now been taken «Electricity in Europe in the Run-up to 1992» 123

away, but the company still has 50 percent of the capacity. As a re- sult, the instantaneous spot market price will be virtually under the control of the unregulated generators. Although the government is trying to impose contracts that will control generator market power for a few years, they have not yet been successful; and there is yet no mechanism for controlling generator market power when the ini- tial contracts expire —shortly after the next election.

Over the next few years, this systems can evolve in one of two ways. The generators may be careful in the exercise of their monopoly power, extracting enough monopoly profit to satisfy their sharehold- ers without upsetting customers, regulators, competitors and politi- cans so much that further controls are imposed. However, it is more likely that some sort of regulated, administered price will have to be imposed. Such a price might look very much like the old bulk supply tariff, with a price being announced for energy during various times of the year and times of the day, and anybody free to sell or buy at that price, with a mark-up to cover the system costs. This would be an interesting arrangement that can probably work, although one might then wonder what all the fuss has been about; after all the tur- moil, they may wind up with something quite similar to the old sys- tem, except that there is now an institutional structure in place that will lead to competition in the long run.

A particularly interesting feature of the emerging UK market, in the light of the discussions that we had yesterday concerning oil market option trading, is the role of contracts. The spot price in the UK mar- ket will be unpredictable and (in the present situation) even highly manipulable. However, anybody —any generator, distributor, banker, insurance company or financial intermediary— is free to sell hedges, options contracts, insurance, or whatever you want to call it, against the spot price. For example, a generator can go to a distrib- utor and say: in exchange for a fixed payment up front, I will guar- antee you that whenever the system price you would otherwise have to pay gets above, say, 2 pence a kilowatt hour, I will pay you the difference between the system price and the 2 pence. Such a con- tract would provide for a guaranteed cash flow from buyer to seller, 124 Session III

equivalent to a capacity payment, in exchange for eliminating the ef- fects on both parties of high spot market prices. This is, in effect, a one-way option contract, similar to those now traded in oil.

Option contracts are relatively simple to write and enforce, eliminat- ing one of the principal difficulties they have had in the UK —the need to write very complicated contracts that give the buyer control over specific generating sets. Options contracts can provide most of the economic advantages of standard power purchase contracts, but are much simpler and easier to trade. Thus, it is predictable that elec- tricity options will be written and traded as in any other commodity market; indeed, the London Futures and Options Exchanges (FOX) announced in January 1990 that it is studying the possibility of such trading.

Taken as a whole, the UK system is an exciting and important exper- iment —but it is an experiment being conducted on an entire na- tional system, requiring the simultaneous development of several complex and little —understood concepts, under the pressure of a politically— driven timetable. The best guess in that it will not work as planned but will require years of modification and renegotiation to work out a stable set of regulatory and commercial relationships. Still, it is demonstrating that the desintegration of the electricity sector is technically and economically feasible; many of the things that have happened in the oil industry could happen in electricity.

CONCLUSIONS

The rapid changes going on in the United States and the United Kingdom, as well as the changes occurring in European electricity that Professor Noreng mentioned —the increases in electricity de- mand and in political and economic integration— are liable to change many of the traditional asumptions about how an electricity system should operate. The essential things necessary for a liberal electricity market are a grid to allow trading, a disinterested market maker to determine market-clearing prices, and some rather sophis- «Electricity in Europe in the Run-up to 1992» 125

ticated pricing and trading systems. How and when these elements will develop in Europe is unclear, given the political realities. But such a market probably can be made to work and would produce major changes in the way utilities make their decisions.

A liberalized electricity market would produce significant effects. In particular, generating technology will change, the scale and lead- time of plants will be reduced, and entrepreneurial IPPs will provide capital and technical know-how. Systems that are starved for capital and technical know-how should think carefully about opening them- selves up in this way. Given the pace of change in Europe today, we may see many of these changes taking place surprisingly quickly.

LARRY RUFF

Larry Ruff, a director of Putnam, Hayes & Bartlett, has advised on electricity privatization in several countries, particularly the UK. In the US, this work has focused on the growth of competitive electricity markets; he developed and applied some of the first competitive bidding systems for utilities and provi- ded analyses and testimony that apply competitive market economics and business principles to utility rate design and least-cost planning/demand-side management issues.

Prior to joining PHB, Dr. Ruff served at the US Synthetic Fuels Corporation, W. R. Grace & Co., Brookhaven National Laboratory, and other academic and government institutions. He has written widely on energy and environ- mental policy issues. He received a B. S. degree (with honors) in physics from the California Institute of Technology and a Ph. D. in economics from Stan- ford University. 127

«ENERGY, ENVIRONMENT AND THE 1992 SINGLE EUROPEAN MARKET»

MICHAEL J. WRIGLESWORTH

SINGLE ENERGY MARKET

The blueprint for achieving the Single Energy Market was set out by the Commission in May 1988. A key element is to remove restrictive national barriers, so that the advantages of a large, single market, with increased competition, will result in lower energy prices to the consumer.

The oil market in Europe is already competitive, both within the Community and internationally, and has transparent pricing. Liberal- ization of the oil market would be a matter of removing national bar- riers, which were often set up to ensure security of supply. For the Single Energy Market, security of supply becomes a Community is- sue. The effects of an energy policy on the environment is a major is- sue. The Single European Act of 1987 requires a high level of envi- ronmental protection and safety to be built into all Commission proposals. As a result, Commission energy strategies must take full account of this need. This means setting consistent energy and envi- 128 Session III

ronmental objectives and ensuring that policies are compatible with these objectives.

Prudent and rational use of natural resources is an explicit environ- mental objective. So the Community must pursue effective environ- mental protection and safety by cost-effective and energy-efficient means. One problem we have to face is that protecting the environ- ment consumes resources —it almost always costs money and usu- ally consumes energy.

ENVIRONMENT AND THE SINGLE EUROPEAN ACT

Article 130 R of the Single European Act sets broad environmental objectives:

— to preserve, protect, and improve the quality of the environ- ment — to contribute towards human health — to use natural resources in a prudent and rational fashion

It also sets principles of action to be taken to meet these objec- tives:

— preventive action should be taken — priority for environmental damage should be rectified at the source — the polluter should pay — environmental protection requirements should be a component of the Community´s other policies.

Article 130 R does not stop here. It also states factors for environ- mental action to take account of the following:

— available scientific and technical data — environmental conditions in the various regions of the Commu- nity «Energy, Environment and the 1992 Single European Market» 129

— potential benefits and costs of action, or lack of action — economic and social developments of the Community as a whole and balanced development of its regions.

Article 130 R must be considered with Article 100 in reference to barriers to exchange of goods and avoidance of unfair competition.

PAYING FOR ENVIRONMENTAL AND HEALTH PROTECTION AND SAFETY

The Polluter Pays principle is established in EC-and OECD-agreed policies. It is a way of internalizing costs so that the customer pays for any clean-up, rather than the authorities being exposed to the costs. Life is not likely to stay so simple.

Authorities are considering taking the principle further in two re- spects. First, the Commission is preparing a proposal for Strict Civil Liability without fault when pollution occurs. If blame for pollution cannot be established, the original manufacturer of the offending material would be liable, even when no blame is established. Sec- ondly, OECD is developing proposals which would charge industry for costs incurred by authorities in being prepared for a major acci- dent —the Potential Polluter Pays.

The market principle I should like to underline is that the Customer Pays. All costs for protecting health, safety, and the environment come at the end to the customer. But how, and how quickly, the costs can be passed on can produce considerable competitive pres- sures for the companies involved, especially for smaller companies. Authorities realize that being used clean costs money. The find mar- ket forces effective in allocating costs and the private sector easier to regulate. A new concept which is being used to assign responsability and cost is «trusteeship» —the bill for current damage to the envi- ronment must be a current responsability and not passed on to pos- terity. Industry should accept the use of market forces within a clear framework, and accept the concept of trusteeship. 130 Session III

CONCAWE´S ROLE

In the Fourth European Community Environment Action Plan (1987-1992) the oil refining is a «social partner» in the sense of the 1972 Declaration, and has a role —and a responsability— in achiev- ing the Community´s environmental, economic, and social objec- tives.

In fact, the industry anticipated the Community´s action by a decade by establishing CONCAWE in 1963. Intially six major companies sup- ported the activity which was limited to relatively straightforward air and water pollution problems. Today, CONCAWE is sponsored by thirty-five contributing companies representing 90 percent of the to- tal Western European refining capacity, with company operations in all nineteen countries of OECD Europe.

The scope of CONCAWE´s activities has expanded far beyond the original air/water remit and today includes consumer and employee health protection, ecotoxic effects, etc. arising from industry opera- tions and the use of its products. CONCAWE´s policy is encapsulated in the following statement:

The overall objective of CONCAWE is to assist the oil refining industry in Western Europe in the study of environmental and health issues relating to the processing, handling, and use of crude oil and petroleum products, and to improve the under- standing of these issues by the industry, authorities, and users. CONCAWE believes that objectives for the protection of the environment and for safeguarding the health of consumers and employees should be determined by both governments and industry, based on a comprehensive understanding of the relevant scientific, economic and social factors. Therefore, CONCAWE will co-operate with the EC and other international bodies by providing scientific, technical and economic data which will assist in the development of cost-effective, techni- cally feasible, and equitable laws and regulations designed to meet such objectives. «Energy, Environment and the 1992 Single European Market» 131

So CONCAWE, on behalf of the oil industry, is able to contribute to meeting the Community´s need for scientific and technical data, with analyses of options for environmental action in terms of their effec- tiveness, potential benefits and costs.

SINGLE MARKET AND REGIONAL BALANCE

Regional differences raise important questions. It is clear that differ- ents parts of the Community are at different stages of economic de- velopment, as well as environmental protection, and have varying abilities to pay. In particular, member states have different priorities for environmental protection because of local circumstances.

An important balance has to be struck between single market objec- tives and regional priorities, in terms of both extent and timing. For the Community free movement of goods will remain a key principle, and this will mean similar oil product qualities throughout the mem- ber states.

However, some quality characteristics must match the regional cli- matic factor, for example, ambient temperature reflected in diesel flow properties and gasoline volatility. As another example, environ- mental need, because of density of population or local circum- stances, is already established as a legitimate reason for a higher standard of environmental protection.

We need to keep in mind the need to balance single market objec- tives with regional needs/priorities, as we consider possible ap- proaches to emission control.

APPROACHES TO ENVIRONMENTAL ACTION

To achieve a high level of environmental protection without incurring excessive cost it is necessary to choose flexible instruments which take account of the following factors: 132 Session III

— allow industry maximum flexibility, compatible with achieving environmental objectives, thus — emission limits allow the operator to select appropriate fuel qual- ity, environmental quality standards allow still more flexibility — allow optimun choice of technology to achieve emmission limits or quality standards.

Within the Community this open choice of technology is part of the «new approach» to directives. Environmental quality standards would allow controls to be based on need, but encourage «bumps» in the playing field for business competitors.

Emission control limits can be made responsive to technological devel- opments by basing them on «best available technology not entailing excessive cost» (BATNEEC). For such a dynamic approach to emission regulation, it is essential that industry contributes to assessing how emission limits should be related to available technology. Even then, this approach suffers by allowing the least flexibility to industry.

An emission control approach which allows maximum flexibility of eco- nomic choice for the operator of a plant is the bubble concept. When applied to an integrated operation like a refinery, the bubble concept al- lows the operator to choose the extent of emission control for individ- ual limits, to meet the overall emission limit. It may allow the refinery to avoid excessive retrofitting, which unit by unit controls might require.

Industry needs to be alert to the dangers of proportionality —as suc- cessive environmental controls become effective this year´s very mi- nor source of emissions becomes a target for further control because it represents a significant proportion of remaining pollution. The more effective emission control is, the worse this problem becomes.

ENERGY AND ENVIRONMENT CONCLUSIONS

As well as allowing to industry as much flexibility of response as possible in meeting environmental controls, authorities need to «Energy, Environment and the 1992 Single European Market» 133

take a comprehensive approach. Such a comprehensive approach will:

— choose most cost-effective control options. — allow for energy efficiency as an important factor — avoid inefficient piecemeal action

In its turn, industry has obligations to:

— take protective approaches, seeking to apply good standards of health protection and safety, with protection of the environment — argue positively for actions preferred for cost effectiveness and energy efficiency when control actions are proposed — promote a comprehensive approach to issues so that rational choices can be made including energy factors

CONCAWE´s work is increasingly promoting good practice. Current example are:

— reports on occupational health — reports on safe product handling — report on managing safety — report in preparation on waste management — strategy to promote closing the gasoline system — guidance on avoiding the nuisance of pipe noise by good design — handbooks on oil pollution clean-up — ecotox guidelines for products.

Authorities will increasingly look to industry to take positive ap- proaches to environmental protection, including health and safety. Via CONCAWE the oil companies can show they are already responding.

MICHAEL J. WRIGLESWORTH

Michael J. Wriglesworth was appointed Executive Coordinator of CON- CAWE, the «Oil Companies European Organization for Environmental and 134 Session III

Health Protection», in 1987. His CONCAWE responsabilities include heading the Secretariats of the Executive Committee, Strategy Planning Committee and Safety Management Group.

Mr. Wriglesworth holds the degrees of MA and D. Phil. in Chemistry from Oxford University. He joined BP Chemicals Research Department in 1966 and transferred to the commercial side of BP Oil in 1973. At BP Oil his res- ponsibilities included supply, commercial operations, regional coordination, planning, information technology, health, safety and environment. 135

«OIL IN WESTERN EUROPE IN THE RUN-UP TO 1992»

JUAN SANCHO ROF

First, let me thank the Harvard-REPSOL Seminar for giving me the opportunity to present some issues which I think are important in the development of the oil industry. I will focus mainly on refining, as one of the sectors of the industry most caught up in all the current movements in the energy industry. In doing so, I will refer to the ideas we have heard this morning about natural gas, nuclear power, and environmental concerns, all of which deeply affect the refining industry. I will begin with figures that show the situation today and how we foresee the near future, according to what we expect to happen in the Common Market and the regulations that are re- quired, in my opinion, to strengthen the Common Market.

First, as Figure 1 shows, in the last few years energy requirements have been growing, and as a consequence the oil business and oil markets in general have been growing as well. This growth reflects the growth of the world market. Figure 2 shows the breakdown of total energy requirements in the EEC by energy commodity. As you can see, oil constitutes a large part of that total, 45 percent of pri- mary energy and, as oil products, 50 percent of final consumption. Coal declined at the primary level from 23 to 21 percent; at the level of final consumption the decline was from 10 percent to 8 percent. 136 Session III

Energy conservation, or savings, has been an important part of the picture, as Figure 3 shows. On an index basis, the relationships of en- ergy savings to GDP in the EEC declined by 1982 to only 80 percent of the 1973 level. In France and Italy the decline was even greater. The situation stabilized through 1987, although 1988 and 1989 may show a slight increase. Nevertheless, the stabilization should persist, given present technology and the cost situation in energy.

Figure 4 gives us an idea of the rationalization in refining capacity that has taken place in the last few years. From more than 900 mil- lion tons per year nominal capacity in 1978, we are now at roughly 580 million tons per year. Distillation is above 80 percent of this nominal capacity, which means that the rate of the utilization of the capacity is about what it was before the first OPEC oil crisis. We are utilizing refineries above 80 percent on average. Through rationaliza- tion, all the obsolete refineries that were formerly part of this capac- ity are now out of service. The efficiency of the refining sector is much greater now than formerly.

This improved efficiency has aided the economic sutuation of the re- fining sector. For example, in 1986 the margin for the distillation of crude was minus one half dollar per barrel; we are now breaking even (see Figure 5). This, of course is a trend: there are fluctuations around that figure, but it is quite clear thas this is the trend of the last three years. The same is true for some of the conversions of the in- termediate products to fuels. Figure 6 shows the ratio between pre- mium gasoline and naphtha based on data for Mediterranean and Northern European regions. As can be seen, the ratio between the two products is growing rapidly. It reflects, of course, the healthy growth in the demand for gasoline. Figure 7 shows the ratio be- tween gasoline and residual fuel oil. All these figures demostrate that the overall situation in refining —distillation, conversion and so on— is improving as a result of the supply/demand situation and the ra- tionalization of the sector.

Another important point to consider for the future is the evolution of the price differential for sweet and sour crudes. The importance «Oil in Western Europe in the Run-up to 1992» 137

stems from the increasing significance of environmental problems. Figure 8 shows the dramatic increase in the past two years between sour and sweet crude prices, a differential which is growing wider.

Let me say more on the subject of the environment. The permissible sulphur content of fuels is limited in many countries to 1 percent.

We expect that this regulation in the rest of the Community will be reduced year by year. Referring back to the differential between sweet and sour crude prices, the producing countries with large re- fineries have major opportunities for selling products to cover some of the deficits in the Common Market.

Figure 9 gives an idea of the balance between demand and refinery production in different areas. In general, projected growth in inland demand does not diverge very far from projected refinery production although some areas show shortages, others a surplus. The balance in all areas will be affected by the level of environmental restrictions on the one hand and the possibilities of improving the «environmen- tal quality» of refined products on the other. The demand/produc- tion balance at the product level shown in Figure 10 assumes a con- tinuation of the present situation, without new environmental regulations. There are some surpluses in motor gasolines, with Eu- rope producting more than the continent needs. There are some shortages in the middle distillates and large surpluses in fuel oils.

Figure 11 shows the breakdown of total demand for each of the pe- troleum-based fuels by individual fuel category in the United States market. Taking the environmental situation into account, all refinery products will be affected by environmental regulations concerning acid rain, SO2, NO, CO2, lead and aromatics. Year by year, the reg- ulation of all emissions in getting tighter. (See Figure 12.)

The industry has to consider this progressive severity of environmen- tal regulation in its making strategic plans. We have considered, for example, two scenarios that currently are plausible forecasts for the future level of environmental regulations. One we have termed the 138 Session III

«hard line», the other, the «worst case». (See Figure 13.) Some com- panies consider this situation an opportunity because their more technologically advanced facilities will make it possible to meet those tightening standards, thus giving them a competitive edge.

Figure 14 is a chart of our forecast for unleaded gasoline demand through the year 2000. We expect that by 1994 consumption of un- leaded gasoline in the Common Market will be about 50 percent of total gasoline consumption.

Figure 15 is a breakdown of gasoline consumption by sulphur con- tent. There are two main markets for that product, motor fuel and heating oil. We expect that the permissible sulphur content of gasoil will be drastically reduced by 1994. Figure 16 is a tabular summary of our forecast of the course of environmental restrictions within the EEC market. Tax advantages will accelerate the demand for higher octane gasolines, but tighter restrictions on benzene specifications will reduce supply; the earlier surpluses will be reduced. The gasoil market was in balance, as shown in Figure 10, because of substitu- tion and the impossibility of allocating fuel oil with high sulphur. With respect to fuel oil demand, there may be no possibility of the substitution of natural gas or nuclear power rapidly enough. We saw in Figure 10 a forecast of 134 million tons as the total demand for gasoline versus a supply of 144 million tons, under a hard line sce- nario. That demand would be reduced to 128 or 130 million tons if we take into consideration the restrictions on aromatics content, va- por pressure and octane (lead content), as shown in Figure 17.

In adapting to the circumstances of this scenario, the industry will have to look for more sweet crudes to meet the requirements dic- tated by the markets and for deeper conversion to get lighter prod- ucts. For the octane components to meet market needs, companies will have to invest in, and put into production, new plants with ca- pability to produce those components. There will be a need for desulphurization of gasoils and residuals. This process is very expen- sive, not only in capital requirements, but also in the amount of suffi- cient hydrogen to desulphurize heavy materials. Another requirements «Oil in Western Europe in the Run-up to 1992» 139

will be stack gas scrubbing at large refineries and power plants in or- der to reduce sulphur emissions. These adaptations are summarized on Figure 18.

Figure 19 gives some idea of the implications of sweet and sour crude production and reserves for the future. In 1986, sweet crudes were 27 percent of the production of all crudes. Sweet crude re- serves, however, were only 12 percent of total reserves. The propor- tion of sweet crude production to total production will unavoidably be reduced. This is an ominous outlook to keep in mind when con- sidering the need for future investments and tecnological evolution in the refining sector.

Figure 20 notes the facilities for desulphurizing heavy oils. Most of existing plant capacity is in the USA and Japan, with very little in the EEC. The capacity of these plants is totally insufficient to cover the market that we foresee.

I have described the needed conversion of the refining sector and the large new investments that will be required in order to adapt refineries to the new regulations. (Figure 21 summarizes the full range of changes.) Survival in the future will be limited to those refineries that have totally adapted to the new business challenges. There will be substitution of the present marginal refineries that cannot afford the new technologies by products imported from producing countries. We think that the critical products will be key factors for companies to pro- duce higher volumes of products. Price differentials between light and middle products versus fuels and heavy products will widen. Quality premiums will increase because the market will demand improved quality materials, and there will be a shortage of refinery supplies that will have to be covered by production from abroad. Refinery locations will be re-evaluated. The present value of location was not taken into account in refinery economics in previous years. Products will be cus- tom-made for the market because of environmental restrictions.

Figure 22 summarizes our conclusions on a broader scale. We foresee a sharp increase in sweet crude prices, the promotion of alternative 140 Session III

subtitute energy through the unrestricted movement of electricity, natural gas in pipelines from Siberia and North Africa, and LNG, from West Africa and the Persian Gulf. (This will be significant in the medium term.) We forese the development of a system for cleaning fuel gases in industry, not only in the refineries but also in the large plants of fuel consumers.

Finally, Figure 23 shows graphically the conclusions we have drawn concerning the ability of the refining segment of the oil industry to meet demand. Big refineries have the potential to improve because they have more diverse feedstocks as well as more possibilities to op- timize production and to take advantage of that feedstock diversity. This is not true of small refineries. Their small size inhibits their capa- bility to produce high octane derivatives or hydrogeneration. One of the key factors for their future viability will be their capability to make enough hydrogen. Some of them will be closed because they cannot afford the necessary new investments. As Figure 21 shows, this will likely be true of some OPEC refineries, including those owned or operated with foreign participation.

JUAN SANCHO ROF

Since 1985 Juan Sancho Rof has been Chairman and CEO of REPSOL PETRÓLEO, S. A. (formerly EMPETROL-EMP), the refining and commer- cial/distribution company of the REPSOL group. He is the member of the Board of Directors of REPSOL, S.A. and CAMPSA.

Dr. Sancho was born in Madrid, Spain in 1940. He received a Doctorate in Chemical Sciences and Chemical Engineering from the Universidad Complu- tense de Madrid, a degree in Business Administration from the IESE, and a degree in Petroleum Economics from the CEI of Genova.

He spent six years working for the Spanish Nuclear Energy Assembly, and then moved to the oil sector. He has worked for RÍO GULF as Engineer in Charge of Operations, and for PETRONOR, S.A. as Technical and Commer- cial Manager, and, later, as Deputy General Manager, Mr. Sancho is author of several technical reports and studies. «Oil in Western Europe in the Run-up to 1992» 141

Figure 1 EEC Total energy requirements

PRIMARY FINAL

NOV 89 SOURCE: ENERGY IN EUROPE 1.200 MTOE 1.100

1.000

900

800

700

600

500 1985 1986 1987 1988 YEAR 142 Session III

Figure 2 ECC total energy requirement structure

COAL NAT. GAS OIL PRIM. ELECTRICITY

SOURCE: ENERGY IN EUROPE

PRIMARY

14% 16% 21% 23%

18% 18%

45% 45%

1985 1988

FINAL

COAL ELECTRICITY GASEOUS FUELS OIL PRODUCTS

10% 8%

17% 17%

50% 51%

24% 23%

1985 1988 «Oil in Western Europe in the Run-up to 1992» 143

Figure 3 Final energy savings related to GDP in the EEC Index in 1973 Basis = 100

EEC 12 FRANCE ITALY

NOV 89 100

INDEX 95

90

85

80

75

70 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987

YEAR 144 Session III

Figure 4 E.E.C. 12 Atmospheric distillation capacity VS. demand

MM TMS/Y USD/B 15-20º CRUDE OIL PRICE MM BBLS/D 1.000 20

900 NOMINAL CAPACITY 18

800 16 80% NOM. CAPACITY

700 14 OIL DEMAND NET IMPORTS

600 12

500 10

REFINERY DISTILLATION 400 8 1978 1980 1982 1984 1986 1988 1990 1992 1994

Equivalent conversion capacity EEC

1985 1987 1992 1994 Atmospheric Distillation Capacity, Thous Ton/Year 636,3 597,5 577,0 577,0 % Capacity Utilisation 71.6 79.4 81.5 84.3

% Conversion Capacity: % On Nominal Capacity 19.7 23.8 24.9 27.2 % On Utilised Capacity 27.5 30.0 30.6 32.9 «Oil in Western Europe in the Run-up to 1992» 145

Figure 5 Topping margin for a standard crude oil basket

2

1

0 US$/BBL

-1

-2 1985 1986 1987 1988 1989 1990

YEARS MED. NWE 146 Session III

Figure 6 Ratio, premium gasoline VS. naphtha

1.50

1.40

1.30

US$/BBL 1.20

1.10

1.00 1985 1986 1987 1988 1989 1990 YEARS MED. NWE

MEDITERRANEAN N.W. EUROPE

Differential,Differential, premium premium gasoline gasoline VS. VS. naphtha naphta

80

60

40 US$/BBL

20

0 1985 1986 1987 1988 1989 1990 YEARS MED. NWE «Oil in Western Europe in the Run-up to 1992» 147

Figure 7 Ratio, premium gasoline VS. fuel oil 1%S

3.00

2.50

2.00

US$/BBL 1.50

1.00 1985 1986 1987 1988 1989 1990 YEARS MED. NWE 148 Session III

Figure 8 Differential sweet VS. sour crude price

2.1 Sour = Dubai, Ural, Suez Crudes ACTUAL 1.9

1.7 Sweet = Brent, Es-Sider, Forcados Crudes 1.5

TREND 1.3 $/b.

1.1

0.9

0.7

0.5 O 87 E 88 A 88 J 88 O 88 E 89 A 89 J 89 O 89 «Oil in Western Europe in the Run-up to 1992» 149

Figure 9 Projection of Western World oil demand/refining capacity balance (MM. b/d)

1986 1990 1994/1995

Inland Refinery Production Inland Refinery Production Inland Refinery Production Country Demand at 90 % Capacity Demand at 90 % Capacity Demand at 90 % Capacity

USA/Canada 17.8 15.5 18.0-19.6 16.0 18.5-21.0 16.0 Japan 4.4 4.2 4.3-4.7 4.2 4.5-5.0 4.2 OECD Europe 12.0 13.0 12.0-13.0 12.6 11.8-14.0 11.8 Others OECD 1.0 1.1 1.0-1.1 1.2 1.0-1.1 1.2 Developing countries 9.2 8.9 9.9-10.4 9.8 10.5-11.8 10.8 OPEC 3.6 7.7 3.6-3.8 8.8 3.9-4.3 9.0

TOTAL 48.0 50.4 48.8-52.6 52.6 50.2-57.2 53.0

NOTE: Inland demand includes all oil needs, including refinery fuel & losses. 150 Session III

Figure 10 Western Europe demand/production of oil products balance

1990 1992 1994

Mm ton % Mm ton % Mm ton %

REFINERY PRODUCTION

Motor Gasolines 135,63 22.1 140,37 22.5 144,38 22.9 Middle Distillates 239,83 39.2 247,02 39.6 250,93 39.9 Fuel oils 112,61 18.4 108,31 17.4 103,79 16.5 Others 124,34 20.3 127,51 20.5 130,13 20.7 Total 612,41 100 623,21 100 629,23 100

INLAND DEMAND

Motor Gasolines 125,31 21.6 130,60 22.0 134,37 22.5 Middle Distillates 244,76 42.2 253,88 42.9 258,73 43.4 Fuel Oils 90,71 15.6 85,07 14.4 78,75 13.2 Others 119,65 20.6 122,65 20.7 124,52 20.9 Total 580,43 100 592,20 100 596,37 100

BALANCE EXPORT. (IMPORT.)

Motor Gasolines 10,32 9,77 10,01 Middle Distillates (4,93) (6,86) (7,8) Fuel oils 21,90 23,24 25,04 Others 4,69 4,86 5,61 Total 31,98 31,01 32,86

% Conv./Dist. Ratio 24,00 24,9 27,2 «Oil in Western Europe in the Run-up to 1992» 151

Figure 11 USA demand structure (%)

Product 1988 1990 1992 1994 Gasoline 43 42 41 39 Leaded (< 0.03 g/l Pb) 12 10 8 4

Unleaded Regular 58 50 40 35 Premium 30 40 52 61 U.L. Total 88 90 92 96 100 100 100 100

Gas-oil (%) 19 19 19 19 Motor 43 38 35 32 Industrial/Heating 57 62 65 68 100 100 100 100

Fuel-oil (%) 7 8 9 10 < 1 % S 19 17 18 18 1,0/2,5 S 67 67 67 68 Bunker 14 16 15 14 100 100 100 100

Others (%) 31 31 31 31

Source: EIA. 152 Session III

Figure 12 Principal EEC directives concerning specifications for petroleum products and emissions

Directive Contents 87/416/CEE modifying «Advancement of legislation of 85/210/CEE Member States regarding (lead con- tent in gasolines)» (including ben- zene). 87/219/CEE modifying «Advancement of legislation regar- 75/716/CEE ding sulfur content in certain liquid fuels» (Gas oil). 88/609/CEE «Excessive restrictions on emmissions of pollutant agents coming from im- portant combustion units.» (Solid, li- quid and gaseous fuels. SOX, NOX and dust emissions.)

CONCLUSION

— Consecutive and modificatory legislation. — Continual worsening of the environmental restrictions.

A new Directive is under study; it will reduce the sulphur content (in terms

of SO2 emission) to 1 % maximun of the fuel oil burnt in Small Combustion Plants (up to 50 MW) in all CEE countries with sweet crude supplies. «Oil in Western Europe in the Run-up to 1992» 153

Figure 13 Future principal environmental restrictions in the EEC (1993/1994)

Regulatory specifications

Hard-line Worst-case Products Concepts scenarios scenarios — Premiun & Eurograde %º 60 75 (Unleaded) (Posioning & Catalyst Equipped Cars) GASOLINES — Benzene Content (Carci- % 3 2 nogenic) — Vapor pressure (Butane) BAR 0.6 0.5 (Hydrocarbon emission/ Smog)

— Sulfur content % (Acid rain) Motor 0.15 0.05 GAS-OIL Heating 0.15 0.15

— Sulfur content % (Acid Industrial 1.5/2.5 1.0/1.5 rain) Bunker 3.0 2.0/2.5 FUEL-OIL — Consumption (Green- Steady reduction Extreme reduction house effect) (15 %/17 % over (10 % over Crude) Crude)

— In EEC, the path is set by Northern countries towards the adaptation of U.S. regulations. — In U.S.A.: • Local governmental regulations, even harder than those of EPA. • Present situation between two future EEC scenaries. • Future development, similar to worst-case EEC scenary (Clean Air Act under consideration). 154 Session III

Figure 14 European Unleaded Motor Gasoline Demand (1985-2000)

MILLION TONNES 140 120 100 80 60 40 20 0 1985 1987 1990 1994 2000 27% * 53% 82%

UNLEADED UNLEADED SUPER 98 LOW REGULAR 91 LOW 95 & 98 RON 91 RON LEAD (0.15) LEAD (9.15)

SUPER 98 MEDIUM SUPER 98 HIGH REGULAR 91 LOW LEAD (8.25) LEAD (0.4) LEAD (9.15)

* Percent unleaded in total gasoline demand.

Unleaded Gasoline Market Share %

Country 1988 1994 Japan 100 100 USA/Canada 90 ~100 Germany 55 70 Switzerland 41 Norway 25 Sweden 40 Denmark 30 UK 18 50 + Italy 0,6 France 0,2 Spain 0,1 «Oil in Western Europe in the Run-up to 1992» 155

Figure 15 Western European Gas Oil consumption by % Sulphur MOTOR INDUSTRIAL/HEATING

100

80

60

40

20

0 1988 1990 1992 1994 YEARS 0.21-0.30 0.10-0.20 <0.10 0.21-0.30 <0.20

%

MOTOR

Sulphur, % wt 0,21-0,30 30 22 13 — 0,10-0,20 13 21 30 35 Less than 0,10 — — — 9

Total 43 43 43 44

INDUSTRIAL/HEATING

Sulphur, % wt 0,21-0,30 34 30 21 11 Less than 0,20 23 27 36 45

Total 57 57 57 56

TOTAL 100 100 100 100 156 Session III

Figure 16 Future trends in the EEC single market (1993/1994) (After environmental restrictions)

— Tax advantages accelerate the demand of high oc- Vanishing surpluses tane clear gasoline and unbalance de- GASOLINES — (Note 1). mand/supply. — Scarcity of high octane components (benzene, bu- tane) due to environmen- tal constraints (Note 2).

GAS-OIL — Increasing demand of hea- Bigger than expected ting oil in urban areas. shortages in middle distillates (Critical). — Demand dampening due to revival of energy saving measures (3 % per year reduction during late 70’S FUEL-OIL early 80.5) (Note 3) — Substitute energies policy: + Electric power (generat- Bigger —than— ex- ed by low sulphur coal, pected residua surplu- nuclear or natural gas). ses (Critical). + Natural gas (direct sub- stitution).

NOTES: 1) Practice widely developed. 2) Even after refinery remodelling. 3) Commission of the EEC recomendations to the Council (Oct. 89). «Oil in Western Europe in the Run-up to 1992» 157

Figure 17 Balance of critical products in CEE (After environmental restrictions)

1994 - MM ton.

Hard-line scenario Worst-case scenario

Supply Demand Supply Demand GASOLINE Premium unleaded 52 56 50 56 Other 88 78 78 78

TOTAL 140 134 128 134 GAS-OIL 205 217 205 230 FUEL-OIL SURPLUS 35 SURPLUS 45 158 Session III

Figure 18 Future refining performances (Adaptation of Necessary Productive Structures)

Adaptations Influential factors

Increase of sweet crudes in the Massive unfeasibility. pools. Relative insufficiency of reserves and production. Maximum deep conversion. Difficulties in simple and/or small refi- neries. Plants of high octane clear compo- Limitations in input products (not nents. quite up to date refineries). Hydrodesulphurization of Gas-oil. Hydrogen requirements. Desulphurization of residuals. Technology, limits and risks (Capital Hydrocracking and desulphuriza- strength). tion of residuals (HYCON)

Washing of plant flue gas Requirement for concentracion of emission outlets. In General

• High investments in structure adaptations. • Starting-point sophisticated pro- ductive structures. • Scale economies or break even of sizes. «Oil in Western Europe in the Run-up to 1992» 159

Figure 19 World crude oils, production & reserves (MM./ton.)

Production

Country of origin 1986 1987 1988 Reserves Sweet Crudes

Libya 50 48 51 2,900 Algeria 42 46 45 1,100 Nigeria 72 64 68 2,200 Gabon 8 8 9 200 Angola 14 18 23 300 Other Africa 23 22 23 300 Oman 28 29 30 600 Indonesia 67 63 63 1,100 India 31 30 32 800 United Kingdom 129 123 114 600 Norway 44 49 56 1,400 Other Europe 25 27 28 400 USA 160 157 154 1,500 China 44 44 45 1,000 Ecuador 14 8 15 160 Colombia 15 20 19 300

TOTAL 749 756 775 14,860 160 Session III

Production

Country of origin 1986 1987 1988 Reserves Sour Crudes

Saudi Arabia 251 212 257 23,100 Iran 95 115 113 12,700 Iraq 86 102 128 13,400 Kuwait 62 54 67 12,700 Dubai 19 20 19 500 Qatar 17 16 17 400 Abu-Dhabi 50 58 62 12,100 Other Middle East 34 39 46 1,800 Egypt 42 46 44 600 Venezuela 93 89 96 8,300 México 136 142 141 7,500 Canada 86 80 83 1,100 USA 320 314 309 2,900 China 87 89 91 2,100 USSR 615 624 624 8,000 TOTAL 1,993 2,000 2,097 107,200 Rest of the World 164 160 159 2.500

% Sweet Crudes 27.3 27.4 27 12.2 TOTAL OECE 1.715

Production Sweet/OECE (20 years reserves) 45.2 % Id. (15 years) 57.8

Sweet Crude: Atmospheric residue contains less than 1.70 % S wt. Source: REPSOL PETRÓLEO and BP Statistics. «Oil in Western Europe in the Run-up to 1992» 161

Figure 20 Direct hydrodesulphurization of residues existing units (Non - CPE countries)

Country N.º of Plants MMT/Y Remarks

USA 7 19.9 35 % Phillips, 34 % Chevron, 10 % Exxon. Canada 1 1.5 Japan 11 21.8 Most plants belong to 100% Japanese Companies. EEC 1 0.8 OPEP 3 13.8 Two plants in Kuwait one in Saudi Arabian. Others 2 3.0 Both plants in Taiwan

25 60.8

Residue HDS definition means a reduction of molecular weight to a maxi- mun of 10 % of the feedstock.

COMMENTS

— Building these plants requires high investment, hydrogen supply cheap large and reliable, and a complex and sophisticated refinery.

— The process technology is in evolution and still needs some improvement.

— Because of the economies of scale, large units are difficult to keep run- ning at high capacity for lack of feedstock. Plants suitable for JOINT VENTURE BUSINESSES. 162 Session III

Figure 21 Future advancement of the refining position in the EEC

— HIGHLY SELECTIVE PROCESS:

• Survival of the totally adapted refineries. • Substitution of marginal refineries by OPEC imports.

— MARGIN INCREASES (adapted refineries):

• Constant sales of critical products. • Widening of the price differential between light middle products. and heavy products. • Zenith of quality premiums. • Importance of regularity premiums (critical products). • Re-evaluation of locations (regional unbalances and freight increases).

— REINFORCEMENT OF REFINING/MARKETING INTEGRATION:

• Products custom-made for the market (different environmental res- trictions by zones/regions and commercial additives). • Disappearance of independent/marginal networks (availability of qualities). «Oil in Western Europe in the Run-up to 1992» 163

Figure 22 Other consequences

— SEVERE INCREASE IN SWEET CRUDE PRICES (On the other hand, mar- ket for sour crude buyers).

— PROMOTION OF ALTERNATIVE SUBSTITUTIVE ENERGIES (free un- hampered movement of electricity, and gas in pipelines from Siberia and Northern Africa plus LNG carriers from West Africa and Persian Gulf).

— DEVELOPMENT OF THE SYSTEMS FOR CLEANING FLUE GAS IN IN- DUSTRIES WHICH ARE IMPORTANT CONSUMERS OF ENERGY WITH PRICE INCREASES AND TAX INCENTIVES.

— HIGH COMPETITION IN UNITS WHOSE BUSINESS INVOLVES THE OUT-LET OF SULPHUR RESIDUALS SUCH AS ASPHALTS AND MA- RINE BUNKER.

— INCREASING COMPETITION IN THE EXPORTING OF PRODUCTS NOT MEETING THE REGULATION SPECIFICATIONS TO NON OECD COUNTRIES (less stringent standards).

— DIRECT EXPORTS OF CRITICAL PRODUCTS TO IMPORTANT FINAL CUSTOMERS (including networks) WITH THE INCORPORATION OF TRADING SERVICES (Freights, Hedging). 164 Session III

Figure 23 Ability to meet demand. Conclusions

INVESTMENT INCREASES

FUTURE MARGIN INCREASE MARGIN DECREASE

MARGIN

POSITIVE

REFINING CAPACITY NEGATIVE ADVANCED PROCESSES REFINERIES

INADEQUATE REFINERIES EXPECTED CLOSURE

INLAND DEMAND

OPEC REFINERIES 165

CONCLUSIONS

BIJAN MOSSAVAR-RAHMANI

The purpose of the last session of these meetings is to sum up what has been said; to think about implications of our discussions of cor- porate and public policy; and to develop and recommend topics for follow-up research at Harvard University, the cosponsor with REP- SOL of the meetings.

As was said yesterday, this is the third Harvard-REPSOL get-together of its kind held here in Spain. The format of these meetings —the mix of academics, business executives, government officials and offi- cials of international organizations— is a mix that works well, we be- lieve. I hope you have also found that the interaction has proved useful to you. One reason for holding these meetings in places like Toledo (other than the delightful surroundings and the very civilized way in which REPSOL organizes the sessions and the related social activities) has been to expose researchers at Harvard an other from outside Spain to developments in this country. Spain, as you know, has been for the last three years a very exciting place to follow and to visit because of the dramatic changes in the Spanish economy, particularly in the energy sector. REPSOL, moreover, has been an ex- citing company to interact with, as it has undergone its own recent 166 Closing Session

transformation and has developed into a significant force on the Eu- ropean oil scene. Participating in these meetings has been a produc- tive and enjoyable experience for those of us who have come in from the outside, and we thank our hosts for the opportunity.

Another purpose has been to air and critique the research conducted at Harvard and other academic institutions that attend these meet- ings. Some good comes out of that process as well. The Oil and Money Project at Harvard which was reported on yesterday had its genesis in an earlier Harvard-REPSOL meeting. It is my hope that as we wrap up the session today we can list other potential research ar- eas of analytical and intellectual interest to researchers but with prac- tical implications for practitioners in industry and government as well.

The moderator of the last session has the luxury and the prerogative of making personal observations on both the formal presentations and the follow-up discussion. My current bias is that of a wildcatter or explorationist; I hope that bias will come through in my comments and that it will generate appropriate responses on your part. After I have had my say, I will call on those of you who have been involved in making presentations, as well as on those of you who have not, to reflect on the implications for policy of what has been discussed here.

The moderator has the task also of seeking some common threads in the discussions, often a hard thing to do. The most one can attempt under the circumstances is to identify what new things may have been said, recognizing that often it is only on departure and further reflection that a new idea or two fall into place. However, on bal- ance, these meetings typically raise more questions than they an- swer, and the past two days have been no exception.

SESSION I

Let me start with Session I, which, as an explorationist, I found least satisfying in that clearly more questions were raised than answered. Conclusions 167

Yet answers, particularly with respect to the outlook for prices, are a key part of the exploration business. Explorationists need to make specific price forecasts on which to base substantial investment deci- sions —risk decisions. The first session underscored the continuing broad differences of opinion that persist among those who worry about prices and the market outlook.

Alan Binder hinted that Shell will make money under any of his oil price scenarios, even within a volatile range of $10 to $20 a barrel. Shell is a large integrated company involved in all aspects of our busi- ness. My company, in contrast, is a small one, involved only on the exploration side. It does matter to us where prices go and when, and how well we place our bets. And we do place bets on prices. We have an oil price forecast in the company that goes out more than 10 years, including a very specific forecast for each year. Every one of our investment decisions is based on those price forecasts. Our price forecasts do not necessarily reflect my own views of the likely direc- tion of the market, since our corporate forecasts mimic the conven- tional wisdom, to which I do not subscribe. The oil companies, my own included, have a pack mentality when it comes to making fore- casts (and often other business decisions). Forecasts, to be credible to boards of directors or investors or management itself, cannot appear too unconventional. It is much easier, comforting, and acceptable for company forecasters to come up with a straight line or trend forecast of the kind that the IEA has made than the type of cyclical forecast that Bill Hogan would subscribe to.

Although Alan suggested that Shell uses scenario planning and not straight line forecasting, I am sure Shell does have very, very specific forecasts that drive their decisions, at least in the exploration end of the business if perhaps not in other areas of their activities.

The presentation of the IEA outlook made by John Ferrier was neither conclusive nor convincing to me. John started out by saying that the long-term forecasts were driven by the IEA’s short-term forecasts and that short-term prices might weaken, or they makes not fore- casts but projections based on scenarios. That is largely a matter of 168 Closing Session

semantics, as is the differentiation between forecasts and scenarios that Shell makes. Shell’s verbal gymnastics do not offer me very much confidence or comfort either, because the reason Shell —and other oil companies— have stopped calling these numbers forecasts is that their forecasts have been so wrong so often that they now choose to obfuscate by calling them something else. Despite the very specific projections —forecasts— made by the IEA, the fact that the Agency prefers not to call them forecasts causes me concern because it suggests that the Agency, too, is not very comfortable with its own numbers. Perhaps the IEA recognizes that the uncertainties that we have faced in this business, at least since the early 1970s, continue to exist.

John talked about moderate and stable growth both on the demand and supply sides, with oil prices reaching $30 a barrel (in 1989 dol- lars) by the year 2000. He elected not to tell us how we will get there, but I am hard pressed to believe that it will be through a process of gradual, dollar-a-year price increases. In my opinion a price of $30 a barrel by the year 2000, if it comes to pass, will only result from one or more «surprises» leading to the kickup in oil prices. John did acknowledge the possibility of minor hiccups but did not want to be pinned down and talk about major surprises. It has long been the view at the IEA that if this organization acknowledges surprises it is somehow sanctioning what might become a self-fulfill- ing prophecy; ironically, the IEA’s raison d’être is to deal with supply emergencies. Notwith-standing, I think a price ratchet or ratchets are in fact implicit in his forecast. If not, the stable and predictable trends he is looking at, and the assumptions he is making about continued reductions in intensity of oil use, do not, in my mind, take us to a $30 a barrel price level. But the IEA needs to warn of high prices in order to justify its continued existence, even if such justification may not fall out of the econometrically-driven models of world oil market supply and demand. The result of these conflicting imperatives is that the IEA forecast is not internally consistent.

Some of the underlying trends that John brought up in his presenta- tion are similar to those seemingly driving the Shell scenario, although Conclusions 169

Shell comes up with a vastly different price outlook. Alan spoke of a $10 to $20 price range and zeroed in on $14 to $16 as his own preferred outlook. That $10 to $20 a barrel range reflects consid- erable volatility and a very different oil market outcome than that of the IEA. The fact that Shell’s assumptions about modest and stable growth in supply and demand still lead to such price volatil- ity suggests a market driven by political forces; in some sense, Shell planners and forecasters, frustrated year in and year out in attempts to quantify and anticipate those forces, have simply thrown in the towel. The only presentation in the first session that was thrown in the towel. The only presentation in the first session that was both internally consistent and explicit was Bill’s. Now I admit I have a bias favoring the work at Harvard, having partici- pated in the Center’s research over many years, but I think others will agree that the Harvard effort at least attempts to be objective, carries no institutional baggage, is transparent, and concludes, not surprisingly, that the basic principles of economics apply to oil markets as well.

Bill, for example, challenged the inevitability of conservation in the face of lower oil prices. He suggested that we are already seeing a re- versal of the reductions in intensity of oil use, and indicated that oil demand, at least in a number of countries, is already outpacing GNP growth. Bill subscribes to cyclical trends, foreseeing a market that will be subject to faster tightening and that will continue to be marked by surprises. No one among us can anticipate the nature, timing, or in- tensity of those surprises, but Bill proposed that the biggest surprise of all in the 1990s would be stability in the oil market. Bob Weiner offered a similar insight in his presentation when he said that the sta- bility of the period 1950 to 1973 was an aberration —the excep- tion— and not the rule. There is an ever-changing, ever-evolving list of possible surprises, some of which were raised at this meeting. One involves that John referred to as «the other guys»: Eastern Europe. Perhaps developments on the Astern European political front will im- pact the energy policies and requirements of those countries. The possibility of surprises triggered by environmental developments has also been raised repeatedly in the past day and a half. 170 Closing Session

SESSION II

Moving on to Session II on oil and money, again I have a bias. I view ourselves, the wildcatters, as the warriors, and the oil and money crowd —the financial institutions, the Wall Street refiners, and the speculating doctors and dentists— as the camp followers. And I tend to believe that we, not they, are fundamental to the business.

I recognize the hedgers and traders —the camp followers— are here to stay. That was made clear in the discussions yesterday. Eija Malmivirta reminded us that the oil and money crowd are now so much a part of the landscape that we forget that this business is only five or six years old. The new player have brought with them new rules of the game; indeed, they have sought to change the game it- self. Oil trading has become a more technical and more complicated business, but again I have problems with the future evolution of this part of our business. One participant mentioned that on the coal side, at least, people like to «touch before they buy». I would hope that in the oil business, too, people would want to continue to touch before they buy and that we do not lose sight of the fundamentals in a rush to embrace new financial instruments.

At the end of the session Eija mentioned to me that with the reference yesterday to «synthetic» oil fields and reservoirs, perhaps, instead of going around the world looking to drill wells, I should be buying syn- thetic fields. I remind you that you cannot burn synthetic oil. If the wildcatters are not out looking for new reserves and do not do more than trade and swap synthetic assets, very soon we will be seeing dra- matic price increases reflecting the limit to the stock of currently avail- able oil. So I think the «wet» side of the business remains critical and should not be overlooked in any discussion of oil and money.

Admittedly, the «paper» side matters, too. Bob talked about how and why the forward and futures markets count more and more, not only to the traders and to those companies that hedge with paper instru- ments, but also the others —including the warriors— whose prices are tied to those markets. That is clearly true. He talked about the effi- Conclusions 171

ciency of forward markets in the sense of providing information; they are good predictors of prices. But he reminded us that hiccups can oc- cur in these markets as well. The Brent forward market collapse in 1986 was a case in point, and he told us that with the collapse, the Merc exhibited substantial volatility. This gives us a question to think about: What kind of hiccup scenarios can one envisage for the future? And what are the implications of allowing the tail to wag the dog?

Hiccups in the paper markets remain a concern to those of us who are involved in the fundamental side of the business. We heard a dis- cussion of what the Merc —what Ernst Weil called «that trading pit in New York»— is doing in terms of expanding and extending its reach around the world to become a round-the-clock electronic trad- ing instrument. The Merc and similar paper markets have become a fact of life, and they grow in importance. What are the implications of a round-the-clock, global, integrated and interconnected paper market for our business? Ernst gave us that practitioner’s view of oil and money markets. He said that the development of these markets has been inevitable, with positive results, suggesting that what is good for Phibro is good for the oil market and is good for the world. On this matter, I defer to Ernst.

A similarly positive opinion of oil and money was held by all the panelists yesterday. We heard from them that the fundamental side of the oil business is learning from paper markets, and that intelligent people can make money trading paper barrels. My own company occasionally dab- bles in that market; we have both made money and lost money. I am not sure what that says about our level of intelligence, but what it does say is that even those us who are part of the fundamentals do pay at- tention to and try to understand how these markets affect us, and how we might best position ourselves to take advantage of any opportunities.

SESSION III

I will not attempt to duplicate the summary just made by the moder- ator of Session III. The issues raised at that session are still very much 172 Closing Session

on our minds. It is safe to say that if we had organized this meeting in the light of the East and West European developments now taking place, we would have done it different issues, than we anticipated even several weeks ago. But clearly the two issues that we came back to on the panel —the importance of institutional arrangements and organization of markets— are key elements of how the Euro- pean oil scene evolves, whatever the size of the continent or how- ever it is called.

FUTURE RESEARCH

With that, let me now return to a list of topical issues for future re- search at Harvard and elsewhere. The question of what happens to «the other guys» —Eastern Europe— is of foremost concern. We heard that the energy sector in the Soviet Union may evolve in dra- matically new ways. Eija speculated that perhaps the Soviet Union could become a net importer of oil, a development certainly impor- tant to her country and her company, but with global implications as well. Oystein Noreng talked about the possibility that the Soviets may allow foreign oil companies in to explore with new technologies, but he also said he was not inclined to become hysterical about So- viet natural gas flooding Western Europe. That possibility of substan- tially greater availability of natural gas from a politically more accept- able Soviet Union would clearly threaten market prospects for Norway. All in all, the opening of what was the Soviet bloc —and of the Soviet Union itself— will provide significant opportunities for col- laborative research with Western scholars and access to previously unavailable material.

The second area of research interest, perhaps more so to the oil com- panies, is the one alan reflected on: Who will make the massive nec- essary investments in new oil infrastructure, at least in the down- stream sector? I think we on the upstream side are comfortable that investments in exploration and production will be made in a timely fashion; companies like mine continue to aggressively chase oppor- tunities. The downstream side faces investments on the order of Conclusions 173

terms of perhaps hundreds of billions of dollars to meet some of the changes in the composition of demand and environmental restric- tions as described by Juan Sancho in his presentation. Juan said that newer, more sophisticated refineries have better margins than older ones, many of which are being phased out as uneconomic. But to put into place the capacity required in the future will require sub- stantial capital investments. Who will pay for new refineries? Or new tankers? Could surprises we have talked about be driven not by shortfalls in availability of crude oil as envisaged by more conven- tional scenarios but stem instead from limitations or bottlenecks in availability of certain kinds of downstream infrastructure? That, I think, is an important question, which extends to other energy sources as well. Larry Ruff talked about the problem on the nuclear power side. Who will pay for new nuclear plants or any significant scale? Is there a role for the oil and money crowd in this arena?

A third area of research interest is that of the impact of changing en- vironmental pressures and challenges. The IEA’s position, at least as reflected in John’s presentation, is that environmental issues are rela- tively well know —a constant, with little possibility for surprises. That view was not however, shared by some of the other discussants, who observed that environmental considerations will remain an im- portant uncertainty to be anticipated and dealt with. Certainly, growing environmental awareness —and corrective action— could change the way energy is produced and consumed in Eastern Europe and the Soviet Union.

A fourth area of potential research is one that Eija and Ernst both touched on: long-term price arrangements. Apparently contracts being written today that lock in prices over periods of five years or more through long-term swaps represent a fascinating extension of cur- rent hedging and other financial instruments. I am eager to learn how these contracts work and to find out whether these contracts are only isolated arrangements that meet the specific needs of par- ticular companies. Or will we see a broad-based shift to firm price, long-term oil sales arrangements? If that is the case, it would be a dramatic change in the way in which we conduct our business and 174 Closing Session

the way in which the oil market functions. So too would be the wide- spread adoption of the concept of Btu-spread contracts. If we do adopt such contracts, markets could be further linked and integrated geographically or across fuel sources, or both, with far-flung conse- quences.

Session III underscored the importance of institutional and organiza- tional considerations as Europe becomes a single entity, either West alone or East and West together. For those of us on the other side of the Atlantic, understanding the institutional barriers and organiza- tional considerations that drive European energy markets become in- creasingly important. Similarly, here in Europe, the experiences of the United States, in such areas as the deregulation of the natural gas or electricity sectors, become important sources of insight and provide lessons to planners and busineses alike. 175

LIST OF PARTICIPANTS

Mr. Manuel Abollado Mr. José del Pozo Chairman of Petroleum and Director of Corporate Petrochemical Area Development Ercros, S.A. Repsol, S.A. Serrano, 41 Paseo de la Castellana, 89 28001 Madrid, Spain 28046 Madrid, Spain

Mr. Aurelio Ayala Mrs. Kathryn Domínguez Director of the Representation Assistant Professor of Public Policy Office Harvard University Repsol, S.A. 79, Kennedy St. 38 Avenue des Arts, Bôite 2 Cambridge, MA 02138, USA 1040 Bruxelles, Belgium Mr. Ignacio J. Egea Mr. Pierre Bullen Deputy Director for Petroleum, Councellor for Economic Affairs Petrochemical and Gas United States of America Embassy Ministerio de Industria y Energía Serrano, 75 Paseo de la Castellana, 160 28001 Madrid, Spain 28046 Madrid, Spain 176 List of Participants

Mr. Gregorio G. Escudero Mr. Antonio Mercanti Supply Director Deputy Director for International Enagás Studies and Projects Avda. de América, 38 Ente Nazionale Idrocarburi (ENI) 28020 Madrid, Spain Piazzale Enrico Mattei, 1 00144 Rome, Italy Professor William W. Hogan Thornton Bradshaw Professor of Mr. Dieter Guenter Moehrmann Public Policy and Management Managing Director John F. Kennedy School of Raab Karcher / Veba Oël UK Government Sicilian House, Sicilian Avenue Harvard University Southmapton Road 79, Kennedy St. London, UK Cambridge, MA 02138, USA Mr. Bijan Mossavar-Rahmani President Mr. Alberto Ibáñez Apache International, Inc. Managing Director 1700 Lincoln St., 20th Floor Salomon Brothers International Ltd. Denver, CO 80203, USA Fortuny, 18 28010 Madrid, Spain Mr. Alan Naismith Binder President Shell International Mrs. Eija Malmivirta Trading Company Executive Vice-President Shell International Petroleum Neste OY Company P.O. Box 20 Sitco, Shell Center SF-02151 Espoo, Finland London SE1 7NA, UK

Mr. Eugenio Marín Mr. Bruce Netschert Rapporteur Chief Executive Officer 3440 So. Jefferson St. Cepsa Falls Church, VA 22041, USA Avda. de América, 32 28028 Madrid, Spain Mr. Øystein Noreng Professor Mr. Alfonso Martínez Norwegian School of Management Sirecox Elias Smiths v. 15 Paseo de la Castellana, 95, 8.º N-1301 Sandvika, P.O.B. 580, 28046 Madrid, Spain Norway List of Participants 177

Mr. Víctor Pérez Pita Mr. Juan Sancho Rof General Secretary for Energy and Chairman Mineral Resources Repsol Petróleo Ministerio de Industria y Energía José Abascal, 4 Paseo de la Castellana, 160 28003 Madrid, Spain 28046 Madrid, Spain Mr. Javier Santamaría Mr. José M. Pérez Prim General Secretary General Director for Energy Petromed Ministerio de Industria y Energía Fortuny, 18 Paseo de la Castellana, 160 28010 Madrid, Spain 28046 Madrid, Spain Mr. Jorge Segrelles Mr. John Pierce Ferriter Director of External and Deputy Executive Director International Relations International Energy Agency (IEA) Repsol, S.A. 2, rue André Pascal Paseo de la Castellana, 89 75775 Paris Cedex 16, France 28046 Madrid, Spain

Mr. Miguel A. Remón Mr. José Sierra Director of Planning and Control Direction B Repsol, S.A. General Direction for Energy Paseo de la Castellana, 89 European Economic Community 28046 Madrid, Spain (EEC) 200, rue de la Loi Mr. Robert Ryan 1049 Bruxelles, Belgium Manager - Risk Analysis New York Mercantile Exchange Mr. Guzmán Solana (NYMEX) Vice-Chairman 4 World Trade Center, Repsol, S.A. 7th floor, Suite 744 Paseo de la Castellana, 89 New York, New York 10048, USA 28046 Madrid, Spain

Mr. Larry Ruff Mr. E.T. Weil Director Chairman and C.E.O. Putnam Hayes Bartlett Ltd. Phibro Energy Inc. Landsdowne House, Berkeley Division of Salomon Brothers Inc. Square Baarermatte, Postfach London W1X 5DH, UK 63012 UG, Switzerland 178 List of Participants

Mr. Robert Weiner Mr. Mike Wringlesworth Research Fellow Senior Executive Coordinator Energy and Environmental Policy Concawe Center Koningin Julianaplein 30-9A Harvard University AA Den Haag, Netherlands 79, Kennedy St. Cambridge, MA 02138, USA Conference Coordinators 179

CONFERENCE COORDINATORS

Mr. Antonio Gomis Mrs. Pilar Suárez-Carreño Deputy Director of International Chief of the External Affairs Dept. and Repsol, S.A. Institutional Relations Paseo de la Castellana, 89 Repsol, S.A. 28046 Madrid, Spain Paseo de la Castellana, 89 28046 Madrid, Spain FOR ADDITIONAL INFORMATION

SERVICIO DE PUBLICACIONES DIRECCIÓN CORPORATIVA DE FUNDACIÓN REPSOL YPF ASUNTOS INSTITUCIONALES Y CORPORATIVOS REPSOL YPF

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