National Reforms in European Gas (Elsevier Global Energy Policy and Economics Series)

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National Reforms in European Gas Editors Maarten J. Arentsen and Rolf W. Kiinneke

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National Reforms in European Gas Edited by Maarten J. Arentsen and Rolf W. Kfinneke

2003

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Contents Preface About the Contributors Acknowledgements

° °

Vll

ix xiii

PART I: Fundamentals Introduction Maarten J. Arentsen and Roll W. Kfinneke o

o

,

The Technological Infrastructure of the Gas Chain Willem van der Wal Harmonisation of European Gas Markets: The EU Gas Directive Leigh Hancher National Models in the Emerging European Gas Market Maarten J. Arentsen and Rolf W. K~inneke

PART Ih National Models o

.

Organising National Interests in the Upstream Gas/Petroleum Industry: The Norwegian Model and its Transformation Atle Midttun, Joar Handeland and Soren Wenstop

13

31

45

63

65

Dilemmas of Duality: Gas Market Reform in the Netherlands Maarten J. Arentsen and Rolf W. Kfinneke

103

The Russian Gas Sector: Survival of the Planned Economy or Evolution of Market Mechanisms? Hella Engerer

133

Contents

vi

o

Gas as a Public Property. The UK Gas Market 1965-86: Maximising the Value of a Limited National Resource

163

Steve Thomas .

Gas as a Commodity. The UK Gas Market: From Nationalism to the Embrace of the Free Market

181

Steve Thomas 10.

The Transformation of the German Gas Supply Industry

213

Lutz Mez 11.

The French Gas Industry in Transition: Breach in the Public Service Model

245

Dominique Finon 12.

Gas Markets in Southern Europe Roll W. Kiinneke and Isabel Soares

13.

Developments and Trends in East-Central Europe and Algeria Maarten J. Arentsen and Rolf W. Kfinneke

PART III: Perspectives 14.

National Prospects in the D a w n of the Internal Gas Market

283

309

327

329

Maarten J. Arentsen and Rolf W. Kfinneke

Index

367

Preface

Despite its increasing importance in European energy balances, natural gas still attracts less research interest than the electricity sector to which it is becoming more closely related. For this reason alone, the publication of a new book on European gas is an important event. As we enter 2003, the relatively slow pace of competition and market liberalisation in Continental Europe, given the weight of expectation in the wake of the 1998 EU Gas Directive, has been disappointing. Despite the determination of the European Commission in Brussels to attribute this to a lack of harmonisation - both among member states, and between the latter and their external suppliers - a more likely explanation is a lack of determination by governments (both EU and non-EU) to press their industries and companies to introduce competition by liberalising access to gas networks. This lack of determination has manifested itself in two concrete forms: failure to create regulatory bodies with strong and proactive powers and a mandate to promote competition; a determination to promote dominant "national champion" gas and multi-utility companies which make it very difficult for new entrants to gain any substantial foothold in the market. This is why, having set the context of EU - or more correctly in the context of imminent enlargement, p a n - E u r o p e a n - legislation, the most useful way to address European gas liberalisation is by means of national case studies written by authors from the respective countries who have not only followed developments in the sector but also understand the political and administrative culture of the countries in question. The 1990s were a time of strident Anglo-North American insistence that the gas (and other energy) utility models created in those countries were best suited to deliver self-sustaining competition and vii

viii

Preface

price reductions. Such insistence has become substantially less influential and compelling in the wake of the California electricity crisis, massive gas price increases in North America, and increasing concern about natural gas security in the UK. With a proposed natural gas security Directive under discussion in Brussels, there is a question as to whether the 1990s drive for liberalised and competitive markets may be overtaken on the policy agenda by security concerns. At a minimum, the new energy security agenda requires that gas exporting countries be taken much more into account by the Commission which has set itself the challenge of dialogue with major suppliers; a process which importing companies and governments have pursued individually for thirty years, but which has now been institutionalised by the EU-Russia energy partnership. This book is published at an exciting time for European gas industries. Despite the fact that the new Common Rules Gas Directive (envisaging full market opening by 2007) is unlikely to have much immediate impact, it will require many governments to revise their legislation and therefore has the potential for surprises. The Eon/ Ruhrgas merger represents another turning point for the European (and not just the German) gas and electricity industries: if approved, this will be a decisive move towards market concentration; if rejected, what will be the future for those players? Irrespective of the outcome, none of the European gas companies which dominated the post-War period can retain their traditional roles far into 21st century. Hence the timelines of this book.

Jonathan Stern Royal Institute of International Affairs/Imperial College, London January 2003

About the Contributors

Maarten ARENTSEN holds a Master's degree in political science (specialisation in research methodology and political modernisation) from Nijmegen University and a PhD (Public Administration) from the University of Twente, the Netherlands. He is associate professor and managing director of the environmental research institute of the University of Twente. He develops, conducts, supervises and coordinates research projects on energy policy, energy market reform and (green) energy innovation, with a special focus on technological and institutional change. He publishes in (inter)national books and journals and occasionally teaches in undergraduate and postgraduate teaching programmes. Hella ENGERER is Senior Researcher at the German Institute for Economic Research (DIW), Berlin. She holds a PhD in Economics from the Free University Berlin. Her main fields of research include institutions and institutional change, privatisation and enterprise restructuring. In recent years, her research has focussed on transition processes in Central and Eastern European countries. Her current work analyses economic reforms in Russia and, in particular, the restructuring and development of the Russian energy sector. Dominique FINON is senior research fellow in the CNRS (Centre National de la Recherche Scientifique); he was director of the Institut d'Economie et de Politique de l'Energie (CNRS and Grenoble University) from 1990 to 2002 and is presently deputy director of the Energy Program of the CNRS. He holds an engineering diploma and a master of economics from Lyon University and a PhD in economics from Grenoble University. He has successively developed researches on energy modelling, nuclear economics and policies, industrial organisation and regulation in electricity and gas industries, and promotion policies of renewables and energy efficiency in liberalised markets. He published numerous papers in international ix

x

About the Contributors

journals and edited several books, in particular Competition in European Electricity Markets, co-edited with J.M. Glachant (Edward Elgar publisher, 2003). Leigh HANCHER is professor of European law, University of Tilburg, The Netherlands and Counsel of, Allen & Overy, Amsterdam, The Netherlands. Joar HANDELAND is Master of Business and Administration from the Norwegian School of Management (NSM). He worked for some three years as a researcher at the Centre for Energy and Environment at NSM focussing on structural changes and strategic developments in the Nordic energy sector. He is currently working as a Strategy Consultant with Anderson Consulting in Oslo, where he works within the Energy and Finance sectors. Rolf KfUNNEKE is associate professor 'Economics of Infrastructures' at the Faculty of Technology, Policy and Management of Delft University of Technology. He holds a masters degree in economics (University of Dortmund, Germany) and received his PhD degree from Twente University, The Netherlands. He has a long record of research on the restructuring of infrastructure industries, with a special focus on the energy sector, i.e., electricity and gas. Recent research includes: liberalisation of European gas markets, innovations in energy networks; convergence of infrastructures; business strategies of energy firms in liberalised markets, regulation and governance of liberalised infrastructure industries. Lutz MEZ is political scientist and holds a diploma in political science and PhD from the Department of Social and Political Sciences, Free University of Berlin, Germany. He is a senior associated professor of political science. He is co-founder and deputy director of the Environmental Policy Research Unit. In 1993/94 he was visiting professor at the Department of Environment, Technology and Social Studies, Roskilde University, Denmark. His major research area is environmental and energy policy with particular reference to nuclear and electricity policy. He is author of numerous articles and chapters in internationally edited books. Some relevant books or editions: Umweltpolitik und Staatsversagen, Electricity in eastern Europe: 10 years after the Chernobyl disaster, RWE: Eine Riese mit Ausstrahlung, Die Energiesituation in der vormaligen DDR and Der Atomkonflict, Energiediskussion in Europa.

About the Contributors

xi

Atle MIDTTUN is professor at the Norwegian School of Management and Co-director of its Centre for Energy and Environment. He was visiting professor at the University of Michigan. He holds a PhD from Uppsala University (Sweden) and a Magister Artium from the University of Oslo (Norway). His research focuses on energy and environmental policy issues especially their regulatory and industrial organisation aspects. He has been the editor of a number of books, including Approaches and Dilemmas of Economic Regulation (2001), European Electricity Systems in Transition (1997, Elsevier Science) and the Politics of Energy Forecasting. He is also the author of an extensive collection of articles on these topics. Isabel SOARES is Full Professor at the Faculty of Economics, University of Porto (Portugal). She is Docteur d'Etat-6s-Sciences Economiques by the Universit6 Louis Pasteur de Strasbourg where she worked at the BETA - Bureau d'Economie Th6orique et Appliqu6e, a CNRS Research Center, and holds a "Aggregation" title by the University of Porto. She was Visiting Professor at the Institute of Advanced Studies of the University of S. Paulo (Brazil) and Invited Researcher at the V P I - Virginia Polytechnic Institut and State University. She has been researcher, supervisor and coordinator of several EC and NATO research projects and she is author of several articles and chapters in (inter)national scientific books and journals. Her main research interests are industrial organisation, energy economics and finance. Steve THOMAS holds a BSc (Chemistry, Bristol) 1971. He is currently Senior Research Fellow of the Public Service International Research Unit (PSIRU), School of Computing and Mathematics, University of Greenwich. He works on issues of public policy related to energy. His main focus is the UK and Western Europe, but he also worked extensively on Eastern Europe and the Former Soviet Union, Brazil, Mexico and South Africa. His main current research interests include: Liberalisation and the restructuring of electricity supply industries; Policy towards and the economic performance of nuclear power; Liberalisation and restructuring of gas industries in Europe; Energy transition in Eastern Europe and the Former Soviet Union; and Structure and policies of the power station equipment supply industry Soren WENSTf~P is Master of Business and Economics from the Norwegian School of Management (2002). He has made a study on investments in Norwegian mutual funds and the financial and moral implications of such investment behaviour. Recently he has been involved in a comparative study on the strategies and behaviour of

xii

About the Contributors

Nordic and European electricity companies, at the Norwegian School of Management. Willem van der WAL was unit manager of the gas purchase consultancy department of Gastec. In the beginning of 2002 he joined the Dutch Energy Regulator, where he is involved in the technical regulation of the Dutch network companies and gas storage companies. At the moment he is member of a project group advising the Dutch Ministry of Economic Affairs about the possibilities for the establishment of a TSO for gas in the Netherlands.

Acknowledgements

The idea for this book was born in Salzburg, Austria in 1998, at the annual meeting of the REFORM group (Restructuring Energy Systems For Optimal Resource Management). The REFORM group is an informal group of scientists who analyse the transformation of energy systems and energy policy in Europe. The immediate reason for this project was the acceptance of the Gas Directive in that year. The consequences are quite profound, as documented throughout this book. For the editors and the contributors it was not always straightforward how to cope and address these fairly complex processes of change. Not at least for this reason it did take longer than expected to finalise this project. We are indebted to the publisher for his patience and confidence in our work throughout this process. The authors, almost all academics, have studied the change in European gas quite closely since 1998 and the book is one of the results of their findings. We are grateful for their valuable contributions, for the stimulating debates and their commitment in getting this book out. We are also thankful to an anonymous referee who made very valuable suggestions to improve our work. For the actual finishing of the manuscript we relied heavily on the support and experience of Amy Mahan and Karin van Duyn-Derwort. Amy Mahan provided essential linguistic support and editorial assistance. Karin van Duyn-Derwort, assisted by Fran~oise Dunant, produced a readable manuscript from all the different formats of the national chapters. At least in this respect there is clear case for convergence between the national cases. The editors.

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PART I Fundamentals

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Chapter 1 Introduction ,=

MAARTEN J. ARENTSEN AND ROLF W. KUNNEKE

'Since the early 1990s there has been a general feeling that the "old order" in European gas markets is about to give way to fundamentally different type of market organisation'. 1 Some ten years later, this 'general feeling', Sterns refers to in his 1998 book, becomes more open for scientific evaluation. At the end of 2002 one can conclude that gas markets in the EU legacy have indeed changed since the turn of the millennium. But did these changes give way to a fundamentally different type of market organisation as was expected at the beginning of the 1990s? The 1998 release of the EU directive on gas market liberalisation (98/ 30/EC) and the national adoption of the EU gas directive requirements in mid-2000 initiated change in the legal order of national gas markets. The economic significance of natural gas as primary energy resource for Europe is beyond question. Natural gas in fact conquered the number one position among fossil fuels from an economiccommercial interest perspective as well as from a climate change perspective. Natural gas steadily increased as fuel in the thermal-based power generation systems in Europe as well. The gas industry across Europe is developing new alliances, developing linkages between thus far unconnected gas fields and constructed new pipelines to satisfy increasing demands of European load centres. But have these changes given way to a fundamentally different type of market organisation? Although too early for 'final' answers to this question, the changes and moves in gas markets in Europe can only strengthen the 'general feeling' about an emerging new order in European gas. The newness of the changes does not yet allow for a final scientific evaluation.

1Stern, p.1.

National Reforms in European Gas Change and development of national gas markets in the EU legacy, is the central focus and theme of this book. A national focus on gas market reform is relevant for several reasons. Firstly, natural gas incorporates highly important national interests, economically, politically as well as socially. In gas producing countries, natural gas stands for national asset and national wealth accelerator as the cases of Norway and the Netherlands have shown. Exploitation of the national gas fields is a highly important political issue because of the economic value of the natural assets as well as its social allocation and distribution for gas producing countries. For gas consuming countries, access to gas resources is of crucial national importance. Until now a constant gas flow has been arranged for in long-term contracts assuring reliable gas deliverance for several decades. Natural gas takes a significant share in thermal-based power generation and its share is expected to increase all over Europe. Of all fossil fuels, natural gas is the least hazardous from an environmental (climate change) impact perspective and therefore is facing increasing demand for reasons of convenience and also due to its environmental performance. Natural gas is crucial for the production of many chemical products, some of them such as fertilisers are crucial for food production and supply. Consequently a secure and constant gas flow is highly important for those countries with significant demand markets but not endowed with their own resources and not, or only partly, able to satisfy national demands. Most EU member states are in this position. Countries have built and developed their national gas markets, both institutionally and technically, according to national interest positions. Understanding the institutional and technical background of these national positions, therefore, provides a second set of arguments for developing a national perspective in EU gas market reform. Natural gas started rising as energy resource only some four decades ago and was preceded by a much longer period of usage of gas variants like coal and city gases. In many European countries, the use of the latter underlies the erection and development of the national gas infrastructures, gas pipelines and the institutional organisation of national gas markets. In many countries coal and city gases started their rise at the local level. Gas production was organised in local factories distributing gases through local distribution networks predominantly for residential heating. Production and distribution were vertically integrated activities under municipal control and in many cases perceived as a public task. From the beginning of the 1960s the rise and development of natural gas drew on this technical and institutional heritage of the city gas era. One by one, countries

Introduction

5

changed to natural gas and implemented varied institutional models to organise their domestic gas market in congruence with national interest positions. The national institutional models each in their specific way accounted for the 'failures' of gas markets, such as the high economic risks associated with the exploitation of gas fields and investments in pipeline infrastructures, the positive external effects of gas pipeline infrastructures and natural monopoly characteristics. The latter refers to the relationship between size and decreasing average costs of gas pipelines. 'National gas markets have until recently and with a few exceptions been characterised by vertically integrated companies; national or regional supply monopolies; market demarcations; exclusive rights to import and transport gas; captive customers and the absence of gas to gas competition'. 2 Within this framework, the national institutional models in one way or another all tackled the gas market specifically, including monopoly regulation for consumer protection. In this way a variety of national institutional models developed in Continental Europe. The recently launched harmonisation of the internal EU gas market departs from this variety of national gas market models. These models will determine, at least partly, the new national strengths and weaknesses in the open, harmonised internal gas market that is expected to evolve. National developments to a large extent incubate the prospects of the emerging European order and analysing these national patterns of development therefore, is a third reason for departure from national perspectives in European gas market reform in this book. Next to the international gas industry, national gas markets have been and still are very important in the overall European gas system, despite the fact that today, about 60% of the gas consumption in the European Union crosses at least one boarder on its way to the final consumer. In Europe, gas is indispensably connected with long distance transmission systems connecting the unequally located sources with the load centres in Europe. As stated in the discussion paper of the Joint Working Group '(...), the European gas market has largely been compartmentalised into 15 separate national markets fragmented into even more regional markets' (p. 8). So 'nationalism' instead of 'Europeanism' might be expected to be on the political agenda and a strong determining perspective in the EU harmonisation process.

2joint Working Group of the European Gas Regulatory Forum, p. 8.

National Reforms in European Gas The history of the EU gas directive shows the significance and strength of 'nationalism' as a determining factor in EU political decision making. The debate on gas market harmonisation was a strong case in this regard. For long, the harmonisation proposals of the EU met strong and massive opposition of national gas industries and national governments of all member states, except for the United Kingdom. The United Kingdom developed its own route of liberalisation, clearly ahead of the one discussed by the EU since the end of the 1980s. The initial ambition to liberalise equally the gas and electricity market was dropped in the beginning of the 1990s and only two years after the Electricity Directive the EU managed to agree a gas directive. The compromise could only be found in a rather restricted reach of the gas directive, leaving core issues of harmonisation, such as access regime to the pipeline system, market opening and market regulation, to the discretion of member states. However, despite its limited reach, the gas directive was a necessary step to initiate regulatory change of gas markets in Europe. But it is likely that the change process will continue a national focus: 'Although the effect of the Directive is likely to be positive, in itself it falls short of being a significant driver for liberalisation in European gas markets. What will happen increasingly will be specific developments in individual countries'. 3 Now at the end of 2002 Stern is confirmed in its 1998 prophetic conclusion. The gas directive did initiate legal change of gas markets in Europe, but given the regulatory variety within the EU legacy at the end of 2002, the change process thus far indeed has been guided by a country specific, national, perspective. 4 Consequently a comparative analysis of what is going on in national gas markets in Europe is the relevant way to understand the ongoing changes in European gas. 1.1. Aim and Central Research Question of the Book

Countries engage in the change process from a diversity of national positions. These may differ in respect to institutional background, national interests, access position to resources and position in the European gas chain. With the prospect of a new European gas order, initial strong national positions might weaken whereas initial weak positions may be strengthened. This book provides an overview of recent dynamics in several national gas markets in Europe, in order to 3Stern, p. 102. Sterns provides for an elaborate overview of the history of the gas directive. For a discussion of the content of the directive see Chapter 3 of the book. 4See Arentsen.

Introduction

7

contribute to a better understanding of the trends and dynamics in European gas. In particular, the book works towards a better understanding of the prospects of the emerging new order in the European gas market, by analysis and comparison of national dynamics. How did countries respond to the EU gas directive and why? What are important barriers for a harmonised European gas market in the context of national developments? What can be expected at the European level given the recent trends and dynamics in national gas markets? The focus and scope of the book is national gas markets rather than the European gas market or European gas industry as such. The comparative analysis in the book has been guided by the following central research question: What are the major developments in the structure, technology and socioeconomic performance of national gas industries and what evolutionary patterns might be identified in the European gas market? The basic assumption here is that the developments in European gas can only be properly understood by analysing and understanding the background and characteristics of national gas markets. The authors assume that these characteristics in particular comprise the overall national institutional structure of the gas industry and the gas market, the specifics of the national public interests involved and the performance of national gas markets, in terms of public service obligations and economics. To analyse and compare the national backgrounds and trends, we assume an overall evolutionary oriented analytical framework. This framework has been guiding (not determining) the in-depth analysis of developments and trends in six national gas markets located in the northwestern part of Europe. The book's focus on national gas markets in the context of EU regulation has resulted in the specific selection of the six countries for in-depth analysis. Except for two gas producing countries, Norway and Russia, these countries are all members of the EU and all located in the northwestern region of Europe. This regional bias of the book stems from the origin of natural gas in Europe. The modern era of production and consumption of natural gas in Europe started in the beginning of the 1960s in the northwestern part of Europe. From there, natural gas gradually spread over Europe. Today the northwestern region therefore holds the oldest, the biggest and most matured gas markets and production locations of Europe. The comparatively long history of natural gas in these countries has resulted in a rather strong institutionalisation of gas in national energy policies, which is now severely challenged by the recent EU liberalisation initiatives. Part of the prospect of natural gas in Europe will be decided by the willingness and ability of the oldest and biggest gas markets in

National Reforms in European Gas Europe to reform the national gas market. This makes it relevant in the prospect of the core question of the book to concentrate the in-depth analysis of the book on countries located in the northwestern region of Europe. Norway and Russia have been chosen for in-depth analysis in the book, because of their significance as gas suppliers for the northwestern European gas markets next to the United Kingdom and the Netherlands. Both countries are important gas suppliers of the region and both have a special, but different relationship with the EU. As a member of the European Economic Area, Norway is obliged to comply with European regulation, whereas Russia is not. Russia is however in the prospect of longer-term security of gas supply in the EU region a most significant gas producer and from this perspective one of the most important signatories of the European Energy Charter. So the inclusion of both Norway and Russia enables to analyse the impact of the EU harmonisation initiatives in two of the EU important production regions. The focus on the matured northern gas markets in Europe does not imply a complete neglect of the other gas markets in Europe. Both the southern and eastern European gas markets are included in the book, but these markets have been far less extensively analysed as the markets in the northern region. The core aspects of gas market developments in south and eastern Europe are summarised in two chapters. In this way it is possible to account for developments in both regions in the final evaluative part of the book. Spain and Portugal are rising gas markets as Italy, within the reach of the Algerian gas fields. Some of the countries in Eastern Europe have been nominated for the EU membership and are important as transit country for the European gas supply. So the book's in-depth analysis concentrates on the northern region, but analyses the northern developments in the wider European perspective. 1.2. Structure of the Book

The aim and focus are reflected in the book's structure, which comprises three parts: a general introduction, an extensive empirical in-depth examination of national developments and trends in six gas markets in northwest Europe and a concluding part comparatively assessing and evaluating recent change and development of national gas markets in the EU legacy. Part I comprises four introductory chapters, on the technicalities of gas production, transmission and distribution, and the legal-institutional aspects of gas markets. These introductory chapters provide a clear overview of core issues in gas

Introduction

9

market reform from a technical-physical and a politico-institutional point of view. Chapter 2 provides the basic background on gas market technicalities. The chapter not only introduces the basics of gas technology to the reader not familiar with technicalities of gas, but it also shows the impacts of liberalisation on the economic significance of gas technology. In Europe, natural gas has developed as a network bound energy resource, which has resulted in an extensive European wide system of interconnected pipelines. These pipelines directly connect the load centres to the gas fields in Europe. The European pipeline system has been constructed to secure the supply of natural gas, but this initial functionality of the pipeline system is affected by the liberalisation initiatives of the EU too, like the institutional and industrial organisation of national gas markets. The analysis of the book tried to capture the changing functionality of the gas pipeline infrastructure and this is reflected in the reference to the concept of 'technology' in the key question of the book. Chapter 2 introduces the technicalities of gas production transport and distribution and indicates the changing demands on technology in the prospect of liberalisation and competition. Chapter 3 addresses the legal-institutional aspects of gas market liberalisation and deregulation. The chapter analyses the core issues of the EU Gas Directive in the prospect of gas market harmonisation. It shows the core controversies that have been debated so long and analyses the harmonisation requirements of the gas directive. In this way the chapter gives an overview of the regulatory issues at stake after the acceptance of the EU directive in 1998 and the discretionary powers left to the member states. Chapter 4, the final introductory chapter, develops an analytical framework integrating the technical, politico-institutional and economic aspects of national gas markets. The analytical perspective developed in Chapter 4 draws on neoinstitutional approaches in economics and political science. It distinguishes three ideal-type 5 gas markets, each reflecting technically, institutionally and economically a particular focus in national gas policies. Three ideal-type gas models have been conceptualised: the public property model, the public utility model and the commodity model. In the book these models serve two purposes. Firstly, the models have been used to select the countries for analysis in the book and secondly, the models structure the empirical analysis of national developments and their comparative analysis for the final chapter of

5'Ideal-type' is meant here in the Weberian tradition.

10

National Reforms in European Gas

the book. The three models are used to group case study countries as follows: Gas as a public property, for typical gas-producing countries like Norway and the Netherlands. Next to these traditional European gas suppliers, the book also holds a non-European gas producing country, highly significant for the current and future European gas market, Russia. Gas as a public utility, covering gas market developments in typical gas consuming countries without extensive domestic gas reserves, such as Germany, France, and the United Kingdom at the end of the 1980s, when the country was about to enter the period of deregulation. Gas as a commodity, covering fully liberalised and open market conditions and therefore for the moment basically to be considered only something as a converging perspective for national gas markets in Europe. Currently (end 2002), several national gas markets in Europe show changes in the direction of the ideal commodity model. The British gas market could be considered as a market in Europe currently taking a leading position in the liberalisation process. The British market is opened, entrance barriers have been relieved and the British have introduced gas to gas competition. These are some of the aspects of the commodity model as conceptualised in the book. The in-depth analysis of the six national gas markets in the second part of the book is complemented with summarised analyses of developments in the southern and eastern part of Europe. The chapter devoted to South Europe includes the Italian, Spanish, Portuguese and the Algerian gas market. The latter market is included because of its significance as gas producer of Europe. The summarised analysis of Eastern Europe includes the gas markets of Czech Republic, Hungary, Poland and Slovak Republic. In the third and final part of the book, the three ideal type gas market models are used to structure a comparative analysis of national developments and discussion on the prospects for a new order in the European gas market. The final chapter analyses and assesses important trends in national developments and the accompanying changing national positions in the European gas chain. These changes are evaluated from the perspective of the emerging European gas market. The book covers several decades of change in national gas markets and contributes to understanding these changes in terms of political preferences, constraints and

Introduction

11

opportunities of the gas pipeline infrastructures and economic and political performances. Due to the harmonisation process, politically initiated by the EU, these changes no longer restrict to national boundaries as they did between the 1960s and 2000. In the coming decade national governments, the EU and the European gas industry is challenged to establish an open European gas market and therefore all challenged by a perspective beyond 'nationalism' in favor of 'Europeanism'. The next chapters analyse the state of the art of this process. Literature

Arentsen, Politics and regulation of gas in Europe, (2003) forthcoming. Joint Working Group of the European Gas Regulatory Forum, A long-term vision of a fully operational single market for gas in Europe, A draft strategy paper prepared for the 4th meeting of the Madrid Forum 2-3 July 2001, Madrid Stern J.P. (1998). Competition and Liberalization in European Gas Markets. A Diversity of Models. London.

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Chapter 2 The Technological Infrastructure of the Gas Chain WILLEM VAN DER WAL

2.1. Introduction

This chapter provides some elementary information for readers not familiar with the technicalities of natural gas. 1 The production, transmission, distribution and usage of natural gas are bound to specific pipeline technologies. This chapter highlights the major components of the technical infrastructure of natural gas, its production, pipeline system and treatment, taking the Dutch case as an example. After some short introductory notes on the origin and composition of natural gas, the respective sections of the chapter address the technical processing of natural gas along the value chain. These processing activities are complementary, technically as well as economically. Strict coordination of these activities, therefore, is of paramount importance to safeguard high quality supply of natural gas from a technical point of view. The chapter ends with some reflections on the changing context of gas technology in liberalising gas markets. 2.2. The Natural Origins of Natural Gas

Natural gas, widely used all over the world, is an attractive fuel in different respects. It is easy to transport and easy to clean. Furthermore, natural gas has the highest hydrogen carbon ratio of all fossil fuels and when burned or used as feedstock, the exhaust gases hold less CO2 compared to conversion of oil and coal. 1Readers familiar with the technicalities of natural gas can skip this chapter. 13

National Reforms in European Gas

14

Natural gas is a mixture of volatile hydrocarbons, saturated hydrocarbons and unsaturated hydrocarbons of the benzene series. Remains of plants are converted under pressure and over millions of years into oil, carbon and natural gas. Sometimes natural gas is found saturated with oil, known as associated gas and sometimes it is found as dry natural gas. Natural gas, as its name indicates, has a natural origin and for that reason, its substance and composition varies throughout the world. As an example, Table 2.1 displays two examples of the composition of natural gas, as found and distributed in the Netherlands. The local Dutch gas is mainly sold to households and small commercial users, while the high calorific gas is supplied to the industry. The Groningen gas field was one of the first gas discoveries at the European continent and therefore, a frontrunner in European gas supply. The Groningen gas is still widely used in Europe. The North-sea gas is a high calorific (H-gas). H-gas is most often found in the world. In Europe most gas importing countries are gradually converting their pipeline system to H-gas at the expense of low calorific gas (L-gas). Natural gas needs special treatment to allow convenient and high quality usage. Pure natural gas for instance, contains various additional compounds, such as sulphur compounds, hydrocarbon condensate etc., that influence the combustion of gas and its emissions. Therefore additional compounds are removed to meet the d e m a n d requirements of the gas market. The next sections deal with the treatment of natural gas in the different phases of the value chain.

Table 2.1. Compositionof low calorific and high calorific natural gas found in the Netherlands.

Compound Methane Ethane Propane Butane Pentane n-hexane Nitrogen Oxygen Carbon dioxide

Formula CH4 C2H6 C3H8 C4H10 C5H12 C6H14 N2 02 CO2

%v/v Groningen gas (low calorific)

%v/v North Sea gas (high calorific)

81.30 2.85 0.37 0.14 0.04 0.05 14.35 0.01 0.89 100.00

88.17 5.30 1.20 0.38 0.09 0.09 3.30 1.47 100.00

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15

2.3. Exploration Natural gas is a gift from nature and finds its origin in high-pressure conversion of biomass into coal and hydrocarbons. Part of this million-of-years process is due to intensive underground dynamics, which brought the natural gas through porous layers deeper and deeper until it became captured in impermeable layers. Exploration is the first step in the value chain of natural gas and is aimed at tracing the natural gas deep in the earth. This is done in different steps and with the help of advanced technology. As a first step, the area under investigation is subjected to geological research. Currently several methods are used for this type of research, for instance, mapping the area by means of aerial photography or at sea by sonar. Geological research is also possible by means of gravimetric research. This type of research traces natural gas by analysing the structure of the territory. Nowadays a frequently used research method in exploration is seismic research. For this, the reflection of vibrations, induced by small explosions, determines in great detail the structure of the deep underground. This technology developed as a two-dimensional method, but currently threedimensional technology is widely used because of its greater accuracy. Most Dutch explorative research uses three-dimensional seismic technology. Irrespective of methods and technologies, exploration of natural gas is a highly time consuming and labour intensive activity, and expensive. After tracing natural gas in underground layers, drilling techniques must be used to confirm its presence. Only by drilling using the important parameters of the potential gas field can the presence of gas be assessed and reliably determined. These parameters include volume of the gas bearing layer, the porosity, the pressure of the reservoir and the presence of water. With the help of these data the natural volume of the gas reservoir, or the Gas Initial In Place (GIIP), can be determined and, from there, the Economically Recoverable Reserves (ERR) are calculated. On average, the ERR value of a viable gas field is approximately 80-85% of GIIP of the field. Decisions on exploitation of new gas fields must also be considered in terms of production costs. Major cost components in this respect are: Location- The location of the gas field strongly influences production costs. For instance, the exploitation of onshore (mainland) gas fields is less expensive than offshore exploitation in deep-sea areas.

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National Reforms in European Gas

9 Gas treatment c o s t s - Depending on the quality and composition of the gas, special treatment might be necessary to bring the gas up to market quality (for instance, neutralising additional components, such as sulphur, mercury, etc.). 9 Gas quality conversion c o s t s - Depending on its caloric value, the gas might need additional treatment to match common quality standards (e.g., de-condensation). 9 Costs of pipeline infrastructure - Sometimes new gas fields need completely new gas pipelines for establishing a connection with the gas pipeline infrastructure and sometimes existing (upstream) pipelines can be used. 9 Gas p r i c e s - Gas prices decide the yields of exploitation and the profits of the producer. 9 Production c a p a c i t y - On average the cost-effective production capacity is about 5-10% of the ERR. Offshore gas fields are quite common. The Continental Shelf in the North Sea is an important European offshore area, producing gas in deep waters and therefore highly demanding for man and technology. Offshore production is more expensive compared with onshore production due to the specialised technological infrastructure needed at sea. In general, gas production either onshore or offshore, needs tremendous investment before the first cubic meter of gas can be produced. For that reason, gas fields are not taken into production without certainty about the sales of the gas. The huge investment in production facilities as well as in gas pipeline infrastructures to a large extent explain the tradition of trading natural gas only on the basis of long-term contracts. Only with these kinds of economic conditions, ascertaining return on investment, are companies willing to invest in the exploitation of gas fields (Clegg et al., 1993).

2.4. Gas Processing A first step in processing the gas is the removal of additive components, such as sulphur compounds, mercury and water. A second step is the specification of the gas quality in line with the contractual requirements. Specification of gas quality means the removal of higher hydrocarbons and water to prevent formation of hydrocarbon condensation, corrosion and methane hydrates in downstream transportation pipelines. Especially prevention of methane hydrates formation is important because this causes plugging. In this way, gas is processed in so-called gas-processing plants. These kinds of plants might hold water, hydrocarbon and CO2

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17

removal units, depending on the basic composition of the processed gas. Some pure gases also need treatment in a desulphurication unit.

2.4.1. Removal of hydrocarbons and water Higher hydrocarbons and water can be removed from the natural gas either by absorption or cooling. As an example, Fig. 2.1 gives a schematic overview of this kind of processing of the low caloric Groningen gas. In the gas processing plant the high pressure of the Groningen field is used to eliminate higher hydrocarbons to prevent the formation of condensate. Depending on the production capacity, the Groningen field produces gas at about 110bars and 75~ In the first step the gas is cooled to 40~ enabling high pressure separation of the formed water and oil parts and the gas. In the next step glycol is added for water absorption. Then the gas is further cooled in the heat exchanger from 40~ to 6~ and depressurised in the choke from 110bars to about 75bars. Due to the pressure drop, the gas temperature falls from +6~ to -12~ Consequently higher hydrocarbons and water separate from the gas in the Cold-separator. A final filtering removes remaining water and oil. Finally, gas temperature is raised to 22~ and is ready for feeding in the network. The natural pressure of the Groningen gas field decreases every year and within a couple of years the pressure will be too low for feeding into the cleaning process displayed in Fig. 2.1. In anticipation of this pressure drop in the gas field, the choke can be replaced by a

Fig. 2.1. Schematicoverview of the gas processing plant at the Groningen field.

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National Reforms in European Gas

propane cooler, which is displayed by the dotted line in Fig. 2.1, or by absorption units, with absorbents for hydrocarbons, such as silica. At offshore gas production sites the processing or treatment of pure gas in general is restricted to removal of water to prevent corrosion of and the formation of methane hydrates in the pipelines. After this partial offshore treatment, the gas is transported onshore for further treatment as displayed in Fig. 2.1. Full offshore treatment of pure gas is prohibitively expensive. However, the partial offshore treatment of the gas affects the upstream pipeline system with liquid hydrocarbons, which reduces the capacity of the pipelines by about 15-20%.

2.4.2. Removal of C02 and sulphur compounds With a few exceptions the sulphur (H2S) content of the Dutch natural gas is rather low. Only gas from some minor small gas fields in the eastern part of the country contain sulphur. French gas from the Lacqfield in the southwest of the country contains about 10% of H2S. H2S must be removed from the gas because it is highly poisonous and causes hazardous air emissions when converted by combustion in SO2. Furthermore, natural gas used as feedstock might result in CO2 and H2S, which could cause corrosion of the production equipment's steel components. Thus, natural gas must be completely disposed of H2S. CO2 only need be removed if the concentration exceeds a 3% threshold. H2S and CO2 are removed by gas washing processes, such as Sulfinol, Selexol. The Sulfinol process, for instance, based on absorption, removes H2S and CO2 by contacting both with a counter current flow of liquid absorbing both in an absorber. At the top of the absorber the clean gas is dried by Glycol and subsequently fed in the transport pipelines. The liquid holding the absorbed H2S and CO2 is regenerated with steam. From the top of the regenerator a concentrated flow of CO2 and H2S is fed into a Claus plant, where H2S is converted to basic sulphur. 2.5. Gas Storage and Gas Transmission

2.5.1. Gas storage in the European Union Storage of natural gas is very important for facilitating a constant balance between gas supply and gas demand under all circumstances. Gas demand fluctuates during the hours of the day, and with the changes of season. Gas consumption on a cold winter day can sharply differ from gas demand on a hot summer day. The gas system must

The Technological Infrastructure of the Gas Chain

19

be able to meet the strong fluctuations in gas demand and storage capacity is very important in this respect, and therefore an important component of the gas pipeline system. Figure 2.2 schematically depicts European seasonal gas demand. The figure gives the capacity in gas supply as a function of seasonal demand. The curve shows the much higher gas demand in winter compared with other seasons. The gas system must be flexible enough to meet these demand fluctuations. Additional storage capacity is needed, especially in winter to satisfy large gas demand at a distance from the production site. Under these circumstances, the pipeline capacity in general is insufficient to meet peak demands at a large distance from the well. By pumping gas from the storage facilities in the pipeline system these peak demands can be met. The right of Fig. 2.2 lists the hierarchy of peak shaving facilities under different circumstances. Under conditions of increasing gas demand, base-load supply by the transportation pipelines might not be able to meet the demand and therefore the gas system will need additional input of stored gas. Gas storage in depleted gas fields and aquifers meet these large-volume low-capacity additional gas demands. This type of storage capacity captures the gas in porous layers covered by an impervious layer. If the gas demand further increases, gas stored in salt caverns is pumped into the system. Salt cavern gas storage allows short-term high-pressure input into the gas system. Extreme peak demand in general is met by a feed-in of Liquid Natural Gas (LNG) or by the temporary interruption of gas supply to giant (industrial) consumers, which are able to switch flexibly to alternative fuels such as LPG, air mixtures or fuel oil. Underground gas storage is a kind of vessel which captures the gas at a certain pressure (Underground Gas Storage in the World, 1995).

l

LNGIInterruptible contracts Salt caverns Depleted gas fields/ aquifers

Capacity Base load

Summer

Autumn

Winter

Spring

Summer

Fig. 2.2. A schematic representation of European seasonal demand of Natural gas.

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An effective supply rate from the gas storage to the pipeline system to a large extent is determined by the rate of independence of the pressure of the stored gas and the inherent pressure of the storage facility. Independence, of both types of pressures, is achieved by keeping the pressure of the storage facility constant with the help of large volumes of natural gas as working pressure of the storage facility. This so-called cushion gas is part of the storage facility and therefore cannot be produced. In addition to this cushion gas, the storage facility is filled with the working gas to be used for peak shaving. Typical cushion gas to working gas ratios are 4 for depleted gas fields and aquifers, and 1 for salt caverns. Gas storage also offers other facilities and flexibility, which are beneficial from an economic point of view. Gas traders can use stored gas to decrease contracted swings, allowing low price gas purchase in summer and high price sales in winter. Further, the storage facility can be leased. These examples point to the economic significance of storage capacity in addition to peak shaving, especially in liberalised gas markets. Table 2.2 gives an overview of the storage capacity in different European countries. The table lists storage volume as a percentage of the consumption and the supply capacity of the storage in million mg/day.

2.5.2. Different technical qualities of natural gas This section explains the quality aspects of natural gas and their treatment for transport and distribution based on Dutch data. The Groningen gas as well as the gas from the small gas fields on the Dutch part of the continental shelf, all have specific qualities. The Dutch distribution system and the majority of Dutch gas consumption has been standardised to a specific gas quality, the so-called pseudoGroningen gas quality. Gasunie, the central Dutch gas coordinator, Table 2.2. Gas storage facilities in Europe.

Country France UK Belgium Germany The Netherlands Italy Denmark Austria

Number of storage facilities

Capacity of workinggas (bcm)

15 7 3 34 4 8 2 5

10.5 4.2 0.6 12.3 8.1 14.6 0.6 2.6

Storageas % of Supplycapacity consumption (mcm) 26.9 5.0 4.3 13.8 18.8 24.6 14.3 30.6

182 166 23 272 215 263 18 27

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21

Fig. 2.3. Cv values and Wobbe indexes of gases supplied to Gasunie. developed a system for blending all gas qualities supplied to Gasunie to this pseudo-Groningen standard. Figure 2.3 displays the calorific values and Wobbe indexes 2 of gases supplied to Gasunie. The Wobbe band specifies the quality range (Wobbe-index) for Dutch gases, for safety reasons all gas distributed in the Netherlands must meet this Wobbe-index. Lower or higher values are risky; as a higher Wobbe index the gas will form carbon monoxide, and lower index will cause lifting of the flame during combustion of the gas. To ascertain nationwide uniform gas qualities within the Wobbe band, Gasunie divided the country into different quality regions. Blending stations in these regions converge the different gases into the valuerange of the Wobbe band, with their distribution restricted to the quality region where they have been blended. In this decentralised system of blending, each quality region has its own quality standards, determining the calorific value for in the region. Uniform nationwide quality standards as deployed in the Netherlands, are rather exceptional in Europe. Most European countries do not convert high calorific gas (H-gas), but instead distribute it as H-gas to specific areas. For instance Brussels and its surrounding areas use Groningen gas, whereas the western and the eastern part of Belgium use H-gas. Other European countries such as Germany, France and Italy use different gas qualities in parallel as well.

2The Wobbe index is a measure of the combustion velocity of the gas.

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National Reforms in European Gas

2.5.3. Transformation of gases in transport and distribution Figure 2.4 shows a schematic representation of a typical gas transport and distribution system. The black square at the top of Fig. 2.4 represents the production site of the gas. Gas appears under high pressure at the well-head. After treatment, the gas is ready to be fed into the gas pipeline network. At the Custody Transfer point, the gas is transferred from the gas producer to the gas transmission company. At this point the pressure of the gas is between 67 and 80bars, the transmission pressure of the high-pressure Dutch national pipeline system. Friction between the transmitted gas and the pipeline reduces the initial gas pressure in the pipeline. Compressor stations geared by gas turbines and fuelled by the transmitted gas, along the gas network keep the gas transmission on pressure. For example, 50% of gas transmissions from Russia to Europe must be fuelled for pressure maintenance in this long-distance pipeline. Maintenance of adequate pressure levels can be rather costly, especially in long distance transport of gas. At M&R stations, gas enters the regional transport networks, which in general are high-pressure distribution networks. At these transfer

Fig. 2.4. A schematic representation of the Dutch transport and distribution network.

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23

points the gas is odorised for safety reasons and the pressure is reduced from 67 to 40bars. Regional transport networks directly supply for large gas customers, for instance power producers, large industrial sites and local distribution companies (LDCs). At the Gas Receiving Stations (GRS) of local distribution companies the pressure is further reduced and gas is further odorised with THT. The transfer points of local distribution companies are called Feeder Stations. In most European countries the distribution network of LDCs does not exceed pressure levels of 20 bars. In the Netherlands the highest pressure used in distribution is 8 bars and in Germany 16bars. In the LDCs distribution network the pressure is further reduced from 8 bars to 4 bars at the Supply Station, via two bars or 100 mbar when the gas reaches the residential end-consumers. The transmission and distribution systems in most European countries are the same as those in the Netherlands. Parts of the HTL network are LNG peak shaving installations and Underground Storage facilities, explained above. Rotterdam, in the western part of the Netherlands, holds a LNG installation, which is unlike the Zeebrugge terminal for overseas landing of LNG, but is rather a storage facility for peak shaving. Gasunie produces LNG from spare gas during the summer and stores it in the Rotterdam installation and therefore, this installation can be used only once every winter. 2.6. Gas T e c h n o l o g y in a Liberalised Gas Market

The prospect of liberalisation will change the economic significance of gas technology. Figure 2.5 schematically displays the gas chain in liberalised gas markets. Figure 2.5 displays the separation between the physical gas flow and the commercial interactions among the players in liberalised gas markets. As for the regulated monopoly market, in a liberalised gas market gas still finds its way to the end-consumer via the transmission and distribution pipeline system. In liberalised markets, traders (often called shippers and suppliers) are the link between gas consumers and gas producers and are responsible for transport and distribution agreements. These traders must have access to the pipeline system, but the operation and the regulation of the pipeline system itself is as per the monopolistically regulated gas market. Traders are wholesale traders and the suppliers the retailers. Traders can trade with end users such as power producers and industries. For large end-consumers low costs are very important and trade in this segment of the gas market will be cost and price driven. It might be

24

National Reforms in European Gas Producers

Network company transport ,,

,

@_1 4 - - --- --I~

Traders . . . . . .

distribution

Power production

Industry

Suppliers,.i

.l T

Households

Fig. 2.5. A schematic representation of the gas chain in liberalised gas markets.

expected that the residential market will be more service driven instead of price driven as in the industrial segment of the gas market. The two types of services indicate this in Fig. 2.5, one is connected with wholesale and the other is connected with retail and supply. Services for traders include underground storage, blending, odorisation, balancing of input and output, etc., while suppliers require services such as short-time storage, take back of electricity from combined heat and power generation (CHP), consultancy, pooling, etc. Balancing is especially important for maintaining the integrity of the transport system, which requires a constant match of input and output in the system. It is expected that liberalisation will commercialise the service activities in the gas market. In a liberalised market, the tariff for transport and distribution of natural gas should reflect the real costs of transport, plus a fair rate of return for the system operator. For reasons of price transparency, it is important to distinguish the different cost-components of natural gas in a liberalised gas market. From the costs of the commodity itself, to the price of a cubic metre of natural gas at the delivery point, tariffs therefore have to reflect the costs of transport and capacity. For that reason gas transport companies in different European countries

The Technological Infrastructure of the Gas Chain

25

developed a tariff-system for the transmission and distribution of natural gas. In the regulated market the costs of transport were an integral part of the cost of a cubic metre of gas, but as previously indicated, in a liberalised market gas supply and gas transport no longer are integrated activities of one company. Under liberalisation the costs for transport and volume are separated. The tarification of gas transport is still one of the core regulatory issues in Europe and the national tarification system is a core problem in international gas trade in Europe. For instance, Ireland uses a non-distance related transportation tariff and daily balancing, while Spain and the United Kingdom combine daily balancing with a distance-related tariff system for transport and capacity. The Dutch Transportation Company Gasunie, combines hourly balancing with a Commodity Service System (CSS). This tariff system charges separately for transport (distance related), capacity services and commodity delivered by Gasunie. 3 In regulated gas markets, the commodity price of natural gas was strongly related to prices of alternative fuels, such as crude oil. For liberalised gas markets, gas prices are expected to reflect more the demand and supply of gas. This is called gas-to-gas competition. The commercial interest of the liberalised market is basically cost reduction and this can be achieved either by gas-to-gas competition or by lowering capacity costs. The latter implies detailed knowledge of the load-pattern of end-consumers. For instance, peaks in the load-pattern are relatively expensive due to the capacity charges. Flattering supply as much as possible by peak shaving can reduce these capacity costs. Here the peak shaving options, discussed above can be applied: interruptible contracts, addition of LPG/air to gas or replacement of gas by LPG/air. It is also possible to install buffer tanks (storage capacity) at the premises of end users. In a liberalised market, providing these services and technologies becomes part of the commercial relations between the trader/supplier and the end-consumer. There are more reasons for detailed knowledge of the consumption, or supply pattern of end users in a liberalised gas market. In the Netherlands traders and suppliers must balance input and output in the pipeline network of Gasunie. This means that the trader must put the same amount of gas into the pipeline system as the customer takes out. This obligation forces the trader to monitor the gas intake of the customers and to intervene when the intake exceeds certain limits.

3The report of PHB Hagler Bailly Ltd, gives a good overview of the transport tariff system deployed in Europe.

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National Reforms in European Gas

If, for instance, a customer takes more gas from the system than agreed, the system pressure will drop and the network company (Gasunie) must supply gas from its own sources, to maintain adequate system pressure. When the intake of gas of the customer is too low, Gasunie must depressurise the pipeline system. Gasunie penalises traders for both actions. For that reason it is important to know in great detail the supply pattern of customers, to prevent deviations from the system input-output balance as much as possible. Many customers, such as households, small commercial users, etc., have temperature-dependent gas intake and therefore, the supply pattern is standardised. Large consumers, such as fertilizer industries, etc., however, use gas as a feedstock with their gas intake independent of temperature. This group has a non-standard supply pattern and therefore gas intake must be monitored continuously. The gas intake of the group in between must be partly monitored and partly estimated on the basis of temperature.

2.6.1. Prospects for gas transport in liberalised gas markets Before liberalisation, the gas market was predominantly nationally focussed and regulated in context of national interests. In a liberalised gas market this is expected to change. Liberalisation of the gas markets in Europe was preceded by deregulation of the gas markets in the United States. Some of the changes in the US might give some indication about the prospects for Europe. Because of the governmental regulations it was rather unattractive to sell gas outside a gas producing state in the US some ten years ago. Non-producing states therefore, suffered severe shortages, putting industry in these states in a disadvantaged position. To mitigate this situation, the federal government decided to deregulate the gas market. The regime imposed on the gas market was regulated TPA 4 falling under the auspices of the Federal Energy Regulating Committee (FERC). Additionally, every state has its own regulating authority. Due to the large influence of the state, regulation can vary considerably between different states. In Georgia, a network company is not allowed to supply gas to individual customers, whereas in Illinois the network company may supply gas to individual customers when it can demonstrate that its cost structure is competitive and that customers benefit from it.

4Regulated Third Party Access allows third parties, such as traders and shippers, to use gas pipelines for transport and distribution of natural gas.

The Technological Infrastructure of the Gas Chain

27

In the US, natural gas is found in the southern and western parts of the country. However, the large gas consumption areas are located in the northeast, the New York area, and in the north midwest, the Chicago area. Gas is transported via interstate pipelines, from the wells, through various states to the target areas. Producers, active in the various production areas, are inclined to transport their gas to areas where much gas is used. In places where a number of interstate pipelines meet, a 'Hub' is formed. A hub is a trading point with many buyers and sellers, where abundant transport infrastructure is available, where storage and balancing services are offered and hub operators facilitate administrative processes. In the US there are several hubs, such as the Chicago Hub, Henry's Hub, etc. The Chicago Hub, interconnects six interstate pipelines. In this area there are seven aquifer storage fields and the normalised annual deliveries are about 15.5 bcm. Services provided by hub operators are, for example, short time park services, which implies that gas is held up for a short time for a trader. At the underground storage fields, hub operators are able to switch from production to injection within one hour. Other services are loaning, wheeling and balancing. These services comprise respectively short time loaning of small quantities of gas, transport of gas through the supply area of the hub operator and balancing of input and output for individual traders. All these new services can only be delivered thanks to the presence of gas storage capacity. Therefore, underground storage must be considered as an economic key factor in liberalised gas markets. As in the US gas hubs are developing in Europe too. At Zeebrugge the Zeepipe I and II from Norway and the Interconnector from the UK come together and are connected to the European gas network. Distrigaz has constructed several pipelines from Zeebrugge to France, Germany and Holland and a LNG terminal in Zeebrugge. The essential storage facilities, however, are not yet fully developed. Other places in Europe which are qualified to be future hubs are northern part of Italy (where gas from Algeria, Russia, the Netherlands and Norway comes together); the north of France (near Dunkirk, a hub is under construction). Here the NorFra pipeline from the Norwegian continental shelf enters France. New pipelines are constructed from Dunkirk to Paris and from Dunkirk to the Swiss border near Basel. New interconnections with pipelines from the North of Europe to Italy are under construction in Basel. In the southwest of France, an interconnection between Spanish and France networks is constructed (LACAL). The area of Marseilles holds a large LNG terminal landing LNG from Algeria. An interconnection between the terminal and Italy

28

National Reforms in European Gas

is planned. All these interconnections and pipelines could strengthen the French position in European gas trade, if the French liberalisation policy would be more advanced than it is now. Germany is another promising candidate for developing a strong trade position because in this country too, gas from different production regions comes together. In the Northern part of Germany, several pipelines from Norway enter Germany at Emden and gas from Russia enters Germany at Frankfurt, Oder and in Bavaria. Germany has direct connections with the large gas fields in Norway and Russia, which have potential for a giant European hub in Germany. Finally, Gasunie is still considering constructing a second interconnector (Bacton, Wieringermeer) between the United Kingdom and Continental Europe. The prospects for this 'Hub-Holland' are however not that promising given the hubinitiatives in Belgium, Germany and France (Johnson, 1997).

2.6.2. Supplier services in liberalised energy markets Storage Supplier competition in a liberalised market is likely to concentrate on peak-shaving services to reduce capacity costs of transport. Liberalisation might offer new opportunities in this regard. In the Netherlands, for instance, the LDCs have installed many CHP units in order to shave the peaks in their power off-take from the central production units. These CHP units have been installed at the premises of large (industrial) consumers. Under liberalisation the end-consumer could make an arrangement with the owner of the CHP unit for peak shaving of his own gas demands. In combination with heat storage facilities at the plant, the peak shaving would be very attractive for both the LDC and the endconsumer. The potential for this kind of services however will depend on the services (short time storage, line-pack, CHP, LPG/air supply) the network company (Gasunie) can provide. Green energy Climate change and sustainable development have highlighted the importance of green energy in the Netherlands as elsewhere in Europe. In the electricity market this is manifested by the renewable based technologies, such as PV, wind and biomass. In the gas market, ECO gas seems to be a promising development. This gas can be produced in several ways. One method is to adapt landfill gas to distribution quality. This is already done in the Netherlands by means of the adjustment of the CO2 content of the landfill gas by processes such as a waterwash, pressure swing adsorption or membranes.

The Technological Infrastructure of the Gas Chain

29

The upgraded gas is injected into the distribution system of the LDCs. A second method of producing ECO gas is the gasification of biomass followed by methanation. The thus produced Synthetic Natural Gas (SNG) is brought to specification by blending with nitrogen, thus meeting the quality standards of natural gas. Under liberalisation, suppliers can produce and supply ECO gas as a new service, additional to the supply of natural gas. Hydrogene gas

Another development, also induced by climate change (and the Kyoto Agreement), is the introduction of hydrogen/natural gas mixtures in gas distribution to lower CO2 emission. Extensive research on appliances available in the Netherlands show that 8% hydrogen in natural gas does not affect the combustion characteristics of the gas. Hydrogen can be produced by gasification of biomass followed by the water-gas shift reaction, converting CO with steam into CO2 and hydrogen. The origin of the produced CO2 is non-fossil, and therefore its atmospheric emission will not have a negative green house effect. An alternative method for producing hydrogen in an environmentally friendly way is the CB&H process of the Kvaerner Company in Norway. In this process, natural gas is converted to hydrogen and carbon black. The solid carbon black can be used in several processes and is not vented as CO2 into the atmosphere. One Dutch LDC extensively explored the feasibility of this process and is currently conceding its introduction in the Netherlands. These kind of green developments may benefit from a liberalised gas market with suppliers offering green alternatives to natural gas. In this way, gas produced from renewable sources could be distributed via the existing gas pipeline infrastructure. This could change the function of the network in the longer run from a supply network to an exchange network. Literature

Clegg et al. (1993) The Gas Chain Concept, presented at The College of Petroleum and Energy Seminar, Oxford, June. Johnson, D. (1997) Trans European Energy Networks. Financial Times Energy Publishing. PHB Hagler Bailly Ltd. (1999) Gas carriage and third party transmission in Europe, a report for NV Nederlandse Gasunie, May. Underground Gas Storage in the World. (1995) A new area of expansion, Cedigaz.

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Chapter 3 Harmonisation of European Gas Markets: The EU .Gas Directive LEIGH HANCHER

3.1. Introduction

After prolonged discussion over almost 8 years, the EU Energy Council finally reached a compromise solution and unanimously adopted a common position on the Commission's proposed draft Directive on common rules for the internal gas market on 9 December 1997. The Directive 98/301 entered into force in the majority of member states on 10 August 2000, although some countries had already adopted liberalisation measures in interim. The measure complements EC Directive 96/92 on the internal market for electricity (O.J. 1997 L27/20) and is in many ways similar in scope and structure. These ostensible similarities should not obscure important differences, however, which could well prove to hinder the future development of the internal gas market. The Directive, which as we shall see is a cautious one, establishes common rules for the transmission, distribution, supply and storage of gas. As such it is essentially aimed at the 'downstream sector' and is designed to allow access to transmission facilities for certain categories of 'eligible consumers' and their suppliers. It also provides for a m i n i m u m degree of accounting unbundling so that companies will be required to keep separate internal accounts for various activities. Importantly, the Directive 98/38 does not require any structural managerial separation between transmission and other related activities: hence the gas merchant and transmission functions can still be combined in a lo.j. 1998 c91/46 as amended by O.J. 1998 C181/20, and finally published in O.J. 1998 L 204/1. 31

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majority of markets. This is arguably one of the major weaknesses of the measure, and the consequences of the failure to require such separation will be addressed below. 2 The Directive 98/30 is cautious in scope and indeed is far-less reaching than its already cautious counterpart for electricity, but the measure recognises some important derogations for areas or regions with little or no gas infrastructure, as well as the possibility of temporary exemption from the rules on access to the market where this would threaten the performance of take-or-pay (TOP) obligations. This chapter will first discuss market opening, and analyse the various exceptions. It will then go on to examine what type of pipelines are covered by the Directive's access requirements, and in this context it will turn to the issue of regulatory supervision of the gas market. Finally, the article will discuss whether there is anything to be learnt from the experience of electricity market liberalisation, and in this context examine the Commission's proposals to revise Directive 98/30 which are currently before the European Parliament and Council.

3.2. Market Opening Like its forerunner, the Electricity Directive, the Gas Directive seeks a gradual liberalisation of the EU gas market and hence a gradual introduction of gas-to-gas competition. Discussion about the minimum threshold for market opening proved particularly difficult in the case of gas, however, as gas penetration and use in some member states is far greater than in others. Thus a strictly quantitative approach was always likely to lead to a very uneven degree of market opening in practice. Article 18 adopts a complex formula based on minimum and maximum quantitative criteria, together with the qualitative criteria for designating so-called 'eligible customers'. Large consumers using more than 25 million m 3 became free to select a supplier of their choice as of the date of entry into force of the Directive, as will electricity producers, irrespective of their annual consumption. This threshold will be reduced to 15million m 3 after 5 years and 5million after 10 years. Member states must achieve a minimum level of opening of their market of 20% in 2000, and this should increase to 28% after 5 years and 33% after 10 years. However, in order to safeguard the

2The Electricity Directive 96/92 requires managerial unbundling so that the transmission service operator (TSO) functions independently from any other activities in a vertically integrated company. The Commission has made it clear to Member States that this means that the TSO should have sufficient resources - both financial and h u m a n - to operate its own independent commercial policies.

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interests of those member states with relatively limited gas market penetration or with a concentration of eligible customers in the high threshold bands, the measure also allows member states to impose maximum ceilings on market opening. If the qualitative approach results in a market opening in excess of 30% of the total annual gas consumption on the national market, the member state concerned can modify the definition of eligible customer so that market opening is reduced to 30% of total annual national consumption. This 'ceiling' should increase to 38% after 5 years and 43% after 10 years. The measure expressly provides that any member state can adjust the definition of an eligible electricity producer by linking its consumption to the thresholds for large consumers. This could thus exclude smaller combined heat and power producers (CHP) from taking advantage of access. This compromise appears to sit uneasily with the Resolution of the Energy Council of December 1997 to promote CHP in the EU. If this strategy is not sufficient to keep the member states within the maximum thresholds, then the definition of eligible can be modified further, albeit in a 'balanced' way, which should relate to types or classes of customers (see Art. 18(5)). The various national definitions must be published annually and approved by the Commission (Art. 18(9)). It would therefore seem that the member states should only be able to modify their definitions of eligible customers once a year, and cannot realign their criteria for defining eligibility at any time they choose. Nevertheless, these complex provisions will make it difficult for investors to predict whether new gas-fired plant will or will not qualify for access to competing supplies of gas. It may however be concluded that a government cannot vary the classes or types of consumers deemed eligible in such a way that a customer can be eligible one year but lose this privilege in the future. This would result in a 'specific disadvantage', which is expressly forbidden by Article 18(5). As with the Electricity Directive, the Gas Directive seeks to deal with imbalances between different national markets that result from different approaches to defining eligibility by incorporating a similar, vaguely worded provision on reciprocity (Article 19(1)(b)). The wording is similar to the problematic Article 19(5) of Directive 96/92, where a transaction is refused because a customer is only eligible in one of two systems, the Commission can oblige the refusing party to execute the requested gas supply at the request of the member state where the eligible customer is located. It is important to stress that this power is reserved to the Commission alone, and would only appear to deal with situations in which the refusing state is the less liberalised of the two. It does not allow member states to restrict unilaterally imports from less liberalised countries. It is however

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unclear whether the Commission is entitled to use this p o w e r against a m e m b e r state that has adjusted its o w n national definition of eligibility to keep it within the quantitative criteria described above. As the Commission's p o w e r is discretionary, it is unlikely to be willing to use it to force a country to open u p its market b e y o n d the thresholds imposed by the Directive itself. This offers little solace to countries that want to move faster than the rest, and for example, allow their distribution companies to qualify as eligible. However, given that national gas production within the EU is confined to a few m e m b e r states, the impact of imbalanced market opening is perhaps not so problematic as could be the case with electricity. For national gas s u p p l y companies, such as Gasunie or Ruhrgas, threatened by w h a t they perceive as unfair competition from an overabundance of competing suppliers w h o can access their own more liberalised markets without fear of retaliation in their o w n home markets, they can seek to invoke the provisions on TOP.

3.3. Take-or-Pay (TOP) Contracts Recital 30 to the Directive recognises that TOP (take-or-pay) contracts are 'a market reality for securing the gas s u p p l y of m e m b e r states' and that provision must be m a d e for derogations from certain provisions of the Directive in the case of a natural gas undertaking which is or w o u l d be in serious economic difficulties because of a TOP obligation. 3 These derogations m a y apply to pre-Directive TOP contracts as well as those entered into or renewed after its entry into force. The latter however, must be p r u d e n t l y concluded in order not to h a m p e r a significant opening of the market. The concepts of 'serious economic difficulties' and 'prudence' are nowhere defined in the Directive. Although the former concept is to be found in the EC Treaty rules on state aids (see Article 87 (3)), it has been very strictly defined in that context, and state aids practice will probably be of little guidance to TOP contracts. It will be up to each m e m b e r state to give m e a n i n g to these nebulous terms. It might be noted that the Directive expressly rules out situations of serious difficulties w h e n the contract sales do not fall below the level of m i n i m u m off-take guarantees, or

3The Directive does not offer a definition of a TOP contract but typically such contracts require that the buyer must take a specified minimum volume per year or pay a shortfall for any quantity not taken. Such contracts are highly beneficial to gas producers because they ensure a regular cash flow over a long period. This could be necessary to finance the infrastructure of the gas production project. Traditionally the buyer enjoyed the advantage of security of supply.

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where the relevant TOP contract can be adapted, or where the natural gas undertaking is able to find alternative, economically viable outlets. Clearly m u c h will d e p e n d on h o w m u c h room the original contract allows for re-negotiation on prices and volume. M a n y of the more m o d e r n TOP contracts do provide for adjustment on both matters. 4 An important issue will be w h o is entitled to see these contracts to check their terms, and in particular whether the Commission is likely to enjoy such privileged access. Article 25 provides that a c o m p a n y which experiences or considers that it is likely to experience serious economic and financial difficulties because of take-or-pay commitments can apply for a temporary derogation from the Directive's requirements on access to the m e m b e r state concerned or a designated competent authority. Each country can elect whether to allow applications - always on a case by case basis to be considered before or after refusal of access to the system and m a y also give the relevant national gas u n d e r t a k i n g the choice to present an application before or after refusal of access. In other words, a m e m b e r state could allow its incumbent gas merchant c o m p a n y to first refuse access, and then consider the application. There are no detailed time limits for these procedures, but the member s t a t e / c o m p e t e n t authority must forward a s u m m a r y of all the relevant information (but not necessarily the contract itself) that has informed its decision to grant a derogation to the Commission. The latter can reverse or a m e n d the national decision within four weeks from receipt of this summary. One can imagine some scope for further prevarication here, as Commission and m e m b e r state negotiate over whether all the relevant information has been supplied or not. Although vague and permissive on the matter of timing, Article 25 is clearer on the question of the criteria to be taken into account, criteria which are intended to balance the interests of the incumbent firm, transmission undertakings, and eligible customers as well as wider matters including security of s u p p l y and the impact of the derogation on the application of the Directive itself. The nine specific sets of criteria could however be interpreted in such a w a y that a country with a more liberalised market could seek to rely u p o n them to justify closing its borders to supplies from less liberalised m a r k e t s hence achieving the power to deal with market imbalance denied by Article 19(1 ). 4Traditional contracts usually contain clauses to protect the parties against unfavourable variations of market prices: i.e., price re-opener clauses and price escalation causes. It remains to be seen whether the price re-opener clauses in Western European contracts do in fact permit the clause to be triggered in the event of gas-to-gas competition.

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The derogation must be temporary, although again there is no concrete guidance as to whether this should mean until the relevant TOP contracts expire, or until a satisfactory solution can be negotiated between the parties or indeed until the member state in question devises a suitable method of apportioning outstanding TOP liabilities. Additionally, Article 26 allows two further possibilities of d e r o g a t i o n s - for countries without direct connections to other systems and for 'emergent markets' (see also recital 31 of the Directive). First, member states without direct connections to another member state, and who have only one main supplier with a market share of more than 75% are allowed to derogate from the requirement to specify lists of eligible customers or to allow the construction of direct lines (Art. 20), or to grant permits or authorisations for the construction of new pipelines, storage facilities, etc. (Art. 4). Second, an emergent market, that is a national market which was first supplied by way of long-term gas supply contract not more than 10 years before the entry into force of the Directive, may also be protected from competition; and if the member state concerned anticipates substantial problems not associated with TOP commitments, it can derogate from Articles 4, 18 and 20. In both cases the Commission must be notified. These derogations expire automatically once the relevant conditions no longer apply. The Commission and not the member state, however, has the sole right to grant a similar form of derogation in the case of 'geographically limited areas' if the implementation of the Directive would cause substantial difficulties in that area or would affect the development of the transmission system. Although Article 26(4) specifies certain criteria for the Commission in granting such a derogation, a derogation may only be granted if no gas infrastructure has been established in this area, or has been established for less than ten years. The Commission considers that this Article is limited to transmission investments and cannot provide a basis for derogations in relation to investments in the distribution sector. The application of derogations for emergent markets, whether national or local as well as for systems with limited interconnections, means that no eligible customers need to be designated for the entire period. Thereafter the first stage of the minimum threshold system will apply, i.e., 20% of national annual consumption, and this will be gradually increased over periods of five years, as provided for in Article 18. This means that a substantial imbalance in gas market opening across the Community will prevail for a considerable length of time, and this may well raise problems of reciprocity. Norway as an European Economic Area (EEA) country may well decide to accept

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the Directive, but could qualify for a derogation under Article 26 as an emergent domestic gas market, even though it will remain a major supplier to the EU for many years to come. One may observe that the Commission will of course be unable to rely on Article 19(1) to force an emergent market country or one with limited interconnections to take supplies. These problems could become particularly important in the accession countries, many of whom could invoke these special provisions if their markets have traditionally been supplied by a single foreign supplier. The TOP provisions in Article 25 could place a substantial break on market liberalisation while the effective sealing off of emergent national markets and regions and single-supplier dependent states will reduce the possibilities for seeking alternative outlets for the very gas that is presently committed under TOP contracts. Market opening and liberalisation, albeit gradual, will be effectively limited to the core European countries with established gas markets. This approach will certainly have a knock-on effect on the development of independent power generation, and hence the emergence of more competition on electricity markets in the more peripheral European countries.

3.4. Access to the Grid

Having discussed the possibilities for and derogations from market opening, the provisions on access will now be examined. First, it should be noted that major controversy centred around the inclusion of upstream pipeline facilities in the Directive. Producer countries as well as the producers themselves attempted to limit its scope to downstream operations. Lobbying has continued at the national implementation stage, as the Directive does leave scope for varying national solutions as to what type of pipeline is likely to be covered by access requirements. Recital 25 provides that upstream networks are covered, albeit by way of separate treatment. Article 23(1) requires member states to adopt necessary measures to allow those eligible customers to obtain access to upstream pipeline facilities, unless these are used for purely production operations. It is conceivable that existing codes of conduct, for example, could be deemed sufficient to discharge these obligations. National governments are given wide discretion to design an access regime that takes account of security and regularity of supply, capacity, technical specifications, efficient planned production, the interests of the existing operators/ owners as well as relevant national production controls and permits (Article 23(2)).

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3.5. Negotiated and Regulated Access In principle, access within the meaning of Articles 15 and 1 6 - i.e., negotiated and regulated Third Party Access ( T P A ) - should be required through a high-pressure pipeline network other than an upstream pipeline, as defined in the Article 2(2), with a view to delivery to customers. Both access procedures should be operated in accordance with objective, transparent and non-discriminatory criteria. While regulated TPA requires published tariffs and conditions, if negotiated TPA is opted for, only the 'main commercial conditions' for use of the network need be published. The Commission has provided some guidance to access charges and has identified a series of relevant access pricing issues. Interestingly, it recalls the original draft Article 12 of its 1992 proposal for a Gas Directive (February 1992), which would have obliged a transmission company to make available to a potential user a statement of opportunities for transactions involving the use of its system containing sufficient information to enable a potential user to make a reasonable assessment of those opportunities. This pro-active regulatory approach did not meet with approval in 1992 and one may wonder whether the Commission could successfully rely upon it some eight years later when the principle of subsidiary is now so firmly rooted in Community energy market policy. It is obviously intended as a form of 'best practice guidance', however, and can have limited value beyond this. In any event it must be stressed that even negotiated access terms must be objective, transparent and non-discriminatory, as required by Article 14. The terms as published must be applied to all parties, including any affiliates of the transmission company. Thus, the concept of negotiated access should not be interpreted as allowing the transmission company to negotiate each and every contract on a case-by-case basis. Whether regulated or negotiated TPA is adopted, access may be refused if there is lack of capacity, or if such access would threaten the ability of natural gas undertakings to meet public supply obligations (see Article 3) or if the procedures (i.e., TOP) in Article 24 have been applied. Member states are given the option to take measures to direct companies which refuse access because of lack of capacity (including capacity under contract) or a lack of connection, to make the 'necessary enhancements'. However, where member states have on the basis of Article 4(4) declined to grant further authorisations to build and operate distribution pipelines, then Article 17(2) obliges them to take requisite measures to secure such enhancements.

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3.6. Storage and Ancillary Services The access requirements do not apply to access to storage facilities. 5 A company requesting access will only have access to ancillarzv storage services necessary to perform the transportation contract. U This is considered by m a n y would-be new entrants to be a major shortcoming in the Directive and subsequent implementing legislation, if national governments do not deal with the storage issue. In particular, it is not entirely clear what burden of proof has to be discharged by a would-be user in order to show that access to storage facilities is both technically necessary and provides for efficient access to the network in question. Nor is it entirely clear whether transmission operators who can opt for negotiated access will have to publish their terms and conditions for storage services. It is certainly arguable that the main commercial conditions for use of the system should include information on the commercial conditions for access to storage facilities and related services. Further, it is possible to argue that the principles of Article 7 of the Directive, and especially the principle of non-discrimination, require vertically integrated incumbent companies to provide storage services if their own affiliates enjoy the flexibility of storage assets. Similarly, the Directive does not explicitly address the issue of ancillary services, such as balancing, blending and related services which new entrants claim must be offered on a transparent, nondiscriminatory and competitive basis. In particular there is no requirement that balancing rules should be harmonised between member states, and this could have implications for the development of interstate trade, as discussed below.

3.7. Regulation and Supervision The Directive has relatively little to say on the question of supervision. Article 21(2) requires the expeditious settlement of disputes in relation to Chapter 4 - access to the system. The competent authority must produce its conclusions without delay and if possible within 12 weeks of the commencement of a dispute. This could mean that the ordinary courts are not equipped to deal with disputes unless they have powers to reach a rapid decision, for example to award injunctive relief. Article 23(3) requires the creation or designation of appropriate

5See Article 2(9) and 2(10) for the definitions of storage undertakings. 6In Statements 80/98 and 81/98 are Article 2(12) of the Directive, the Council and the Commission clarify that access to the system does not cover access to storage and related facilities as such, independent of system use.

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dispute settlement arrangements for disputes in relation to access to upstream pipeline networks. No time limits are provided. Article 21 indicates that in the event of cross-border disputes the dispute settlement authority should be the authority covering the system to which access is refused. With regard to upstream pipelines this could depend on which authority has jurisdiction under international law. Where two or more such authorities are likely to be involved, there is a duty to consult. National dispute settlement authorities should have access, where necessary, to the unbundled accounts of natural gas undertakings. It is not clear from the wording of Articles 6-8 on Transmission and Storage whether the rules to be developed for transmission and storage should be subject to any form of ex ante regulatory supervision.

3.8. Cross-Border Issues

It is of major importance to note that the Gas Directive, like the Electricity Directive, makes no explicit mention of how cross-border transmission is to be dealt with. In some respects, the problems that will arise in the gas market may be less acute than those which have occupied the Commission officials responsible for electricity in the last two years. 7 With respect to cross-border electricity transmission the Commission has been anxious to implement a non-distance related or 'postage stamp' system that in essence will prevent what has become known as pancaking of national tariffs. Postage stamp tariffs reflect the basic principle that the physical path of the international supply contracts involved will be quite different from the so-called 'contract path'. For gas the physical and contract paths may converge but not necessarily, so various forms of swaps could be involved. It is therefore not a foregone conclusion that international gas transmission fees should be contract based or indeed that supplier should be forced to negotiate back-to-back contracts. The Commission has indicated that international trade, transit or transportation should in principle differ from national trade or transportation only because of the distance factor. This in turn may mean that access to several, separate pipeline systems will have to be negotiated. As a consequence of the general lack of unbundling and the probable tendency for member states and their gas companies to favour negotiated over regulated TPA, considerable inconsistencies between national tariff systems are 7A good overview of the issues involved is continued in the Commission's Second Report to the Council and the European Parliament on Harmonisation Requirements, April 1999.

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likely to be the rule. Each system may also adopt quite different approaches to determining capacity constraints on their national systems, again complicating multi-country transportation projects still further. It is therefore hardly surprising that in its first Report to the Council and the European Parliament on Harmonisation Requirements in relation to the Directive, 8 the Commission stressed the issue of more efficient interoperability of gas networks. This should be approached at least initially by a careful monitoring of implementation measures with a view to examining whether from technical and economic points of view, the existing organisation of the European gas network is capable of facilitating gas trade. The Report singles out a number of technical issues including the absence of harmonised gas quality specifications as well as pipeline specifications. Article 5 of the Directive is interpreted as providing a sufficient basis for member states to establish requisite rules for minimal standards of operability. These rules should be transparent and non-discriminatory. More complex matters such as balancing services and the terms and time frames could be dealt with by a network code. Laudable as these aims might be, in reality the lack of national regulators to supervise the formulation as well as the enforcement of such rules will remain a problem in many member states. The Report makes no reference to this issue, however, perhaps in an attempt to avoid provoking debate on the controversial issues of specialist, European-wide regulators. Other major commercial issues such as capacity constraints on interconnectors between markets are acknowledged but not dealt with in any detail in the report. Reservation of capacity in long-term contracts, as permitted under the Directive itself for TOP contracts, will inevitably raise major problems for new entrants. Similarly, tarification methodologies for use of interconnectors in cross border trade are not examined at this stage but once again this is a matter, which is to be the subject of future discussion and possible action. If one considers the current state of development of implementation of the Electricity Directive, it is clear that these types of issues will have to be addressed sooner rather than later if cross-border transmission is to become a reality.

3.9. Public Service Obligations Article 3 of the Directive, like its counterpart in the Electricity Directive, allows member states to adopt wide definitions of the term 8Com(99) 612.23 November 1999, Brussels, final.

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'public service obligation', and to impose these obligations at each and every stage of the supply process. In other words, member states will have the power to limit access to gas pipelines and therefore also to eligible customers if this would prevent a gas supply company from fulfilling its public service obligations. It is necessary that the company in question is entrusted with these obligations by a public law measure. This was emphasised by the Court of Justice in its recent rulings on the legality of the French gas import/export monopoly rights (Case C-159/94 Commission v France). This would mean for example, that public service obligations would have to be formally conferred upon a company such as Gasunie if Article 3 were to be invoked. Until now the various rights and duties of Gasunie have not been established in such terms but by way of informal agreement between the company and the Dutch Government. Nevertheless, as long as the duties are conferred by a public law measure the member states have a wide power to determine the scope and extent of such obligations, as confirmed by the Court in Case C-157/94, Commission v. Netherlands.The last sentence of Article 3(3) indicates, however, that such measures should not be invoked to prevent supplies to recognised eligible customers, as this would be contrary to the EU interest: It is however not entirely clear whether this means that the public service exemption cannot be relied on if this would frustrate the implementation of the minimum thresholds specified in Article 18 or if it would be necessary to rely upon it to justify re-defining eligible customers when the maximum threshold was likely to be exceeded. What would seem to be clear from recent jurisprudence of the Court is that it is only necessary to show that the relevant public sector duties could not be performed under acceptable economic conditions if the companies entrusted with those duties were exposed to more competition. This could mean that a gas company entrusted with the duty to provide gas at reasonable prices to small consumers could argue that it could not cover all its costs if a competitor entered the market and took away its more profitable, larger customers. This could be used as a justification for refusing access, but such an argument can normally no longer be accepted if the larger customer has a consumption of over 25 million m 3 per year: the right of such a customer to receive its supplies from a competing supplier is now guaranteed. But what if the number of large companies consuming such volumes is sufficient to bring the member state in question over the maximum threshold; i.e., could access then be legitimately refused if the loss of so much custom would disrupt the normal economic conditions under which the company operated?

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3.10. C o n c l u d i n g A s s e s s m e n t on the Directive

The Directive, as noted, is weak on three key aspects: unbundling, access and regulatory supervision. Further, the combination of the general derogation clauses for certain types of system, and the individual provisions on TOP contracts have meant that many markets could remain well-insulated from gas-to-gas competition. The major push for further gas market liberalisation in many EU countries will probably come from the opening up of electricity markets. The 'dash for gas' that this should produce will lead to demands for gas-to-gas competition across the EU. Some member states may be more responsive than others to such claims and hence adopt a more pro-active and pro-market approach in their implementation of the Directive. It is important that the Commission is already producing policy guidance in this respect and encouraging a pro-active approach to implementation. Nevertheless, it is doubtful whether such exhortation can ensure a level of harmonisation across the 15 member states, which is really conducive to creating a single market for gas as such. Even before the deadline for the implementation of Directive 98/30 has expired, it was already clear that considerable follow-up action would be required. Major, outstanding harmonisation issues in the context of cross-border trade and transmission have already been identified in the First Harmonisation Report of November 1999.

3.11. The Way Forward - the Proposed R e v i s i o n s to the Gas Directive

Despite the fact that Directive 98/30 had been in force for less than one year in the majority of member states, the Commission did not hesitate to identify major flaws and recommend fundamental revisions to it when, in March 2001 it published a detailed assessment of the impact of the Gas and the Electricity Directive. In summary the revisions will require a considerable strengthening of the unbundling requirements. A separate TSO (transmission system operator) must be designated and that body must be independent at least in terms of its legal form, organisation and decision making from other activities not relating to transmission, although responsibility for storage as such need not be transferred to the TSO. The negotiated access option will d i s a p p e a r - third party access is obligatory and tariffs for the use of the system must be subjected to regulatory approval procedures and published. Access to storage and related 'flexibility instruments' can

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still however be based on negotiated access procedures. Significantly, the revisions do not amend the existing provisions on TOP contracts. A first draft of these revisions was submitted to the Stockholm Summit in the Spring of 2001, but several member states were immediately hesitant to endorse the Commission's proposals to open up both the commercial and the domestic segments of the market to competition by 1 January 2005. Others objected to the strengthening of the powers of independent regulators, arguing that adequate control and supervision of their national gas and electricity markets could be left to general competition authorities. The Commission is now engaged in the lengthy process of persuading both the European Parliament and the Council to accept its proposed revisions to both the Electricity and Gas Directives. In June 2002 a further revised version, including many of the proposed amendments advanced by the European Parliament was published but this version too appeared to make little impression on the Council under the leadership of Spain. The Parliament had called for the Commission to proceed with the revisions to the Electricity Directive first and then turn to gas, as it had done before, but the Commission has so far insisted that package of reforms must be seen as an integrated one and has resisted the Parliament on this point. It is difficult to predict when and indeed if further liberalisation measures will eventually prove acceptable. Many member states are wary of being deprived of the means to deal with security of supply i s s u e s - especially as they are going to be more rather than less dependent on imported gas in the near future. In the meantime the Commission has been prepared to accept extensive amendments which would effectively allow member states to broaden the scope of the public service obligations which they impose on gas companies and to suspend the operation of numerous key provisions if this proved a threat to the realisation of these extensively defined obligations. This could lead to a continued fragmentation of markets along national lines. Nor do the proposed measures tackle the issue of cross-border trade and transmission, the Commission having judged that it was too early to adopt secondary legislation dealing with issues that are still the subject of substantial debate, if not controversy in the context of the Madrid Gas Regulatory Forum. In many respects then, the proposed revisions are unlikely to address the myriad of criticisms levied at the current framework.

Ghapter 4 National Models in the Emerging European Gas Market ~176

MAARTEN J. ARENTSEN AND ROLF W. KUNNEKE

4.1. Introduction

The preceding chapters described two major drivers of gas market reform in Europe: technical change and liberalisation. As noted in the introduction the differing national heritage of gas market development, determine specific positions held in the unfolding liberalisation process. This chapter will elaborate these differences in a more systematic way by suggesting a framework for comparative analysis of national responses to the emerging EU gas market liberalisation and harmonisation. A point of departure are the obvious differences between European countries with respect to access to gas resources. Only a few European countries have gas reserves voluminous enough to allow both domestic consumption and export. In these countries gas reserves are considered as national assets and without exception have been exploited for national benefit. In this regard Norway adopted a model strictly focussing on gas production and gas export for the benefit of national welfare and prosperity. The Netherlands, also gifted with huge gas reserves, combined gas export with domestic gas consumption. The country developed one of the most dense gas markets in the world, connecting almost the entire population to the gas network. Initially the Netherlands gave priority to domestic gas consumption and for a long time gas export was only a function of domestic consumption. Only after 1989 did the Dutch put more emphasis on exports. Due to its isolated position, the United Kingdom initially had little choice other than to consume its gas domestically. The interconnector with Belgium improved the connection between 45

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the British gas fields and continental Europe, and thus improved the British export position in Europe. For net importing countries, those without significant gas reserves, security of supply has been a major point of reference in the development of the domestic gas market. These countries secured their gas supply with long-term contracts with gas exporting countries. These contracts date back from the 1960s when German local distribution companies started contracting with the Dutch company Gasunie. The local networks had direct connection with the Groningen gas field in the Netherlands and local city gas networks were transformed to use the natural gas from the Groningen field. Until the mid-1970s the Netherlands was the most important European gas supplier, but in the 1970s Norwegian and Russian gas also entered the European gas market. Produced at different locations, natural gas gradually achieved an important position in the energy balance of many European countries, and irrespective of existing gas reserves, all discovered the convenience of natural gas as an energy resource. Originally, natural gas was only available for private household consumption, but steadily moved to industrial sectors. Industry discovered natural gas as a convenient and cost-effective alternative to crude oil and as an important feedstock for chemical products. Over the course of time natural gas also achieved a strong position in the thermal-based European electricity systems. The development of gas markets in Europe was guided by a specific focus on national gas policies, a focus assumed to be determined by countries' access position to gas reserves. This chapter pursues this idea of focussed guidance of gas market development as a point of departure to distinguish two different models for gas market development: a public property focussed model, and a public utility focussed model. The first model refers to the 'haves' in Europe, the countries with voluminous gas fields and the public utility model referring to the 'have-nots', the countries without voluminous gas fields. In addition to these two models we distinguish the commodityfocussed model, referring to a gas market where natural gas is perceived as a freely tradable commodity. This commodity-oriented model is now challenging all EU countries due to the EU Gas Directive. Liberalisation has affected the image and perception of natural gas, which can no longer be considered only as public property or a public utility. Natural gas is steadily being transformed into an 'ordinary' economic good that is assumed to be unconditionally tradable on a European scale. Both the public property and public utility models are helpful for describing and understanding the way countries developed national

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gas markets in the past. The third model, the c o m m o d i t y model, hardly covers any real developments in Europe thus far and serves as a reference for a competitive gas market. This model enables us to evaluate countries' gas market developments in the context of emerging competition. The three models are elaborated as ideal-type reference models in a more systematic w a y below. 1 Each model will be specified in terms of industrial and regulatory organisation, functionality of the gas pipeline infrastructure, and economic and public performance - all characteristics of national gas markets the central problem statement of the book refers to. The models developed and described in this chapter serve three purposes. First, the models have guided the analyses of national gas market developments in the next part of the book. 2 Second, in the final part of the book, the models are used to systematise comparison between national developments, and third to assess the prospects of national positions in the emerging internal gas market in Europe. Each model is described in a separate section and their core aspects are s u m m a r i s e d in Table 4.1.

4.2. Natural Gas as Public Property The few European countries gifted with natural gas were faced with challenging questions after the discovery of the resource. The first discoveries on the European continent date back to the early 1960s, a time w h e n no gas markets existed, as we k n o w them today. Governments at that time had to answer questions that appear quite obvious today. These included ownership of the resource, its exploitation, the investments needed for exploitation, to w h o m to sell the resource, and using what kind of appliances. At that time, these questions were new and had to be answered almost 'in the dark'. A c o m m o n underlying idea for gas policies of the gas producing countries at that time was that natural gas was considered as public property, and was expected to bring prosperity for the country as a whole. This became a guiding principle in the 1These models represent ideal-type models in the Weberian tradition and therefore are not referring to any existing national gas market in Europe. All European countries display gas market developments holding combinations of elements of the three idealtype models. In this book the models provide guidelines for the analysis of national gas market developments, which are the subject of the second part of the book. In the final part of the book, the models will serve as reference for the comparative analysis of national gas market developments in Europe. 2The national chapters have been written with the help of a common schema holding the aspects of the models discussed in this chapter.

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48 Table 4.1.

Features of ideal-type gas market models. Public property

Public utility

Commodity

Resource policy

Market failure

Competition

Dominant policy focus Political-economic organisation Ownership structure Governmental control and regulation Economic regulation Number of actors Barriers to entry

Public dominance

Eligibility

Not relevant

Private dominance

Focus on resources

Sector specific regulation

Competition policy

Producer oriented

Consumer oriented

Focus on upstream: Controlled access and limited number of actors

Focus on downstream: Controlled access and limited number of actors Regulated monopoly

Network related (access, tariffs) Market driven

Competitive market

Pipeline infrastructure International orientation Matured upstream system (production, transport, storage)

National orientation

Economic

Maximisation of state revenues

Public

National welfare and prosperity

Reasonable consumer tariffs and selective services Public service obligations

Interconnectivity Dominant functionality

Matured downstream system (storage, auxiliary services, distribution, supply)

National and international Matured upstream and downstream system

Performance Static and dynamic efficiency Competitive economic structures and allocative efficiency

exploitation of the resource, but countries took their own decisions in this regard, as the next part of the book will show. This section summarises the commonalties in gas market development of countries gifted with their own gas reserves.

4.2.1. Dominant policy focus Governments of gas producing countries in general have been fully aware of the economic and financial opportunities offered by the

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discovery of natural gas. All countries developed specific resource policies for the cost-effective exploitation of the discovered fields, the exploration of new fields to ascertain long-term security of supply, and public devices for distribution of the financial and economic values involved. Governments of all gas producing countries developed leading positions in the exploitation of the national resource, either in collaboration with private industry or by establishing state owned enterprises. The strong governmental position served the effective economic and financial exploitation of the resource for the benefit of the national economy. All gas-producing countries have benefited economically and financially from the exploitation of gas in their territory and all are still benefiting. The exploitation of natural gas increased state budgets and created new opportunities for public spending. In the Netherlands, the development of the welfare state in the 1970s to a large extent was financed by gas revenues and in Norway the financial gains of natural gas are expected to contribute to long-term national welfare and prosperity. Gas reserves offered countries flexibility in national energy policies. The discovery and exploitation of natural gas facilitated choices regarding short and long-term energy supply. In the Netherlands, the exploitation of the gas fields has been a function of securing the longer-term availability of natural gas for the domestic market. The Dutch developed a national energy infrastructure that indeed became dominated by natural gas. British depletion policies on the other hand were more fluctuating, at first restricting appliances of natural gas, but later changing in gaining short-term profits and relieving restrictions in appliance and sale of natural gas. Natural gas exploitation was accompanied by industrial spin-offs. The Norwegian shipyard and offshore equipment industry is a clear example of this. In the Netherlands, the gas turbine industry and the gas facility industry both had strong incentives due to the domestic presence of natural gas. Furthermore, natural gas offered countries flexibility in economic and industrial policies. In the Netherlands, greenhouse horticulture, significant parts of the chemical industry, the aluminium industry, and Dutch power generation have long been supported by preferential gas tariffs. The discovery of natural gas challenged countries to develop specific policies to ascertain effective exploitation of the resource. The history of natural gas in Europe shows how countries each in their own way dealt with the challenge to exploit the gas as a public property and the types of decisions they took regarding the design and building of the national gas pipeline infrastructure, the gas industry and the domestic gas market.

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4.2.2. Political-economic organisation The property of national gas reserves has been a guiding principle in the institutional organisation of the national gas industry. In Europe, gas and oil exploration dates back to the beginning of the last century and was basically a private business activity approved by governmental licensing. The first voluminous discoveries did not change this system of licensing but it did change the property issue. All gas producing European countries considered the natural gas as a public property, but all continued to exploit the resource in close cooperation with private industries. For that reason the institutional organisation in all countries developed as a complex organisation holding combined public and private interests, and regulatory governance structures focussing on state control of the national gas resources. All institutional and regulatory devices that developed across Europe, in one way or another, display this kind of public-private partnership in the exploitation and state regulation guaranteeing that revenues flow to the national treasury. The exploitation of reserves induced an economic organisation dominated by upstream segments of the gas chain, the production and transmission of natural gas. For gas producing countries the upstream segment is the 'money maker' and for that reason is subject to strict entry regulation. Gas production was and still is licensed and has long been without genuine competition. Gazprom's monopoly on export in Russia is a clear example. Norwegian producers are organised as a supply cartel, jointly operating on the European market. The Netherlands and Britain both opted for the coordination model, putting one organisation in charge, with centralised coordination of production and supply of natural gas. European gas supply developed as a regulated monopoly based on the bilateral long-term contracts and regulated prices mirroring the price of oil-based alternatives. Competition in European gas supply has not existed, other than in terms of preference for a specific supplier or specific regions. Gasunie's reputation for reliability, for instance, allowed for additional charges for the quality of the service of Gasunie's gas supply. For a long time Russian gas supply suffered from a bad image and for historical reasons still faces some strong sentiments especially from the east European countries. In gas producing countries, organisation of the upstream activities prevails and the downstream market organisation of distribution attracts little attention as long as it matches and supports the upstream activities. The number of downstream distributors might be large or small, but the monopolistic supply of natural gas and

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controlled wholesale leave little room for rivalry in downstream activities.

4.2.3. The pipeline infrastructure Because of gas field exploitation, the public property model necessarily supports a technological system facilitating upstream activities. The technicalities of the upstream system (explained in more detail in Chapter 2) involve the finding, producing and processing of gas. Offshore production in particular can be extremely challenging. The technicalities of the public property model are guided by effective pipeline connections with relevant European load centres. The system must not be hindered by any technical or institutional barriers and must be reliable enough to ensure secure gas supply. The system assumes high interconnectivity with the highpressure European transmission pipelines, to allow for flexibility and assistance in case of calamities. The European high-pressure pipeline system has been extended tremendously in the last decades. In particular the density of the pipeline system on the Continental Shelf increased and its connection to the European continent has been diversified and extended.

4.2.4. Performance In terms of performance, the public property model strongly focussed on increasing national welfare, which could be attained along different routes as explained above. Irrespective of the particular choices made in this respect, all viewed the national resource to be exploited for the benefit of national welfare with the state taking a central role in the distribution of wealth. Norway capitalised on gas for the benefit of longer-term prosperity, whereas the Netherlands and Britain also distributed the wealth of the gas resource by means of domestic gas consumption. In terms of policies, organisation, technicalities and performance the public property focussed gas market model developed along a specific pattern. A pattern guided by the presence of gas fields on the national territory and the ambition to capitalise the economic value. Table 4.1 summarises the core characteristics of the public property model. 4.3. Natural Gas as Public Utility

For the public utility model, natural gas is conceived as a vital energy resource for the national economy and as public utility resource

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because of inherent imperfections of the gas market. These imperfections stem from the grid-bound supply of natural gas and the high and risky investments involved, which have been handled thus far primarily by public monopoly regulation rather than economic principles. State control and monopoly regulation was meant to reduce investment risk and to ascertain long-term domestic consumption by developing a domestic consumer market. The utilityfocussed gas market developed in many European countries, including in countries not gifted with their own gas reserves. In particular in these latter countries the public utility focus has provided strong guidance in gas market development because of the countries' import dependence. This is an issue strongly related to the national autonomy in energy supply and its being considered of vital national interest by nations all across Europe. This section lists the core elements of the public utility model.

4.3.1. Dominant policy focus Whereas the public property model concentrates on gas production and gas supply, the public utility model concentrates on gas consumption and gas demand. Policy for the utility model draws on the idea that natural gas is a vital national energy resource that should be available nationwide. In this regard, the state takes an active role in developing the utility-oriented gas market for economic and political reasons. Economically, the challenge for nations has been to develop a national gas market that functions efficiently and adequately. Due to economies of scale and scope in grid-bound gas supply, a contestable market would not develop and therefore entry and monopoly regulation needed legitimising state intervention and control to prevent abuse of monopoly supply position. Therefore, everywhere in Europe monopoly regulation developed as dominant regulatory model in gas supply and gas distribution. In addition to the economies of scale and scope argument, state control of gas supply also has been legitimised by political arguments. Several European countries made specific political decisions in shaping their national gas market. The Netherlands decided to connect all Dutch households to the gas network, irrespective of location. For years the connection of new residential areas was an explicit obligation for gas distribution companies. Companies were legally obliged to distribute gas to all connected to the gas grid and gas prices have long been decided politically. Similar political considerations guided the development of the consumer market in France, where gas supply is guided by a set of public service obligations,

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among others, to charge private consumers equally, irrespective of location. France also made the political choice to consider gas supply a function of national electricity supply. In energy policies, the French initially gave priority to coal and later to nuclear energy on account of natural gas. For that reason parts of the country were not connected to the gas grid. Similar considerations have restricted the use of gas in British electricity production. Here too, the national coal industry and the development of a national nuclear industry were the political arguments to restrict gas usage in electricity production. More recently, gas supply has been used as a device in environmental and climate change policies. Dutch gas companies were obliged to stimulate energy efficiency at the consumption level. Norway provides another example of political choice guiding development of the gas market in its decision to not develop a national gas consumption market, but instead, to fully concentrate on gas export. Part of the consideration was the largeness of the country in combination with the small and geographically widely spread p o p u l a t i o n - bad conditions for developing a profitable domestic gas market. Subsequently, environmental considerations became part of the argument, due to the environmental soundness of the Norwegian hydro-based electricity system. In terms of policy focus, the utility model concentrates on development of the demand market legitimised by a set of economic and political arguments.

4.3.2. Political-institutional organisation The utility focus in gas market development is also reflected in the typical ownership structure of national gas industries in Europe. The demand-oriented market of the utility model implies an institutional organisation concentrating on gas distribution by publicly owned gas companies. Many of these companies across Europe date back from the city gas era, which changed their networks to natural gas after the discovery of gas fields in Europe. In Germany as well as in the Netherlands, local authorities are the owners or shareholders of the gas distribution companies. Gas companies were guided by the political considerations of local authorities. In the Netherlands, governmental and provincial authorities enjoyed the financial benefits of profits made by the gas distribution companies. At the same time these companies were committed to local employment policies obliging them to create jobs in the region. So the utility-oriented model developed a strong interrelation with national politics resulting in a strong public control of business strategy and price policy of gas

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companies. The economic regulation was consumer-oriented and focussed on entry control of downstream activities and monopoly regulation preventing abuse of monopoly distribution.

4.3.3. The pipeline infrastructure The utility model concentrates on a well-developed and reliably functioning gas distribution pipeline infrastructure, connecting the endconsumers to the gas fields. The utility model's emphasis on quality of the distribution network, assumes adequate connections to high-pressure transmission networks in Europe. The upstream network is considered to be a function of the downstream network and the operation of the utility-oriented gas network concentrates on system balance for consumer demand. The operation of the system is a function of reliability and security of supply and distribution under all circumstances, day and night, summer and winter. The system might include additional storage facilities to meet demands under extreme circumstances and gas distribution might be accompanied by specific services for the convenience of endconsumers. In short, the gas pipeline infrastructure of the utility model assumes a matured downstream gas system effectively connected with European gas fields to satisfy national gas demand.

4.3.4. Performance The public utility model focuses on secure and reliable satisfaction of consumer demands in terms of price and type, and quality of services. The model also focuses on the achievement of a combined set of political and economic goals through gas consumption, in many cases operationalised as public service obligations of gas companies. Reasonable consumer tariffs and public service obligations are important performance parameters of the utility-focussed gas market model. Table 4.1 summarises the core characteristics of the public utility model. The table shows the differences in policies, organisation, technicalities and performance between the public utility and the public property model. 4.4. Natural Gas as C o m m o d i t y

The third and final model introduced in this commodity-focussed model. Compared with the other modity model has the smallest empirical reference gas market until 2000. The commodity model in fact

chapter is the models, the comin the European reflects the ideal

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of a competition-based gas market. What this competition-based market should look like is still far from clear (Joint Working Group of the European Gas Regulatory Forum, 2001). The EU Gas Directive only provided for some basic harmonisation rules generally recognised as necessary conditions to introduce competition in gas markets. Access of gas pipeline networks for third parties and separation of vertically integrated supply and transmission activities are considered to be of paramount importance in this regard. The first review of emerging liberalisation in Europe reveals that the required openness and transparency for competition are still in an infant stage of development. Thus far, only the British gas market to some extent matches the necessary conditions of competition (see EU Commission Staff Working Paper, 2002). The following section summarises the characteristics of a commodity-focussed and competition-based gas market. For this model natural gas is assumed to be an economic commodity whose trade and supply is not conditioned by any political considerations, other that efficient, competition based, allocation of natural gas.

4.4.1. Dominant policy focus The commodity model policy focus is based on the proposition that competition will improve the longer-term vitality of the gas market because competition induces innovation and competitive advantage. Short-term policy therefore should focus on establishing and ascertaining competition in the gas market, by means of providing the rules of the competition game and by means of regulation, control and enforcement of the competition rules. Entry regulation and all other political and economic considerations underlying regulation in other models are no longer needed. The state only provides for the design and control of competition rules, demand and supply of natural gas is left to private market actors.

4.4.2. Political-economic organisation Due to the state's role in originating competition rules and as regulator of the competition in the commodity model, the state's involvement as owner or shareholder of companies is no longer obvious, except for the gas pipeline infrastructure. In general the gas pipeline network is considered a natural monopoly and therefore, ownership and operation is controlled and regulated in the commodity model. The ownership and/or the operation of the high-pressure transmission network and the low-pressure distribution network

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requires state control to ascertain third party access. No other entry barriers exist and the fit between supply and demand of natural gas is left to private actors. The commodity model assumes no regulatory restricted consumer choices, as in the case of the property and the utility model. Suppliers and consumers negotiate gas supplies and gas prices reflect supply and demand conditions of natural gas. The price of oil alternatives no longer serves as reference for state price policies, but will only influence individual consumer preferences. Upstream as well as downstream entry barriers do not exist and in all phases of the value chain of natural gas, the number of market actors is large enough to prevent strategic behaviour of specific market actors. Commodity model market conditions are transparent and accessible to all actors operating in the market. System operators are open about the availability of transmission capacity and the conditions for third p a r t y transport of the gas. Gas flows are not hindered by any technical, legal or institutional barriers. Those who request transmission or transport services are served on the basis of transparent and non-discriminatory conditions.

4.4.3. The gas pipeline infrastructure The commodity model assumes a matured upstream and downstream gas pipeline infrastructure. The technicalities of the system accommodate the economic functions of the gas market (see also Chapter 2) by offering a wide range of specific services, including storage for economic reasons and not only as a flexibility service. The technical reliability of the system is an obvious precondition and no longer a principal focus in the system operation. The system is able to meet specific and individualised demands of users and consumers. The flexible system has a high connectivity, both nationally and internationally. Internationally, the system is connected with all important gas fields and with all important gas hubs in Europe. There are no technical, operational or managerial barriers in the free flow of natural gas in and between national pipeline systems. The system offers services based on capacity, and tariffs are cost-reflective because of swap-based transmission across Europe. Finally, the transmission system allows for trade and change of owner of gas volumes as long as it is in the gas pipeline system.

4.4.4. Performance The performance of the commodity-focussed gas market is economically oriented, with allocative and dynamic efficiency as two principal

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performance parameters. Allocative efficiency is reflected in transparent, unconditional and non-discriminatory access to the pipeline system and optimal transmission and consumer prices. Dynamic efficiency is reflected in short-term adaptability and innovation of market actors and longer-term competitive advantage of the gas industry. The commodity model assumes a competition-based supply of natural gas that is not hindered by any additional considerations operating in the property- and utility-oriented models. For the commodity model, the state regulates and controls the conditions of competition, with control of third party access to networks and abuse of owners and or operators of the gas systems as important focal points of regulation. The next section summarises the core characteristics of the three gas market models. 4.5. Summary of the Gas Market Models

Table 4.1 summarises the core characteristics of the three ideal-type gas market models introduced above. The table comparatively lists the core aspects of gas markets with a principal focus in gas policies. Each of the three models holds a principal focus in gas policy, which is assumed to be guiding for the development of the gas market. The gas markets developed in this policy-driven environment are different in terms of political-economic organisation, the principal characteristics of the gas pipeline network and in terms of principal performance. It should be noted that each model is introduced as an ideal-type model and not as an empirical model. As the next part of the book will show, gas market development in Europe reflects the varied way the combination of all three models has shaped specific gas markets in Europe, with no single gas market in Europe matching the ideal type of any one of the models. The three models provide guidance in answering the central research question of the book. The book covers past developments of gas markets in Europe, but from the perspective of liberalisation. The EU Gas Directive obliged member states to change the legal order of national gas markets, to introduce third party access, free consumer choice of gas supplier and unbundling of transmission and trade activities of the vertically integrated gas companies that dominated gas markets for so many years. The change induced by the EU Gas Directive, has just started and is forcing incumbents of the old order to reconsider their position in the national and the European gas market. Comfortable production and supply positions are challenged by the choices offered to eligible customers. The state has to reconsider

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its ownership position in production and supply. Resource policies have to be reconsidered in the context of emerging competition across Europe. National governments have been captured by the legal requirements of the EU and private companies are reconsidering their public-private partnership in production and supply. Natural gas is expected to be the booming energy business of the near future, forcing all incumbents of the old gas order to reconsider their position in this new perspective. As national gas markets in Europe face the challenge of competition, we attempt to unfold their prospects under competition based on past developments. Important questions in this regard are whether national gas markets are captured and locked into path dependency due to the specific track of their past development. Do countries have the proper technical, institutional and economic conditions to develop a good position in a competitive oriented internal gas market? Are the technical aspects of the systems sufficient to cope with emerging demand and supply of natural gas? In short, do countries possess enough flexibility to adapt to the changing gas order in Europe? Before turning to the national level analysis of these questions, the next and final section of this chapter briefly discusses some of the inertia and dynamics of gas market reform in more general terms. 4.6. Inertia and Dynamics in Gas Market Reform

The three models presented above assume a close interconnection between the principal focus in gas policies and the organisation and technicalities of national gas markets. Simply put, a public property orientation in national gas policies induced a different kind of gas system and institutional organisation than the public utility focussed orientation in gas policies. The organisational and technical requirements of the commodity model are assumed to be quite different from the property and utility model. Due to EU requirements all member states are now facing the challenge in one way or another, in order to adapt to organisational and technical requirements of the commodity-oriented gas market model. Changes within national gas markets will draw on past achievements and therefore will result in different routes. Some countries already have matured and have well-connected pipeline systems, while others do not. In some countries the organisation of the gas industry might be more flexible and adaptive to competition. The conditions in some countries may be appropriate for developing new economic functions in the gas infrastructure while other countries may

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not be so predisposed. Some countries are already more centrally located in the emerging European gas market than others. Each in their own way, and with their own national heritage in gas market development, are challenged to transform the old gas order into a new one. The common problem countries are facing in this regard can be understood with the help of the evolutionary notion of increasing returns to adoption (North, 1990; Arthur, 1988). Increasing returns incorporates the general idea that history or past achievements tend to determine next steps in technological and institutional change. North distinguishes four sources of increasing returns: large fixed set-up costs, learning effects, coordination effects, and adaptive expectations (North, 1990; p. 94), which in one way or another all gas markets in Europe are facing and therefore pose serious barriers to change. All countries with matured gas markets are facing the fixed cost problem, because all have heavily invested in the technicalities and the institutional organisation of the national gas system, but with a different guiding focus than to trade and supply natural gas as a commodity. They have all developed routines (learning effects) to manage and operate the system and many of European gas markets were and to a large extent still are centrally coordinated. The logic of central coordination draws on the economic rationale to integrate different functions in the value chain of natural gas. For that reason almost all European countries have had centrally co-ordinated and vertically integrated gas companies combining supply, trade and transmission of natural gas, quite often closely connected to production by means of ownership structures. Only Germany developed a different, decentralised, model of gas market coordination. In this way, the history of natural gas in Europe also reflects the idea of adaptive expectation especially regarding the central coordination model and the technical operation of national pipeline systems. The idea of adaptive expectation is that market actors anticipate new technical or economic developments and in this way decisively determines a specific path of development at a point when the anticipated innovation has not yet been proven to be the best or most efficient. The idea of adaptive expectation developed increasing importance in the late 1990s. British gas market reform preceding the EU harmonisation process is a clear example. The Belgian initiative to host the continental connection of the British interconnector is another example. These initiatives clearly anticipated the emerging competition in the internal gas market in Europe. In the context of emerging competition an important issue is the extent to which national gas markets are locked into past development

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patterns. No country can embark on overall redesign of the technical aspects or institutional framing of its gas market and some have better conditions than others to reform the organisation and operation of the national gas industry. For different reasons countries like France and Norway have strongly focussed on electricity instead of natural gas to satisfy domestic energy demand. Both countries have sophisticated electricity systems and domestic energy consumers in both countries are familiar with the convenience of the electricity system. These kinds of consumer routines are extremely difficult to change even if consumption of natural gas would prove more efficient or optimal from an economic point of view. In this manner, Norway too is locked into past decisions to not develop a domestic consumer market for natural gas. Apart from the evolutionary based inertia in gas market reform, there are also signs of new and promising dynamics. Europe is in a process of building new international connections between national gas networks. New gas hubs are planned or under construction and old and new gas fields in Russia and Norway are connected to the European load centres. Europe is working on the improvement of gas supply, technically, institutionally and politically. Industry is searching for new business opportunities and is beginning to enter previously closed markets. Consumer demand for lower prices, new entrants and regulatory requirements increasingly will challenge fixed traditional structures, and in this way will stimulate the emergence of new competition-oriented routines. In general, increasing return systems, like the gas system, are almost by definition characterised by multiple equilibria. Empirically, this is evident. No national gas market is an equivalent of another; all are different and there is no empirical evidence yet for a commonly shared development pattern into one 'final equilibrium'. National gas markets have historically developed under different conditions and been guided by different objectives. Not surprisingly, the different technical and institutional choices made in the past necessarily engender specific paths of development in the emerging competitive oriented internal gas market in Europe. The extent to which the evolution of gas markets in Europe is adaptive to the regulatory changes induced by the EU Gas Directive will be explored in greater detail in the next part of the book. Part 2 provides detailed studies of the history of six gas markets in Europe. Four of these markets are part of the EU, Germany, France, Great Britain and the Netherlands and two markets, the Norwegian and the Russian, developed in close correspondence with the EU gas market. The gas market in each of these countries was shaped by one of

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the three models of development and corresponding policy focus elaborated in this chapter. The authors of the following national case studies analyse the political, organisational and some technological aspects of the gas market, as well as the dynamic interaction between these aspects in their past and recent development. With one exception, each chapter is devoted to a specific country. The history of the British gas market was too rich to cover all details in one chapter only and therefore is told in two chapters. Further, the history of the British gas market is clearly separated into two periods guided by different policy foci. Until 1984, the public property model guided development of the British gas market, but this changed gradually into a commodity-oriented development from 1984 onwards. The sequence of national chapters in the next part of the book is motivated by the dominant focus in national gas market development. In this way, the stories of Russia, The Netherlands, Norway and the United Kingdom (until 1984) represent the public property reference in national gas market development. The stories of France and Germany, evidence the public utility model gas market, and Britain after 1984 represents the commodity focus in national gas market development. Additional to the detailed analyses of the developments in the six gas markets in the northern part of Europe, the development in some of the south and eastern European gas markets is sketched. This overview of the south and eastern European gas markets and Algeria is not only informative in itself but provides a more complete picture of gas market change in Europe. Literature

Arthur, W.B. (1998) Competing technologies: an overview, In G. Dosi, C. Freeman, R. Nelson, G. Silverberg and L. Soete, Eds., Technological Change and Economic Theory, London, Printer. Commission of the European Communities, (2002). Commission Staff Working Paper, First benchmarking report on the implementation of the internal electricity and gas market, updated version with annexes, Brussels, 3-12-2001, SEC (2001) 1957. Joint Working Group of the European Gas Regulatory Forum, (2001). A Long-term vision of a fully operational single market for gas in Europe, a (Draft) Strategy Paper, Prepared for the 4th meeting of the Madrid Forum on 2-3 July. North, Douglass C, (1990) Institutions, Institutional Change and Economic Performance. Cambridge, University Press.

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Chapter 5 Organising National Interests in the Upstream Gas/Petroleum Industry: The Norwegian Model and its Transformation ATLE MIDTTUN, JOAR HANDELAND AND SOREN WENSTOP

5.1. Introduction

Norwegian oil and gas policy has, from the 1970s, to throughout the 1990s, followed a tradition previously developed in the hydropower sector, characterised by a strong public involvement in the exploitation of energy resources. Given weak private capital interests in Norway, active government intervention was seen as necessary to secure national control of valuable domestic resources. The Norwegian Government has therefore played a major role not only in regulating and taxing, but also in the actual development and operation of the petroleum industry. The end of the 21st century marked the beginning of major changes for the Norwegian oil and gas regime, in the direction of deregulation and privatisation. The oil and gas sector thus followed in the footprints of Norway's electricity sector, which had undergone deregulation more than a decade before. However, there were important differences between the two sectors' deregulation processes. The electricity sector reform in Norway was endogenously initiated, as Norway (along with the UK) was one of the European deregulation pioneers. In contrast, oil and gas sector reform resulted from external pressure, and the progression and enforcing of supranational regulatory mechanisms. The European Union's energy deregulation initiatives posed major challenges for state involvement in managing and trading natural oil and gas reserves. 65

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As a member of the European Economic Cooperation, Norway was forced into a peculiar position in the geopolitical game between gas supplying nations and consuming nations. As a dominant supplier to Europe, Norway had common interests with other exporting countries such as Russia and Algeria, but simultaneously, as member of the European Economic Area (EEA), Norway was obliged to comply with European regulation. These regulations were predominately tailored to suit gas importing interests. The Norwegian oil and gas deregulation was further complicated by the wake of EU deregulation which left little guarantee of effective access to continental customers for North Sea suppliers. The European energy markets were likely to evolve into an oligopoly if effective deregulation actually were to take place. From a Norwegian producer's point of view, it was also important that the upstream North Sea deregulation process be closely monitored to avoid pre-emptive downstream competitive exposure. Creating a centralised purchasing scheme could seriously derail the prospect of eventual upstream deregulation. As a result, much of the state influence that characterised the previous regime remained, but was channelled through different institutional mechanisms. The Norwegian Model has been characterised by four elements: 1. A regulatory framework with production contracts and development licences, and special ground rent taxation regime to secure a national political appropriation of ground rent. The special engagement of the State in oil exploration with a direct government share in addition to the appropriation of oil revenue through the state companies is also part of this scheme. 2. Strong direct government engagement via government-owned firms - Through the wholly-owned company Statoil, and the public majority-controlled company Norsk Hydro, the Norwegian state companies built up experience of the exploration sites and then subcontracted large multinationals as technical assistants. Gradually the Norwegian companies also built up technical expertise and took full control over operations. Statoil had the leading position, with Norsk Hydro in a secondary position. 3. Careful strategic planning and organisation to optimise the Norwegian bargaining position vis-a-vis foreign b u y e r s - This strategic planning and organisation included a state imposed coordination of the industry through the so-called 'gas negotiations committee' as well as national control over pipelines and engagements in long-term take or pay contracts.

Organising National Interests in the Gas~Petroleum Industry .

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Measures to secure industrial return from oil activities were also a major part of the Norwegian model. The petroleum activities were seen as a basis for new industrial development, and the Norwegian government therefore initially assumed that petroleum would be landed in Norway in order to allow maximum national industrial spin-offs (Hanisch and Nerheim, 1992). The state was seen to play a major role as a facilitator both through the state companies and through general state functions. Later, when the national landing policy was more or less given up, the industrial return was focussed on supply industry spin-offs.

The newly deregulated regime implies modification of all four elements. The regulatory framework with production contracts and development licences remains, but may have to shift towards a less national bias, and correspondingly a weaker bargaining position for the Norwegian state-owned companies, in light of the strengthened European competition law. The strong government engagement through government-owned firms is also retained, as the privatisation of Statkraft has only been partial, and as the major parts of the State's petroleum and gas resources have been transferred to a new, whollyowned state company. The most dramatic change has come in the organisation of strategic planning and bargaining vis-a-vis European buyers. The dismantling of the Gas Negotiation Committee (GNC) and Gas Supply Committee (GSC) after strong EU pressure has given room for a deregulated market regime with more dynamic individual contracting. Operations via the wholly state-owned grid company Gassco and a state led integration of grid ownership has, however, retained considerable state coordination. Furthermore, the proposed grid access regime also leaves considerable room for societal intervention. This chapter presents the main elements of the Norwegian oil and gas regime, as it was developed in the 1970s through to the 1990s. It then describes the transformation of this regime under the pressure of the European deregulation and the emergence of the new deregulated Norwegian gas market regime. The chapter ends with a brief discussion of how the transition may affect the existing bargaining balance between supplier and consumer countries.

5.2. The Regulatory Framework and the Appropriation of Ground/Cartel Rent As noted by Andersen (1988), Norway initiated its petroleum policy with high ambitions with respect to state regulation. The mechanism

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National Reforms in European Gas

used was a discretionary concession regime, based on competitive bidding for blocks, where specified work programmes were part of the concession terms. The concessionary system was based upon the model for developing the hydropower sector, where discretionary concessions for exploitation of Norwegian waterfalls had been in place since the turn of the last century (Haagensen and Rognstad, 1986).

5.2.1. Concession policy- rules and criteria The petroleum concessions were based on geographical division of the Norwegian Continental Shelf (NCS) into areas, or, so-called 'blocks'. The allotment of concessions was achieved through a discretionary system. The criteria for block allocation were: competence, financial strength, contributions to strengthening the Norwegian economy, and R&D. Public authorities at several levels were involved in discretionary allotment of concessions. The Norwegian Petroleum Directorate (NPD) mapped the blocks on the shell and gave recommendations to the Ministry of Petroleum and Energy (MPE) on the blocks that were considered ready for further exploration. Based on these recommendations, in addition to dialogue with the companies involved, the MPE prepared a proposal to the parliament, which subsequently decided which blocks were to be opened. Companies were free to apply for stakes in the chosen blocks whereby the MPE put together group of licensees (between three and five companies) for each block, and selected an operator company. The Norwegian Government finalised the allotment decisions of blocks based on the suggestions of the MPE. The authorities determined the allotment after approval by the individual companies (MPE, Fact Sheet, 1997). Thus far, there have been 17 rounds of block-allocations (Table 5.1). 1 The first allocation of blocks was in the southern part of the NCS. As additional blocks were conceded, new discoveries and the blocks were located increasingly further to the north, and recently exploration has taken place mostly outside the northern parts of Norway in the Barents Sea. From licensing round three and onwards (as can be seen in Table 5.1) operations were dominated by Norwegian companies. Still there are some exceptions to granting Norwegian companies the control of operations such as the Draugen field, smaller side-fields of 1This table is constructed by combining information from different tables in the MPE Fact Sheets 2001 and 2002.

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Table 5.1. Licensing rounds on the Norwegian continental shelf. Licensing round

Year

Number of blocks

1st

1965

78

1969-71 1973 1974-76 1977 1976-77

14 2 11 NA 9

1978 1979 1980-81 1982 1981 1982 1982 1982 1984 1985 1985 1985 1986 1986 1987 1987 1988 1989 1991 1991 1992 1993 1995 1995 1995 1996 1997 1998

1 8 6 6 9 1 5 3 17 13 1 8 9 1 11 11 16 13 36 1 3 31 1 1 1 46 25 11

NA NA

1999

28

NA

2000 2001 2001 2001 2001 2001 2001

34 7 1 1 1 1 1

NA Statoil NA Statoil NA NA

2nd BI 33/9-12 (Statfjord) 3rd BI 2/1 (Gyda) BI 1/9, 24/11-12, 15/8-9, 33/2-5, 15/2-5 BI 34/10 (Gullfaks) 4th 5th parts 1 and 2 5th part 3 6th BI 30/9 7th BI 31/3-5-6 (Troll) 8th 9th BI 25/2 10th A 10th B BI 25 / 1 11th A 11th B 12th A 12th B 13th Licensing round BI 31/7 BI 31/3-5-6 14th Licensing round BI 1/6 (Ekofisk) BI 34/10 (Gullfaks) BI 9/5 (Yme) 15th Licensing round Barents Sea Project BI 7/12, 33/12, 30/6, 25/5-7, 9/1-2-4... North Sea round 1999, mm. 1999 16th Licensing round North Sea round 2000 BI 15/6 (Glitne) BI 2 / 11 (Valhall) BI 15/5 (Glitne) BI 30/3 (HuIdra) BI 16/7

Awarded operators Exxon, Amoco, Philips Petroleum Elf, Exxon Statoil Statoil British Petroleum Statoil Statoil Norsk Hydro Statoil NA Norsk Hydro Norsk Hydro NA NA Shell, Statoil Statoil Statoil Statoil Statoil Statoil Norsk Hydro NA NA NA NA NA British Petroleum NA Statoil

Continued

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Table 5.1. Continued. Licensing round

Year

Number of Blocks

BI 7/1 BI 30/11 BI 2/9 BI 33/12 BI 30/6 BI 30/2 BI 43/9 BI 33/9 BI 1/3 17th Licensing round BI 6405/4,7,10 BI 6504/6 and BI 6505 / 1,2,4,5 BI 6605/5,7,8,9 and BI 6606/7 BI 6607/11,12 BI 6607/5 BI 6609/5,6

2001 2001 2001 2001 2001 2001 2001 2001 2001 2002 2002 2002

1 1 1 1 1 1 1 1 1 18 3 5

Norsk Hydro Norsk Hydro Philips Statoil Statoil RWE-DEA RWE-DEA Kerr-McGee Pelican/Dong

2002

6

Norsk Hydro

2002 2002 2002

2 1 2

Philips Agip Norsk Hydro

Awarded operators

Statoil Shell

the Frigg field, and in the developmental stage of the huge Troll gas field. Foreign companies now generally play a modest role as nonoperating licensees that initially were played by Norwegian companies. The blocks that have been awarded (see Table 5.1) are of a fixed size, 15 minutes of latitude and 20minutes of longitude. The strong position of Statoil in the rounds following its founding were in accordance with the intentions behind this company. The purpose of establishing Statoil was to create an active caretaker of the Norwegian interests on behalf of the state. The policy of allotting at least 50% of all blocks to state interests, has, since 1973, been done through Statoil, to enhance the Norwegian position. The Storting (Parliament) decided, at a later point in time, that the level of state participation might deviate from the minimum-50% principle, to benefit from different contingencies (MPE Fact Sheet, 2002). Apart from Statoil, two other Norwegian companies, Norsk Hydro and Saga Petroleum also built know-how and operator competence by way of political intent. 5.2.2. The tax regime and state income

Besides the discretionary licensing policy, taxation has been another major element in the Norwegian national control over petroleum resources. The taxation regime has changed significantly in response

Organising National Interests in the Gas~Petroleum Industry

71

to market developments and to shifts in national policy. The main phases of this development can be summarised in stages including three major revisions, respectively in 1975, 1986 and 1992. At the start of the petroleum activities on the Norwegian Shell petroleum taxation was modelled very much on taxation of onshore businesses, the biggest difference being the royalty (production tax) of 10% of gross value (Ot. prp. nr 47 1965). Additionally, there was an area tax of NOK 500 s q / k m the first year, then rising by NOK 500 per year to a maximum of 5,000. The municipal tax was 15%, and a deficit could be delayed up to 15 years. The first major revision came in response to the OPEC shock in 1973-74 when crude oil prices rose significantly. In only a few months the price increased four-fold. The new super-profits to be made in oil and gas production became a target for financing increased welfare state expenditures and a new law on the taxation of petroleum resources was passed. This new law sought to appropriate the new 'ground rent' or 'cartel rent' by introducing a production fee on a sliding scale (8-16%), corporate taxation as of onshore companies, special tax of 25% (increasing to 35% in 1980) calculated on the basis of net income from production and pipeline transportation, and by the establishment of a base-price for taxation purposes. 2 In addition the area tax was kept and a free, non-taxable income equal to 5% of gross investments was introduced. 3 The third oil price shock in the mid-1980s, with dramatically dropping oil prices, initiated a revision of the taxation scheme. The tax reform in 1986 changed the deduction criteria; it also changed the free income base for calculating the special tax and introduced production compensation. The rationale behind the latter change was to inspire the oil companies to exploit and develop new fields despite the low oil and gas prices. The production compensation was to function as an additional deduction on the bottom line when calculating the special tax. Also in this revision the special tax was set to 30%, down from 35%. The third petroleum tax reform was triggered by a general Norwegian tax reform in 1992 that also affected the petroleum sector. The purpose of the petroleum tax reform was, like the general tax reform, to provide more correct incentives for investments and better resource employment, thereby increasing the ground rent from 2When calculating the special tax, deductions are given for a free income in addition to ordinary deductions given on net income tax. 3Ground rent (or economic rent) refers to a kind of extraordinary yield the owner of the resource above what those resources could command in any alternative use (Buckanan et al., 1980).

National Reforms in European Gas

72

petroleum activities (Ot prp nr 12, 1991-92). After the reform, taxation of offshore activities again came to be based on onshore rules, with a 28% corporate tax as the basis. To compensate for the lower corporate tax, the special tax on petroleum production/exploration and pipeline transport activities was increased to 50%. However, the government was careful to secure incentives for further petroleum development and exploration. When calculating the tax, investments are therefore depreciated on a linear basis over six years and deductions for net financial costs are allowed. The production compensation introduced in 1986 was removed following the 1992 reform. This was due to the fact that the compensation led to asymmetric taxation of various fields, revenues and costs, in addition to administrative problems. Table 5.2 shows the magnitude of the various taxes still active after the reform. The current production tax (royalty) rate is 16% of gross production value and is payable

on production

January

1st 1986. N o p r o d u c t i o n

annual

from fields approved

for development

before

t a x is l e v i e d o n g a s p r o d u c t i o n .

a r e a fee c u r r e n t l y v a r i e s b e t w e e n

NOK

The

4,000 a n d N O K

5,000

Table 5.2. Paid taxes and fees, NOK bn (2002 value).

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001"

Corporate tax

Special tax

Royalty

Area fee

Carbon dioxide tax

Total

22.0 27.3 27.4 24.2 29.6 33.6 25.6 10.2 7.1 6.4 15.8 18.3 8.9 7.4 7.0 8.7 10.8 16.6 9.6 5.8 22.6 42.0

10.9 16.0 16.5 15.1 17.8 20.0 14.8 4.6 1.5 2.0 6.3 8.2 8.6 10.9 10.1 11.9 14.1 20.9 11.6 6.4 33.9 65.1

8.1 10.5 10.5 13.1 15.7 17.9 I2.0 10.7 7.6 9.6 10.8 10.9 9.6 9.0 7.4 6.5 6.9 6.7 3.9 3.3 3.6 2.5

0.1 0.1 0.1 0.1 0.1 0.3 0.3 0.3 0.3 0.3 0.3 0.7 0.7 0.6 0.2 0.6 1.2 0.7 0.6 0.6 0.1 1.0

0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.0 2.2 2.6 2.8 2.8 3.0 3.2 3.4 3.4 3.1 2.9

41.1 53.9 54.5 52.4 63.1 71.9 52.7 25.9 16.4 18.4 33.2 39.2 30.1 30.5 27.5 30.5 36.0 48.2 29.2 19.5 63.3 113.5

*Preliminary national planning budget figures. Source: MPE Fact Sheet 2002, Table 5.

Organising National Interests in the Gas~Petroleum Industry

73

per s q / k m in the exploration period and NOK 7.500 to NOK 121,500 per s q / k m in production period. Following a more general environmental awareness a CO2 tax was imposed in 1992. This CO2 emissions law is levied on Scm of gas burnt or directly released and per litre of oil burnt. The 1997 rate for CO2 emissions is NOK 0.87/Scm.

5.2.3. State income, a general overview At all stages, from exploration to sales, the Norwegian government has sought to appropriate economic rent from its petroleum activities. Cooperation with several multinational oil companies has been and will continue to be necessary, and some degree of profit sharing is required to attract desired level of investments for exploration and development in the sector. In addition to tax revenues, the government has appropriated revenues from the States Direct Financial Interest (SDFI) in oil exploration through its fully state-owned company, Statoil. This engagement only dates back to the mid-1980s. An overview of the Norwegian State net cash flows from the petroleum operations from 1971-2001 is shown in Fig. 5.1 below. The figure shows the net SDFI cash flow added to the state's tax revenues, measured on the vertical axis in NOK billion. As illustrated in Fig. 5.1, the state income from taxation and direct engagement has been highly volatile. The gradual build-up from the start in the mid-1970s to the mid-1980s was chiefly the result of increasing oil activities in Norway in combination with a premium-priced

Fig. 5.1. The Norwegian State's financial returns from the Petroleum operations, 1971-2001.

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National Reforms in European Gas

oil market resulting from the successful cooperation and coordination of the OPEC cartel in the Middle East. The fall of oil prices in the second half of the 1980s clearly indicate the vulnerability of the Norwegian petroleum tax system to changing market conditions. From a high level of over 60billion NOK in 1984, the sales revenue from petroleum dropped to less than 20billion in 1988. It rose to above 35billion again in 1991, but then fell below 30billion again in 1994, only to rise to new highs, close to 50 billion in 1997. The high volatility of state revenues cannot be explained by only one factor. The interplay between tax regimes, oil prices, how the state chooses to administer its engagement, and the general investment activity on the shelf, are all factors that have impact. The price of crude oil is, nevertheless, by far the most influential factor in explaining the income of the Norwegian State in the oil sector. As can be seen by comparing Figs. 5.1 and 5.2, the state income correlates with the crude oil prices - although not to an impressive extent. From Table 5.2 it is clear that the total state income (without dividend from Statoil) has followed fluctuations in the crude oil price. A closer inspection of the different tax components shows that corporate taxes have come to play a less important role compared with specialised 'ground rent' taxation such as special taxation and royalty fees. The addition of a new CO2 tax and a higher area fee have not mitigated the general decline of tax income. However, the large payoff from the SDFI has more than compensated the tax decline, and in 1996 and 1997 constituted a net income to the state coming close to that of the total petroleum taxation.

Fig. 5.2. Price of Norwegian crude oil, 1975-2001. Source: MPE Fact Sheet 2002, Fig. 9.1.

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75

The careful balancing between the two prerogatives of maintaining state 'ground rent' revenue and securing future investment in further offshore petroleum exploration has obviously made the inflow from taxation to the Norwegian state highly risk exposed. If tightened too much, taxation prevents future investment, however when lightened to create investment incentives the income flow becomes highly volatile. The direct state engagement in petroleum operations may here represent a stabilising factor. 5.3. The Build-up of a National Champion

One of the cornerstones of the Norwegian oil and gas model was the creation of a wholly state-owned oil company, Statoil, performing as a major vehicle for the Norwegian appropriation of petroleum rent. The Labour Party fronted the creation of Statoil as an important element in the Norwegian oil policy. However, the Statoil-policy was initiated in the wake of the Conservative Party's failing attempts to promote an electrochemical and electrometallurgical company, Norsk Hydro, to become a national oil champion. Statoil was established in September 1972 as a wholly state-owned company with limited responsibility. However, it took two years of debate and political negotiations before its statutes could be agreed upon. Controversy mainly involved issues concerning Parliament's ability and need to have control with the company. The political compromise reached on the companies' statutes implied a special obligation each year to present an outline of its plans, projects and economic dispositions of major political concern to Parliament (Stortings Tidende, 1973). The special obligations imposed and the process leading up to them did not take place without grievance for the Statoil board of directors, who strongly advised that the company be given more autonomy in strategic matters. Eventually, as a consequence of parliamentary approval of the regulations and as a consequence of other disagreements with the ministry, the chairman, in June 1974, withdrew from his position. The ministry could then replace the old board with a 'friendlier' one (Hanisch and Nerheim, 1992). In the beginning, Statoil had close ties to the regulatory authorities, particularly the Oil Directorate (Hanisch and Nerheim, 1992). These ties were gradually loosened after pressure from the Oil Directorate to attain more autonomy and a more impartial position in relation to the multitude of actors in the oil sector. Nevertheless, Statoil was clearly favoured in the assignment of blocks for drilling and exploration and the company was also given controlling positions in the development of the North Sea gas pipeline grid.

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National Reforms in European Gas

5.3.1. Statoil's position in the concession rounds Statoil's role in the concession rounds has evolved, first through gaining a 'favoured-company status' under the Labour government, and subsequently by having to channel an increasing amount of the oil revenue directly to the state, a practice that was institutionalised by intervention from a Conservative-Centre coalition government. The first two concession rounds, publicly announced respectively in 1965 and 1969, were held before Statoil was founded. At this stage, Norwegian national interests were limited to the Norwegian Government's claim on profits through concession fees and taxation. However during the second round, government views started to change and by the third concession round, 1973-1977, after Statoil was established, control was exercised by awarding the company a majority share of at least 50% in every block. This practice continued in all later rounds up to 1985. Statoil initially lacked drilling competence, and did not function as a block operator during the first years of block allocation. However, this soon changed, and the company received full operating responsibilities after having acquired sufficient knowledge from partnership operations with other companies (Hanish and Nerheim, 1992). The political deliberation and wrestling concerning the purpose and role of Statoil did not end with a regulation debate which place when the company was established. During the 1970s and 1980s the Conservative Party, both in opposition and in government, tried to diminish Statoil's role, importance in the Norwegian economy, and to cut back on its autonomy. The strong Social Democrat wing in Parliament managed to stop the Conservatives' attempts to play down Statoil's role up until 1985. The establishment of SDFI, the State's Direct Financial Involvement during the conservative Willoch government in 1985, marked a change in government policy. From this date, the state directly retained exploration licences in addition to Statoil's share. Statoil's traditional right to a 50% share was now to be reduced to 20%, as a practical rule, favouring 30% direct state interest at minimum. (St. meld. nr. 46, 1986-87). The establishment of the SDFI gave the state more direct access to the petroleum revenues, and reflected the conservative Willoch government's opinion that Statoil's position was too dominant. The SDFI arrangement means that the state itself pays their part of all investments and operating expenditure in a project. According to its share, the state then receives its part of production and income like the other stakeholders. However, the conservative coalition government accepted Statoil's position at the operative level, and Statoil thus continued to work as a

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caretaker on behalf of the government, with 50% control in all operational questions and decisive power as operator.

5.3.2. Statoil's position in the gas pipelines to the continent Besides its central role in drilling and production Statoil was also given a central role in control over gas pipelines and gas trade. Norwegian authorities have thus made Statoil a co-owner in all pipelines from the Norwegian shelf. This participation and control over the pipelines was important for as a means of securing royalty gas transport and their own gas to market. In the first 440-km gas pipeline from the Ekofisk reservoirs to Emden in Germany, Norpipe, Statoil obtained 50% ownership having contributed only 5% of the capital cost. In all of the other existing pipelines to the continent, Statoil is a majority shareholder, the exception being the two Frigg pipelines to England in which Statoil has only 24% and Norsk Hydro is the largest shareholder with a 32.87% ownership (for a systematic overview of pipeline-ownership see appendix A). The emergence of the North Sea continental pipelines was clearly in conflict with Parliament's expressed position in 'the ten oil policy commandments'. These commandments gave extensive guidelines as to how the resources in the North Sea should be exploited, to provide most benefit to society as a whole. One of the central elements was that Norwegian gas resources should be taken onshore in Norway (Hanish and Nerheim, 1992). However, the oil companies and a committee appointed by Parliament to advise on where to land the gas, the Ekofisk committee, clearly gave priority to economic considerations and argued that it would be very costly and technically difficult to lay pipelines across the Norwegian Trench. The committee's conclusion that the best solution was to build a pipeline and take the Ekofisk gas onshore in England was nevertheless welcomed and approved in Parliament in spite of the previous policy position. Protest came mainly from representatives from the rural Norwegian west coast, who had expected the 'oil policy commandments' to be followed and to bring new industry and jobs to this area.

5.4. The Development of Statoil Towards a Full-Scale Operator and Integrated Oil Company One of the critical elements in the Norwegian strategy to develop a national champion as an instrument of national control was the buildup of Norwegian drilling and production competence. Statoil drilled its first well in 1975 with a leased exploration rig. From then on the

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National Reforms in European Gas

company developed rapidly into an independent operator and was soon ready to take on bigger operating tasks. In order to build knowhow and competence in the early years, Statoil had closely cooperated with Exxon and Mobil (Johnsen, 1990; Hanish and Nerheim, 1992). This was partly done by letting the partner/cooperator be the technical operator while Statoil itself remained formal operator, thus allowing Statoil's own personnel to work alongside the partner's skilled workforce. In 1980 the company had acquired both the knowledge and the capital basis required to become fully operational (Andersen, 1993). There was however, considerable political debate as to whether Statoil should be just a production company or an integrated oil company. The company's board of directors and CEO always sought the integratedcompany solution. The political opinion shifted with varying governments. The Labour Party and the socialists wanted a state-owned company, but were not quite sure about the scope of it. The conservative parties, however, did not like Statoil at all. Allowing Statoil to sell petroleum-based products at a retail level was therefore a matter that was not thoroughly dealt with politically until the mid-1980s.

5.5. Development of the Company Statoil's growth during the 1970s was spectacular. The number of employees increased from 54 in 1973 to 244 by year-end 1975. To develop the company into a fully integrated oil company, key personnel were needed. Statoil found it hard to find qualified technical personnel in Norway and soon realised that they would have to go abroad in order to hire key personnel. Therefore, during the first few years, many foreigners were employed in key positions in Statoil.

5.5.1. Financial development Financial data reveals that Statoil has had an almost continuous financial growth since its foundation in 1972. There have been a few setbacks however. The major one in 1987 was due to a costly explosion on the Mongstad refinery, which also cost the CEO Arve Johnsen his position. Since most revenues are from the sale of crude oil, Statoil is very dependent on the market price of oil and the exchange rate of Norwegian kroner versus the US dollar. Nevertheless, the company has continued to grow both in terms of size, knowledge, and scale of operations, in spite of large fluctuations in oil prices and revenues. Figure 5.3 shows the recent financial development of Statoil.

Organising National Interests in the Gas~Petroleum Industry

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Fig. 5.3. Statoil's earnings, 1997-2001. Source: Statoil Annual Report, 2001.

5.5.2. Organisation structure and phases Statoil was organised into ten divisions: security and quality enhancement, R&D, information and community contact, law and secretary to the board, financial and administration, technology and development, exploration and production, transport, refining and marketing. In addition there are a total of 16 business areas in the Statoil Group. The company headquarters was established in 1972 in Stavanger, and has since remained located there. Statoil's first international establishment was in the petroleum retail business in the Nordic countries. Gradually the company received operating responsibilities and licences abroad and in various locations around the world.

5.5.3. The Norwegian gas sales model Exploration of North Sea petroleum resources has over the last 30 years revealed large gas deposits, turning Norway into one of the major European gas suppliers. Unlike oil, which can cost-effectively be transported over vast distances with tankers, transport of gas in this

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National Reforms in European Gas

manner is expensive as the gas needs to be liquefied (LNG) in a costly and energy intensive process. Gas from the NCS is therefore brought to the European market through pipelines, which allows the gas to be transported off the field without further processing. Figure 5.4 shows the existing and planned pipelines to the continent. A grid-based gas supply system requires heavy investment in infrastructure. Lengthy negotiations to establish the financial basis for such investigations therefore often precede the gas sales, and hence, the sales contracts tend to be based on long-term agreements. The market for Norwegian gas has primarily been member states of the European Union, excluding Great Britain, Denmark and The Netherlands, who have been self-sufficient in gas supply. The remaining EU countries have been dependent on imports to cover their needs. In addition, Norway has signed an agreement for gas export to the Czech Republic. In addition to the pipelines from the NCS, there are pipelines to the EU from Russia and Algeria. The competitors for Norway are therefore domestic production within the EU and imports from Russia and Algeria. Of these, Russia has the biggest reservoirs and production capacity, producing 715billion Scm of gas in 1996, equal to 30.9% of world production. Norway, in comparison, produced 38billion Scm or 1.6% of total world output. There are also future plans for large expansions in production. The Norwegian gas sales can be divided into two phases based on the nature of the underlying contracts. One type of contract, called 'depletion contract', is that in which the buyer agrees to purchase all the gas extracted from a particular field (Table 5.3). The other type of contract specifies the amount of gas to be supplied to the seller without reference to any specific field (Table 5.3). Phases can also be discerned on the basis of the organisation of the negotiations on the Norwegian side. The earliest contracts, until 1973, were negotiated by individual companies. Later, from 1974 to 1986, Statoil held a monopoly on negotiating contracts. Between 1986 and 2002, contracts were negotiated centrally through the Gas Negotiations Committee (GNC), an institutionalised cartel set up by the Norwegian authorities. Presently, the negotiations take place on an individual company basis, due to the major structural changes that have taken place, involving the abolition of the GNC, effectively from January 1st 2002.

5.5.4. The first phase of gas sales The period from 1973 to 1986 marked the first phase of Norwegian gas sales. It was characterised by the strong influence Statoil had on

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81

Fig. 5.4. Existing and planned gas pipelines from the Norwegian continental shelf (as of 2002).

the Norwegian side in the negotiations, apart from the sales contracts from the Ekofisk and Frigg fields, which were negotiated by Phillips Petroleum and ELF respectively (Table 5.3). During this period all contracts were depletion contracts. Prices agreed to during this period were relatively high due to high oil prices and high demand for less polluting alternatives to coal and refined petroleum.

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National Reforms in European Gas

Table 5.3. Norwegian gas sales based on depletion contracts and individual company/ Statoil dominated negotiations. Year

Seller/Negotiator

Buyers

Amount

1973, 1975 Phillips Group

1977-

1973

1977-2000

1981 1981 1981

Ruhrgas, Gasunie, 260billion scm, Distrigaz, GdF total ELF British Gas 110billion scm, total Statoil, Statfjord Group Continentalbuyers 60billion scm Statoil, Heimdal Group Continentalbuyers 40billion scm Statoil, GulIfaks 1 Group Continental buyers 20billion scm

Duration

To depletion To depletion To depletion

Source: Royal Norwegian Ministry of Oil and Energy, Statoil AS.

Given the high oil prices in the aftermath of two major oil crises, in 1972-73 and 1978 and the European and OECD obsession with security of supply, the Norwegian negotiators held very good cards in negotiation over gas from Frigg, Ekofisk, Statfjord and other affiliated fields. The strong Norwegian position was made up by having ample gas to sell close to the market and guaranteed deliveries. The first agreement on gas sales to the continent, negotiated by Phillips, was signed in Oslo in January 1973. The signing of this contract however, came before the oil crises had any impact on the negotiations. Therefore the price agreed was rather low. Gas started flowing from the Ekofisk field through the Norpipe pipeline to Emden in Germany in September 1977 and marked the start of dry gas sales from the Norwegian Continental Shelf. The second pipeline, Frigg Transport from the Frigg field to St. Fergus in Scotland, came on-stream in August 1978, and thus marked Norway's becoming a major supplier of gas to EU area. The next round of negotiations concerned gas from the Statfjord field. In negotiations with potential buyers of Ekofisk and Frigg gas, the price reached was close to the price of light heating oil, which was the norm at the time. By now the major gas buyers in Europe were worried about the future situation for petroleum fuels and were willing to discuss a price increase for gas. Statoil, now monopolising the negotiations on behalf of the sellers, wanted gas prices to contain a crude oil parity condition. In the final agreement, reached with a consortium of continental buyers the price did not reach crude oil parity, but was the highest price ever paid for gas to Europe (Nerheim, 1996). The gas from Statfjord, Gullfaks and the Heimdal field were to be transported through a new gas pipeline, starting on Statfjord via Kdrsto in Norway to the gas terminal in Emden, Germany. This agreement fulfilled the long time dream of landing

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gas f r o m the N o r w e g i a n shelf in N o r w a y ( N e r h e i m , 1996). The n e w pipeline, Statpipe, a 880 k m s y s t e m w i t h t w o riser p l a t f o r m s a n d a t e r m i n a l at Kdrsto, c a m e o n - s t r e a m in O c t o b e r 1985 h a v i n g for the first time in h i s t o r y crossed the N o r w e g i a n Trench.

5.5.5. The second phase of gas sales The s e c o n d p h a s e started out b y the p h a s i n g in of the Troll field in the sales contracts. Unlike earlier contracts, the so-called d e p l e t i o n contracts, N o r w a y n o w sold its gas in s u p p l y contracts, w h i c h m e a n t that the b u y e r b o u g h t a specified a m o u n t of gas, to be s u p p l i e d b y the seller w i t h o u t reference to specific fields. A n o t h e r characteristic of the s e c o n d p h a s e w a s the e s t a b l i s h m e n t of the Gas N e g o t i a t i o n s C o m m i t t e e , G N C (Table 5.4). The c o m m i t t e e consisting of Statoil, N o r s k H y d r o a n d Saga P e t r o l e u m w a s n o w set in c h a r g e of all gas sales on behalf of o t h e r licensees. H o w e v e r , b o t h the g o v e r n m e n t a n d the licensees c o u l d d i s r e g a r d the n e g o t i a t e d deals, a n d if a licensee could sell its gas at a h i g h e r price s o m e w h e r e else, the gas could be sold i n d e p e n d e n t l y of the G N C . Also the licensee c o u l d choose to use his share of the gas in his o w n facilities.

Table 5.4. Norwegian gas sales based on supply contracts and coordinated negotiations. Year Seller/Negotiator

Buyers

Amount

Duration

1986 1988 1988 1993

Statoil, Troll Group GNC, Troll Group GNC GNC

2 billion scm 4 billion scm / year

-

56 billion scm

1996-2010

1994 1994 1994 1994 1995

GNC GNC GNC GNC GNC

Austria Enagas and SEP SEP Distrigaz, Verbundnetz Gas, Ruhrgas GdF German Mobil (MEEG) Scottish Power Enagas GdF

4 billion scm/year 13 billion scm 1.7 billion scm I billion scm Additional volumes, 2 billion scm / year 264 million scm Additional volumes to 1996 150 billion scm 53 billionscm 2.2 billion scm I billion scm / year

19961996-2014 1995 1994-1996 -

1995 GNC, Froy Group 1996 GNC

Bord Gais Eireann Ruhrgas

1997 1997 1997 1997

SNAM TRANSGAS National Power Naturkraft AS

GNC GNC GNC GNC

Source:Royal Norwegian Ministry of Oil and Energy, Statoil ASA.

1997 25 years, 200020 years, 1997-

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More specifically, in the early and mid-80s the gas supply situation in Europe improved, and turned into a surplus. There was ample gas from the various supplier fields, gas consumption flattened out and in some countries declined. The dramatic oil price falls obviously also had a strong negative effect on gas prices. When Statoil started negotiations with potential buyers of gas from the Troll field, the price could therefore not be expected to be as good as the one agreed on in the Statfjord negotiations. The Norwegian negotiators felt the pressure from Russian and Algerian gas and were afraid that a wait-and-seeattitude would lead to a loss of market shares (Nerheim, 1996). In order to come to an agreement with a continental consortium, concessions were given by allowing for renegotiations of the price on gas delivered from the Statfjord field and by allowing the price of gas delivered at the border to follow what the other sellers charged. On the other hand, it was agreed that contrary to earlier deals where the buyers bought gas from a certain field, this time the gas would come from several fields. The Troll field, which accounted for 65% of all known petroleum resources in the Norwegian sector, would serve to guarantee steady supplies. This strategy was crucial for the development of smaller fields, like the Sleipner field, that were not considered financially viable on their own. The Troll agreement was the largest agreement until then reached for Norwegian gas, and the deliveries would reach a plateau level of 20 billion Sin 3 per year from 2002. The Troll agreement also resulted in the construction of a new pipeline from the Sleipner Platform to Zeebrugge in Belgium, the Zeepipe. In retrospect, analysis have asked if the price agreed upon for Norwegian gas was too low (Nerheim, 1996). It seems that the authorities, over-riding concern to secure industry jobs came in the way of a better deal. At the time, it was known that both the Groningen field in the Netherlands and the fields in the British sector would not be able to uphold their current plateau levels long after the turn of the next century. In light of this and the fact that strategically European gas companies did not like to commit themselves to just one or two suppliers, Russia a n d / o r Algeria, the negotiators might have better exploited the fact that Norwegian gas would offer considerable flexibility and diversification of the gas supplies to the European continent. In addition to the deals already signed, Norwegian sellers have negotiated with POGC in Poland, Dangas in Denmark, MOL in Hungary, Alliance Gas in the UK, and Board Gais Eireann in Ireland. These deals partly prolonged old contracts, and partly resulted in altogether new deals.

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5.6. The Gas Negotiation and Supply Committees The Gas Negotiations Committee (GNC) has, until recently, been a peculiar feature of the Norwegian oil and gas model, and deserves a special attention. The Committee (GNC), traditionally consisted of Statoil, Norsk Hydro and Saga Petroleum, and handled the gas sales from the Norwegian Continental Shelf. The GNC is a state-authorised coordination organisation, created to maximise the Norwegian State's interests in sales and dissemination activities from the petroleum sector. The GNC, for an extended period of time, provided stronger bargaining power for the Norwegian producers, than they would have had as individual companies. For many years, the GNC negotiated unilaterally with potential buyers on behalf of all companies active on the NCS. The rationale behind preventing foreign companies from direct participation in the GNC was that most of them also had ownership in companies on the demand side of the negotiation table, a situation that could easily run to counter the financial interests of the Norwegian State. The GNC had the status of permanent advisory committee to the Ministry of Petroleum and Energy (MPE) in matters connected to the usage and transport of natural gas. Thus, it is the MPE that formally had the final say in approving a gas sales contract. In practice, however, the GNC enjoyed a great deal of autonomy, bordering on decision-making authority in some respects 4 (Helle, 1991). While the GNC has taken care of the external negotiations of contracts with continental buyers, the so-called Gas Supply Committee (Forsyningsutvalget (GSC)) has taken care of internal coordination between the gas suppliers on the Norwegian Continental Shelf. The GSC was a more broadly based organisation than the GNC, and included most of the licensees on the Norwegian Continental Shell including foreign-owned companies. The coordination by the GSC and GNC vis-a-vis continental buyers has not been without friction. Members have had difficulties agreeing on which fields to supply specific contracts. This was the case in 1993 with the signing of a contract with Distrigaz of Belgium and in 1994 concerning supply decision on which fields to serve the deal with German VNG (Reuters News Service, 1994). In 1995 a great deal of controversy was raised when Saga wanted to sell gas through its subsidiary in Germany to Wingas. Saga claimed that the other two

detailed discussion of the functions and mandate of the GFU is given in Chapter 11 of Report to the Storting No. 46 (1986-87).

4A more

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members of the GNC pressured the company into shelving the plans, which would have amounted to 1.5bcm annually for 15 years. Statoil denied that any actions had been taken against the Saga-Wingas deal and said that Saga was free to sell its own equity gas to Wingas, but that the GNC at the moment did not want to sell to Wingas. Later, according to Saga, Norsk Hydro and Statoil mobilised such strong opposition that they effectively denied Saga the right to use its own equity gas to fulfil the agreement with Wingas. Wingas ended up buying gas from the British sector and later signed new contracts for additional volume through the Interconnector pipeline (Reuters News Service, 1994).

5.7. Exported Volumes Norwegian gas exports in 1996 amounted to 38.1 billion scm, up 38% from the previous year. The main buyers were France and Germany. Figure 5.5 shows buyer country imports in percentages (Norwegian Petroleum Directorate, 1996). From the first gas deliveries from the Ekofisk field to Emden in September 1977, Norway sold gas to a number of buyers, with Germany unloading a major part of the gas. The major players unloading Norwegian gas in these countries have

Fig. 5.5. Norwegiandry gas exports to Europe (2001). Source:MPE Fact Sheet 2002,Fig. 9.6 (originallyfrom the National Petroleum Directorate).

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recently been Ruhrgas, Thyssengas and BEB (Germany), Gas De France (France), Distrigas (Belgium), British Gas (UK), SNAM (Italy), SEP (Netherlands) and Enagas (Spain). Given the 2001 level, contracted gas supplies from the Norwegian gas sector are expected to reach a plateau level for delivery of about 70billion scm in the years 2004-2014, thereafter declining rapidly. However, as new fields are discovered and with new negotiations, it is possible that the prospect for Norwegian gas will be revised and extended further into the future, as has already happened with previous forecasts. Contracts are most likely to be struck with the UK and Ireland as there is much available pipeline capacity and these countries soon will have drained their own domestic resources. In terms of market share in the European gas market, Norway enjoys a comfortable position. Continental Europe is today heavily dependent upon Norwegian deliveries. As can be seen from Fig. 5.6 this position has been strengthened substantially during the recent years.

Fig. 5.6. Market Share in the European Gas Market in 2001. Source: Energy Information Administration, Official Energy Statistics from the U.S. Government (Original source: Statoil).

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5.8. Domestic Consumption In spite of its huge gas reserves, Norway has not developed a substantive domestic gas market. Consumption of natural gas in Norway has thus far been very modest. In 1999 domestic consumption was estimated at 100 million scm. The low usage of gas in Norway is mostly due to topographical conditions and the low electricity prices. Extensive construction of pipelines in Norway is not economically viable on commercial terms, with a highly dispersed population and rough terrain. However, there is a potential for increased gas usage in the surrounding cities to the existing processing plants. In the City of Bergen, plans for gas-driven citybuses and gas-fired local CHP in buildings have been initiated. In the short run the plans in Bergen imply an annual consumption of 30 million scm. Gas in industrial processes is for the moment the dominant use in Norway. The industrial gas consumption is located close to the existing land-based processing facilities for natural gas at Tjeldbergodden (North-West), Kollsnes (West) and Kdrsto (SouthWest), and includes a methanol factory which consumes 800million scm per year. Existing plans to build gas-fired CHP plants in different locations is a new feature of Norwegian energy policy and, if implemented, will increase the domestic consumption extensively. The plans include building two power plants at Kollsnes and Kdrsto in West Norway and one power plant in Skogn in Mid-Norway. These plants if built will consume 2.4billion scm annually. The implementation of these plans is, however, pending final government approval and the questions of if and when realisation will take place are uncertain as yet. Should the Skogn Power Plant be built there is a high probability for a pipeline into the City of Trondheim, where the potential for gas usage is close to that in Bergen.

5.9. Active Policy for the Norwegian Supply Industry As part of its approach to maximise Norwegian returns from the gas industry, the Norwegian model also contains an active policy to promote spin-offs to Norwegian supply industry. The Norwegian authorities were aware of potential returns to Norwegian industry from offshore activities at an early stage of the offshore development. The Ministry however, did not go so far as to vouch for protectionism on the continental shelf, but saw fit to pass a Royal decree stating that if Norwegian companies were competitive with respect to price, service, quality and deliveries, they should be preferred to foreign

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companies (Royal Decree, 1972). Norwegian authorities also introduced programmes for investment in Norwegian industry and Norwegian R&D, so-called Goodwill programmes as part of the criteria for assignment of concessions for oil and gas exploration. These programmes fund approximately 80% of Norwegian R&D in the Oil and Gas industry. Three sectors stand out as major areas for industrial return from Norwegian petroleum activities: Shipping and transport, maritime engineering, and consulting. The following section briefly discusses each of them.

5.10. Shipping and Transport Norway, in the early seventies, had an active maritime and engineering industry traditionally occupied with shipbuilding and contracts for local industry. In the mid- and late-1960s shipping rates were high and the shipping industry was prospering. This boom was followed by extensive shipbuilding, resulting in a gross over-capacity on the world market in the 1970s. This spelled trouble for the many shipyards as customers could not pay for ships they had ordered. The industry searched desperately for new assignments. The activity on the Norwegian Continental Shelf was a welcome stimulus and ship owners turned their focus to offshore activities. The first contracts were on regular supply- and rescue/stand-by ships but quickly the focus shifted to include mobile rig vessels (Hanisch and Nerheim, 1992). Today a number of Norwegian ship owners have ships on supply charters for oil industry, both in the Norwegian and the British sector. Another consequence of offshore activities was the need for helicopters to transport people out to the fields. Norwegian-based Helicopter Services Group (HSG) was until recently the world's largest helicopter company, judging by turnover, which is NOK 2.165million (it is now owned by CHC Helicopter Corporation).

5.11. Maritime Engineering Even though the Norwegian authorities tried to pressure foreign operators to choose Norwegian contractors, there were initially strong barriers against the Norwegianisation of maritime engineering. Oil companies claimed that Norwegian companies were not ready for such tasks (Nerheim, 1996) and tended to use their traditional contractors from other fields to the North Sea. In many cases they did

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not even bother to translate the tender into Norwegian. In contracting the first instalments in the Norwegian Sector, Norwegian contractors were therefore not handed any assignments. However, a growing number of Norwegian ship owners started to invest in offshore activities and the engineering and shipbuilding company Aker, partly owned by ship owner Fred Olsen, received their first order for the newly developed drilling rig, H-3. This order in the fall of 1971 kicked off a boom in the Norwegian construction and engineering industry. In 1973 the Condeep platform, a legend on the shell was developed. Optimism ruled even in Parliament and report nr 25 (Ministry of Industry, 1973) on the oil economy in 1973, stated clearly that from now on Norwegian contractors could expect a 'golden age'. During this up-turn period the only major concern was over which groupings of Norwegian constructors should be handed major contract awards and how they could build their competence and reliability fast enough to service the oil industry. In particular the Aker and Kvaerner groups fought hard over the important deck construction on Statfjord B. Norwegian Petroleum Consultants had already been handed the consultancy task, and the Norwegian Contractors had the Condeep platform base. Aker had built the Statfjord A deck, however not totally satisfactorily, but were still seen as the favourite candidate to the B deck construction task. In order to satisfy the foreign owned oil companies, the assignment had to be made as a public tender. In this tender the Kvaerner Group surprisingly won the contract, signalling more intense competition for contracts in the future. Available data from 1984 to 1996 suggest that on average, the Norwegian contractors and sub-contractors, once they entered the market, have been rather successful in keeping offshore development assignments in Norway. As Fig. 5.7 shows, the percentage of commodity costs accrued abroad varies a lot, but the domestic part of the commodity costs remains between 70-80%.

5.12. Consulting The third major field of industrial return from the oil industry was in consulting. As for the maritime engineering business, foreign companies were dominant during the first years. In the development of the Ekofisk field, all construction and consulting work was done by US and UK based companies, and on the Frigg field French and British companies were prominent.

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Fig. 5.7. Commodity costs accrued abroad. Source: Statistics Norwa~ 3rd quarter 1996.

The Norwegian authorities knew that if Norwegian sub-contractors and services were to be used during the building of the platform it was essential that Norwegian companies were involved from the very beginning of field development. This required Norwegian consultants to be involved at the drawing board stage. On initiative from Statoil, Norwegian Petroleum Consultants, NPC, was founded in late November 1975. The reason forming NPC was that existing Norwegian engineering consultants did not have the size nor the competence required to carry out a full-scale development of an oil field. The participants in this venture were ten Norwegian engineering and industrial enterprises. Among these were Aker and Kvaerner, who also competed on the contracting side. Immediately after its establishment, NPC was handed the task of planning and constructing the Statfjord B platform (Johnsen, 1990). As with the development of Norwegian offshore drilling competence, a foreign company was chosen as a partner and tutor to the Norwegian company. In this the first major Norwegian attempt to construct and build a platform on its own, Brown & Root was elected partner. This choice did not take place without a struggle between the oil companies which all wanted their own favourite elected. This time it was Mobil, the field operator, who got its favourite elected. Further development of Norwegian consulting companies has followed that of the petroleum companies with moves towards

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vertical integration. NPC may serve as an example of this. The company was listed on the Oslo Stock Exchange in the late 1970s and was then bought by Aker Maritime in 1992 in order to become an integrated part of Aker's activities. There are currently several companies in Norway that can carry out the entire process of developing a petroleum field from the drawing board to on-stream production. Among these are Umoe, Aker Maritime and Kvaerner.

5.13. Deregulation and Fundamental Revision of the Norwegian Model The Norwegian gas model, as it appeared in the 1990s, has undergone fundamental revisions in the early 2000s as a response to both national and international issues. First, the need to adapt the Norwegian gas regime to the EU Gas Directive has been a major issue for several years. Second, the need for greater separation of business and politics has been voiced by both company managers and conservative politicians. Furthermore, Norway's influential and pioneering role in deregulating the electricity sector has provided a model for deregulation in other energy sectors. The Norwegian position, as a dominant supplier to the European gas market, gives the country special interests to take care of vis-a-vis its European counterparts. Like other large suppliers such as Russia and Algeria, Norway indeed has largely conflicting interests to those of the consumer-dominated EU in the geopolitical oil and gas game. This complicates its deregulation policy in the gas sector and may explain the reluctance and caution that characterises recent policy initiatives. New challenges for the 2000s relates to all of the four elements of the earlier Norwegian model: (1) the regulatory framework (2) the public ownership, (3) the strategic organisation of sales-procedures to maximise Norwegian interests vis-a-vis European buyers, and (4) the securing of industrial return from oil activities.

5.14. Privatising Statoil and Establishing Petoro: A New Institutionalisation of State Control

5.14.1. Statoil Subsequent to vigorous arguments from Statoil's CEO and pressure from right wing parties, the government decided to allow for more owners of Statoil by listing the company on the stock market (Ministry

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of Petroleum and Energy bills no. 36 and 48 2000-2001). The government argued that expanding ownership would provide new expertise, partners and capital. Some of the 'national champion philosophy' still remains, however. Statoil remains a Norwegian-based company. Its head office and associated top management, decisionmaking authority and strategy functions, will still be located in Norway. As part of privatisation, the Norwegian government opens up the possibility of equity-based strategic alliances with other companies. The labour government that executed the partial privatisation has expressed a wish to retain at least three-quarters of the ownership in public hands. The conservative party, which dominates the coalitiongovernment that came into power after the 2001 elections, has expressed an openness to further privatisation, down to a blocking minority position (34%) for the state. On June 18, 2001 Statoil was partially privatised, and listed on the Oslo and New York Stock exchanges. State ownership was decreased to 81.8%, and the partial privatisation brought roughly 60,000 new owners to the company. Most of the newly issued shares contribute to internationally diversified ownership (the largest being institutional owners from US).

5.14.2. Petoro AS Following the partial privatisation of Statoil, the Norwegian government established a new vehicle for management of the state interest in the petroleum sector, Petoro AS. This is a state-owned limited liability company now manages the State's portfolio of interests in production licences, pipelines and land-based plants. Petoro manages the major part of the Norwegian States Direct Financial Interests (SDFI) in the oil sector, which represents a substantial part of Norway's national wealth. Petoro's core task is to maximise the value of these assets. The value of this portfolio is several times greater than Statoil ASA. The company also has the role of monitoring Statoil's duties related to sale of petroleum produced from the SDFI. As part of the privatisation of Statoil, 20% of the SDFI were sold out, 15% to Statoil and 5% to Norsk Hydro. Petoro AS operates in an intermediary position, between a state bureaucracy and an operative company. It manages the SDFI assets at the state's risk, and expenditures and revenues pertaining to the SDFI assets will continue to be channelled through the central government budget. On this

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basis, it will function as a licensee and contract with petroleum companies for the actual operation of the licenses. Petoro does not, however, have the mandate to function as an operating company on the Norwegian Continental Shelf, nor does the company have the mandate to sell its own oil and gas. This confines Petoro to a functional segment focussing on tasks related to finance, management and decision-making. Recently, however, Petoro has expressed the desire to move into a broader scope of activities, especially focussing on petroleum research (Aftenposten, June 15th 2002). With the minority-share privatisation of Statoil and the Government control through Petoro, it may be argued that the national champion policy and commercial engagement by the Norwegian Government has undergone fundamental change in shape, but has not disappeared.

5.14.3. Gassco AS As part of the new regime a separate company, Gassco, was split off from Statoil to operate the North Sea gas grid. Gassco was created in 2001 and is wholly owned by the Norwegian State as a vehicle for running the transport system for natural gas on and from the Norwegian continental shell hereunder pipelines and terminals. The company became operative as of January 1, 2002. Forming a fully state-owned system operator complies with the ideal deregulation requirements of a neutral actor in this position and also retains public control with the grid system. Gassco does not itself own grids, but merely coordinates the gas transport pipes and processing facilities on the Norwegian continental shelf, which are owned by others. However, as part of the reorganisation in the wake of the GNC/GSC, the Norwegian government also negotiated an agreement among all the participating North Sea operators to establish a jointly owned gas infrastructure. Consensus was reached, between all parties for rich and dry gas facilities that today are or will be used by others than the owners. Facilities that are only used by owners remain under separate ownership. Gassco is mandated to ensure that transport and processing on the Norwegian continental shelf shall serve all producers and contribute to efficient utilisation of resources. This mandate is best served, according to the Norwegian Government by a unit, which is neutral in relation to all users of the transport system. The mutual dependence between the pipelines requires that the grid be operated as a unified

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system. In this regard, Gassco continued functions previously taken care of by the GSC. 5.15. Dismantling of the Gas Negotiation Committee and Establishment of a New Regulatory Regime The most controversial part of Norwegian policy revisions has clearly been the abolition of the third element of the traditional Norwegian gas regime, namely, the strategic planning and Gas Negotiation Committee (GNC). As noted above, the EU clearly forced this move upon Norway as part of a shift in the regulatory framework. On the one hand, the EU position had been that Norway, as part of the development of the European Economic Area Agreement should implement the EU Gas Directive, opening competition and third party access in the North Sea upstream grid. The Norwegian government, represented by the Ministry of Petroleum and Energy, on the other hand, clearly stated that the government's legal view on the matter was that the joint organisation of North Sea producer interests in the GNC fell outside of the European Economic Area Agreement, and that even if it were to fall within, a clause within it would provide sufficient legal basis for the committee's right to operate. This position was clearly expressed in Prime Minister Kjell Magne Bondevik's letter to his European colleagues on November 24th 1997.5 ... I would like to take this opportunity to recapitulate to you the Norwegian concerns regarding the proposed directive. From our point of view the directive will weaken our possibilities to continue administration of our petroleum resources on a cost-efficient basis. Ever since the oil and gas activity first started up in the North Sea in the late 1960"s, Norway has developed an integrated gas production system as part of our petroleum resource administration. This whole system involves a complex interplay between platforms, gas grids and landing terminals and ensures full utilisation of the entire production system, a high resource recovery rate and a high cost-efficiency ratio. Norway is an important oil and gas supplier to the EU. The Norwegian Continental Shelf contains close to 50% of all localised oil and gas resources within the EEA. We are very concerned that the proposed gas directive will influence on our abilities to sustain the integrated production system and thereby weaken our ability to ensure stabile, long-term energy supplies to

STranslated to English by the authors.

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After several rounds of resistance, however, the Norwegian government, facing a possible case in the European Court, backed down. It therefore decided to temporarily discontinue marketing Norwegian gas through the Gas Negotiation Committee to the European Economic Area as of 1 June 2001 and permanently abolished this in January 2002. 6 The EU directive has subsequently been explicitly integrated into the Economic Agreement between the EU and Norway. The dismantling of the GNC/GSC system clearly illustrates the power of the EU regulation over domestic Norwegian regimes. By way of domestic justification for this manoeuvre, the Norwegian Government has pointed out that the increased maturity of the oil and gas activities on Norwegian continental shelf implies that much of the oil and gas production facilities and the necessary infrastructure has already been put in place. The Ministry of Oil and Energy has therefore seen a diminished need for coordinated organisation, to support new investments. Furthermore, the Ministry has interpreted the deregulation of European end-user markets for gas to imply larger recursion to shortterm contracts, with more and smaller short-term sales. The GNC/GSC systems were primarily designed for longer-term large-scale contracts, and would not be able to handle the decentralised contracting on the short-term spot market. Companies have also voiced an interest in direct handling of their North sea resources to supply their Continental European business units for the European market. Parallel to the dismantling of the GNC/GSC system, the government has, however, continued to refine the regulatory regime, which still includes exploration licences, the rights to influence and decide on plans for exploration or operation, plans and operation of installations (St meld. Nr 38(2001-2002)). Some of the basic elements of the public revenue creation of the traditional Norwegian model therefore have remained.

5.16. The New Regulatory Model for Gas Transport The acceptance of the EU directive on gas implies that a grid regulation regime must be established that is much in line with the

6press releases from the Ministry of Oil and Energy, 29-05-001 and 13-06-01.

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earlier electricity grid regulation. However, the North Sea upstream regulation has been far less radical than that of electricity, probably reflecting the hesitance to unleash full upstream competition in a situation where downstream competition remains uncertain. In the first place, access is therefore limited to natural gas undertakings and eligible customers 'who have a duly substantiated reasonable need for transportation or processing of natural gas'. 7 Second, although access is formally proposed to take place on objective and non-discriminatory conditions, there is no provision for standardised tariffs and systematic congestion management of the type found in electricity. Third, the access is conditioned by complex technical conditions, which leave considerable room for judgement. The right to use capacity in the upstream pipeline network is subject to the specifications of the natural gas to be transported a n d / o r processed being reasonably compatible with the technical requirements, and the efficient operation of the upstream pipeline network. The operator may furthermore refuse access if the conditions for the right of use pursuant to this provision are not satisfied. The gas grid regime also favours long-term contractors, as rights to use spare capacity on a long-term basis are allocated before rights to use long-term spare capacity on a short-term basis. The grid owners (who are also the upstream producers) are favoured in the proposed regime in terms of allocation of spare capacity. 'Consideration shall first be given to the owner's duly substantiated reasonable needs, limited u p w a r d s to the double of the owner's equity interests in the upstream pipeline network in question'. 8 The tariff regime is also fairly judgemental. The proposal basically signals a cost-plus regime where the Ministry may determine which costs shall be taken into account when calculating the operating element. However, the Norwegian regime is here hardly less fuzzy than many of the EU regimes, and the EU may find it hard to press for a stronger UK-type deregulation upstream with downstream deregulation so clearly lagging behind.

7preliminary draft laid down by a Royal Decree of 2002. Laid down pursuant to Act 29 November 1996 no. 72 relating to petroleum activities, Section 10-18 first paragraph and Section 4-8. 8preliminary draft laid down by a Royal Decree of 2002. Laid down pursuant to Act 29 November 1996 no. 72 relating to petroleum activities, Section 10-18 first paragraph and Section 4-8.

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5.17. Final C o m m e n t

The implications of giving up the Norwegian protectionism, embedded in the GNC and an industry-controlled transport-system, depend very much on the deregulation process on the European continent. If the EU effectively implements its new Gas Directive smoothly, the transition to a more open and competitive structure can more easily take place with corresponding ease on the Norwegian continental shelf. It seems most likely that if the Gas Directive is effectively implemented it will mean the end of monopolistic buyer consortiums on the European continent. The core argument justifying the GNC would then no longer be valid, as a strong united Norwegian seller would no longer face negotiations with European monopoly buyers. However, there may also be reasons to expect that the EU directive on the liberalisation of the gas market will have limited effects a n d / o r the Continental downstream markets will be highly oligopolised. In this case the effect of giving up the GNC may be more serious for Norway. Irrespective of the European-Continental buyer oligopoly, the GNC and the coordination of the Norwegian offshore production system might also be crucial in determining the value of Norwegian gas production. With the Norwegian supply-contract philosophy, as previously explained in Section 5.2, the Norwegian GNC guarantees a flow of gas to the buyer with a basis in the total production system on the Norwegian Shelf and with the Troll field in particular serving as a buffer. Presumably the Norwegian producers thereby get a higher price in return for a stable guaranteed gas delivery than from depletion contracts for individual fields. If continental buyers could buy deliveries at individual fields and route these through the Norwegian pipelines by TPA, aggregation of production and thereby stabilisation of deliveries might take place in other parts of Europe for instance in the large Dutch Groningen fields. This would transfer revenue away from the North Sea to, for instance, the Netherlands. With the partial dismantling of important elements of the governmentled strategy of the Norwegian gas-regime, Norwegian companies will have to fall back on their own commercially based strategies, and their profit-sharing will come to rely on their ability to play strategic rather than political games. The continuation of a selective licensing policy and the Petoro engagement may, nevertheless, give sufficient strongholds for pursuit of producer-based strategy should the EU end-user markets for gas remain as protected as they have been under the first year of deregulation.

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Literature Akselsen, O. (2001). 'Norwegian perspectives on energy pricing and taxation', OPEC and the Global Energy Balance seminar, September 28th 2001. Andersen, S.S. (1988) 'British and Norwegian offshore industrial relations: pluralism and neo-corporatism as contexts of strategic adaptation.' Aldershot, Avebury. Andersen, S.S. (1993) The Struggle over North Sea Oil and Gas. Scandinavian University Press. A-tekst, on-line database, http://www.aftenposten.no/atekst/ Den Norske Stats Oljeselskap A.S, 'Statoil Annual Report', 1973-1996. Energy Information Administration, the U.S. Government (www.eia.doe.gov) Haagensen, K. and Rognstad, D. (1986) Vassdragsjus. Kompendium Juridisk Fakultet, University of Oslo. Haagensen, K. and Midttun, A. (1984) Kraftutbygging, Konflikt og Aksjoner. Energi og Samfunn, Universitetsforlaget. Hanisch, T.J. and Nerheim, G. (1992) Norsk Oljehistorie, Vol 1. Leseselskapet, Oslo 1992. Helicopter Services Group, (1996). Annual Report 1996. Helle, H. (1991) Om Styring og Samspill Ved Slag av Gass. Marius, Sjorettsfondet. Johnsen, A. (1990) Statoil-dr. Gjennombrudd og Vekst, 1978-1987. Gyldendal Norsk Folag, Oslo. Johnsen, A. (1988) Statoil-dr. Utfordingen. Gyldendal Norsk Folag, Oslo. Kjell Haagensen, K. (1984) Kraftutbygging og Konflikt. Et Tilbakeblikk. Energi og Samfunn, Universitetsforlaget. Ministry of Finance and Customs, (1986-87). Government Bill, (Ot.prp. nr. 3)."... on taxation of sub-sea petroleum resources etc." Ministry of Finance and Customs, (1991-92). Government Bill, (Ot.prp. nr. 12)."... on taxation of sub-sea petroleum resources etc." Ministry of Industry, (1971). Government Bill no. 63 (St prp nr 63). Ministry of Industry, (1973). Parliamentary Proceedings 11.06.1973. (St tidende 11.6.1973). Ministry of Industry, (1992). Royal Decree of December 8th 1972 'On exploration after and exploitation of offshore petroleum resources'. Norwegian Storting. Ministry of Petroleum and Energy, (1986-87). Government White Paper no. 46, 'On the petroleum activity in the medium long run.' Ministry of Petroleum and Energy, (2002). 'Fact Sheet' Ministry of Petroleum and Energy, (2001). 'Fact Sheet' Ministry of Petroleum and Energy, (1995-1997). 'Fact Sheet' Ministry of Petroleum and Energy, (1999-2000). Government White paper no. 39 (19992000) on the Oil and Gas Industry. Ministry of Petroleum and Energy, (2000-2001). Ownership of Statoil and future management of the SDFI. Government Bill no 36. Ministry of Petroleum and Energy, (2000-2001). Changes in the law of November 29th 1996. no. 72 on the petroleum activity. Government Bill no. 48. Nerheim, G. (1996) Norsk Oljehistorie, Vol 2. Leseselskapet, Oslo. Wood Mackenzie Energy Services, Newsletters On-line, http://www.woodmac.com/ enrgserv/

Appendix A-1. The major concession rounds on the norwegian sector R o u n d 1" T h e first r o u n d s of b l o c k a l l o c a t i o n o n t h e N o r w e g i a n Shelf w e r e t h e m o s t d e b a t e d ones. Before t h e first r o u n d in 1965, t h e r e w e r e

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m a n y and conflicting views on how N o r w a y should manage its potential resources on the Continental Shelf. The most vivid debate evolved around how to best secure Norwegian interests. Anticipations about size and scope of the resources were low and if any findings were expected to be small and in the far south corner of the Norwegian sector. Nevertheless the government adopted an approach that called for cautious development. This meant careful progressing in the question of which areas to be explored and the scope of the development.

Round 2: By the second rounds in 1969 the optimism was ruling the ground as indications of major findings in round one was becoming known. The outcome of the debates at this stage was to implement a strategy of controlled development so as to make sure that big internationals would run them over. Later rounds: By now the rules and regulations for m a n a g e m e n t of the Norwegian continental shelf was in place and also the know-how on Norwegian hands was substantial. In addition Statoil and the Oil Directorate had been established, and thus the governmental control and overview of the situation was complete. This made it possible to increase the tempo of the developments and explorations. The oil prices were fluctuating but the government was afraid of low prices and draining resources so the adopted strategy was to get the m o n e y while its there and also maintain high employment and activity in the supply industry. In these rounds the government sometimes compromised themselves by putting development in front of financial considerations. Another characteristic of the later rounds was that the n u m b e r of blocks out for allotment in each round was substantially lower than in particular the first round but also in the second. Table A-1. Gas pipelines from the Norwegian continental shelf. Pipeline

Company

Ownership

Capacity

50% 15.89% 12.90% 8.62% 5.60% 4.43% 2.36% 0.20%

19 million scm / day

Norpipe -Ekofisk

- 1977 - 440 kms -30"

field - Emden

Statoil AS Phillips Petroleum Fina Agip Elf Petroleum Norway Norsk Hydro TOTAL Saga Petroleum

Continued

Organising National Interests in the Gas~Petroleum Industry Table A-1.

101

Continued.

Pipeline

Company

Frigg Transport - F r i g g field - St. Fergus - 1978 -2*32" - 350 kms Statpipe -Statfjord field - Kdrsto-

32.87% 29.00% 21.42% 16.71%

20 million s c m / d a y

Statoil

58.25%

Dry gas: 53 million s c m / d a y Wet gas: 25 million s c m / d a y

Elf Petroleum N o r w a y

- 1985 - 880 kms

Norsk Hydro Mobil N o r w a y Esso N o r w a y Norwegian Shell Norwegian Conoco TOTAL Saga Petroleum

Zeepipe Sleipner F i e l d Zeebrugge, IIA: K o l l s n e s - Sleipner, IIB: Kollsnes Draupner E. - 1993 / 1997 -I:

Capacity

Norsk Hydro Statoil Elf Petroleum N o r w a y TOTAL

Ekofisk field

- 2 8 " , 36"

Ownership

10% 8% 7% 5% 5% 2.75% 2% 2%

12 billion s c m / y e a r

Statoil Norsk Hydro Norwegian Shell

70% 8% 7%

Esso N o r w a y Elf Petroleum N o r w a y Saga Petroleum Norwegian Conoco TOTAL

6% 3.3% 3% 1.4% 1.3%

Statoil Norsk Hydro Norwegian Shell Esso N o r w a y Elf Petroleum N o r w a y Saga Petroleum Norwegian Conoco TOTAL

70% 8% 7% 6% 3.3% 3% 1.4% 1.3%

13 billion s c m / y e a r

Statoil (SDFI, 65%) Norwegian Conoco Neste Petroleum A / S

76.87% 18.13% 5%

2.2 billion s c m / y e a r

Statoil (SDFI 60%)

69.71%

16 billion s c m / y e a r

Norsk Hydro Saga Petroleum ASA

6.47% 5.18%

Europipe -Draupner

E - Emden

- 1995 -40"

Haltenpipe - H e i d r u n Field Tjeldbergodden - 245 kms - 16"

Norfra - Draupner E Dunkerque - 1998 - 840 kms

Continued

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Table A-1. Continued. Pipeline

Company

-42"

Esso Norway a.s Mobil Norway TOTAL Norway Elf Petroleum Norwegian Agip Norwegian Shell Neste Petroleum Norwegian Conoco

3.88% 3.88% 2.91% 2.14% 1.94% 1.29% 1.29% 1.29%

Statoil (SDFI 60%) Norsk Hydro Saga Petroleum ASA Norwegian Shell Esso Norway a.s Elf Petroleum TOTAL Norway Norwegian Conoco Mobil Norway Neste Petroleum Norwegian Agip

60.01% 4.76% 10.63% 1.18% 7.68% 0.01% 5.91% 2.66% 1.18% 3.66% 2.36%

Europipe II -Kdrsto (N) - Emden (D) -42"

/~sgard Transport -Asgard field- Kdrsto (N) Statoil (SDFI 46.95%) - 730 kms Saga Petroleum ASA Norwegian Agip TOTAL Norway A.S Mobil Norway A/S Neste Petroleum A/S Norsk Hydro a.s

Ownership

60.50% 9% 7.85% 7.65% 7.35% 5% 2.6%

Capacity

18 billion scm / year

Chapter 6 Dilemmas of Duality: Gas Market Reform in the Netherlands MAARTEN J. ARENTSEN AND ROLF W. KUNNEKE

6.1. I n t r o d u c t i o n

The Dutch gas market was induced by voluminous gas findings in the northern part of the country in 1960. After recognising the enormous reach of this gas field, the Netherlands established a nationwide technical infrastructure connecting the whole country to the gas field and erected a centralised gas industry for the depletion, transmission and distribution of gas. Gas became the major energy source domestically to the determined coal and the national coal mining industry in the southern part of the country. Not only a domestic gas market but also an export market was developed. From the middle of the 1960s, the Netherlands exported gas to Germany, Belgium and France and later to Italy and Switzerland, making the Netherlands one of the major gas suppliers in Europe. From the very beginning the Netherlands adopted a public property orientation in national gas policies, combining longterm security of domestic gas consumption with a long-term strategic reserve policy. The property model reflected three underlying principles: 9 centralised coordination of demand and supply; public-private partnership in upstream activities; and 9 commercial exploitation of the national reserves for the benefit of the national economy.

9

These principles, adopted in a White Paper in 1963,1 guided Dutch gas policies for almost 40 years and ended in 1999 when the Dutch 1Nota inzake het aardgas (White paper on natural gas), Dutch Parliament 1961-1962 6767, no. 1.

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government presented a gas law for a liberalised gas market. The law provided rules for third party access (TPA), unbundling of transport and trade and opening of the market. The gas law, the first one in Dutch gas history, was a direct consequence of the EU Gas Directive (98/30/EC) and clearly reflected the duality of the Dutch position as a gas producing and a gas consuming country. The interests associated with both sides of the Dutch position were a major focus in the political debate preceding the enactment of the gas law. The central coordinating position of Gasunie, the Dutch strategic reserve policy and the Dutch export position in Europe were but some of the themes debated in Parliament. Initially, the Dutch government tried to serve both sides of the Dutch interest position as good as possible, but soon it was clear that the centralised Dutch gas market model could not maintain in the emerging liberalising climate in Europe. Now some three years after the enactment of the gas law, the Dutch gas industry has changed significantly, with Gasunie separated in two independent companies, a trade and transmission company. At the end of 2001 even the termination of Gasunie Trade was suggested, but this decision was not effectuated yet at the end of 2002 due to elections and change of political coalition from central left to central right. Domestically, the market share of Gasunie is still strong and significant, but new companies have weakened its market position in the Netherlands. This chapter analyses recent changes in the Dutch gas market and Dutch gas industry. Section 6.2 briefly summarises the highlights of the history of Dutch gas and then continues with the analyses of liberalisation and its impact on the Dutch gas industry and the Dutch gas market. The chapter ends with some final remarks on prospects of the Dutch gas industry. 6.2. 1960-1990: The Building and Consolidation of the National Gas Market 2

Soon after the discovery of the voluminous Groningen gas field the Dutch developed a public-private organisation for the exploitation of the huge gas field. By means of shares and royalties the Dutch state got a strong position in the exploitation of the gas field. Gasunie, a public-private company, developed a central position in the Dutch gas industry. From 1963 Gasunie coordinated the gasification of the

2The analysis of the history of the natural gas in the Netherlands is based on A. Correlj6, 1998.

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country and the building of the nationwide gas pipeline infrastructure. All private households have been connected to the national gas grid within 10 years. The price for gas was based on its market value (i.e., the parity principle) compared to coal- and oil-based alternatives for residential heating, cooking and hot water supply. In addition to the private market, the sales strategy also aimed at developing an industrial market, but only for industries lacking gas alternatives for technical reasons (at that time, chemical industry, metallurgy and ceramic industries) to ascertain relatively high gas prices. The construction of the national pipeline system connecting all Dutch households and industries to the Groningen gas field started in the early 1960s and was completed in 1970. The strategy of overwhelming the country with natural gas turned out to be successful. Almost all households changed to Groningen gas, because of the price advantage over oil- and coal-based alternatives 3 and because of the comfort of natural gas. Industries changed to natural gas for the same reasons, price and comfort, both leading arguments of the gas promotion campaigns of distribution companies during the 1960s. By 1969 about 65% of the Dutch industry had changed to natural gas. Gasunie directly supplied large industrial consumers, whereas gas distribution companies supplied small and medium-sized industry and households. Gas became also available for base-load power generation. During the 1960s, the Dutch electricity industry changed from dominantly coal-based base-load power generation to gas-based generation. By 1969 about 80% of the Dutch electricity was produced in gas-fired power stations. The Groningen gas was also adopted as a major natural resource in some branches of the Dutch chemical industry. In this way Dutch gas stimulated the rise of the national fertiliser industry, which contributed to steep productivity increases in Dutch agriculture. Shortly after the launch of the domestic gasification programme in the early 1960s, export of gas was considered. In 1964 in the first supply contract of 10mcm to a nearby German gas distribution company was signed. Subsequently, pipelines supplied gas to Belgium and France and later also to Switzerland and Italy. The contracts all were signed for at least 25 years. In the 1960s and 1970s export was additional to long-term security of domestic gas supply. In 1967 export was already on a level of one bcm and in 1974 the overall

3In general the price of natural gas has been settled just below prices of the oil and coal alternatives for all types of consumers over the years.

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export-contracts met the annual domestic consumption volume of about 41 bcm. In the aftermath of the first oil crisis in 1974, Dutch gas policies reinforced the idea of long-term domestic security of supply by discouraging demand (energy saving, price increases, export restrictions) via a long-term reserve strategy. 4 The Dutch government introduced a strategic depletion policy favouring the exploitation of the smaller offshore gas fields. Core to the new strategy was first, a preferred sale of the gas from the smaller offshore fields, and second, encouraging of the exploration and exploitation of smaller gas fields by means of financial incentives. The small-field strategy reduced depletion of the Groningen field, which became the national swing capacity from that time on. 5 Due to this policy change, the exploration and exploitation of the on- and offshore smaller gas fields became more attractive and the resulting increase in exploration and production significantly improved the prospects of the Dutch reserve position and ensured a continous flow of gas revenues to the national Treasury. Figure 6.1 shows the steep increase in gas production after 1974. The caloric value of the offshore gas differed from that of the Groningen gas, and Gasunie developed different devices to cope with these quality differences. First, Gasunie constructed a high-pressure pipeline for the transmission of high caloric natural gas from the smaller offshore gas fields directly to power generation and large industrial consumers. Second, Gasunie invested in special facilities to adjust the different gases to the Groningen caloric standard, either by mixing high and low caloric gases or by adding nitrogen to high caloric gases. Gasunie constructed a nitrogen plant at its Groningen location and also it buys nitrogen from the national blast furnace industry. Nine stations in the national pipeline system mix the different qualities and add the mixed gases to the high-pressure pipeline for Groningen gas. Both the high caloric and the Groningen caloric gas are exported separately requiring construction of two different high-pressure export pipelines. A third measure to cope with the mixed gas substances is to add small quantities of high caloric gas to the Groningen gas field without affecting the Groningen quality of the gas. 6 The exploitation of the Dutch gas reserves was assumed to benefit the Dutch society as much as possible and state participation and

4Second Chamber of Parliament 1974-1975, 13 122, nrs 1-2. 5The costs of using the Groningen field as swing capacity are rather low due its physical conditions. 6See Chapter 2.

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Fig. 6.1. Onshore and offshore production of natural gas in bcm 1960-1998.

Fig. 6.2. Gas revenues 1980-1999. taxation assured a flow of gas revenues to the national Treasury. Figure 6.2 shows the gas revenues between 1980-99, which held track with fluctuations in gas sales. The figure displays an increase of gas revenues to the m a x i m u m of about 25billion Dutch guilders in 1985. The revenues decreased in the second half of the 1980s. During the 1990s the level of revenues more or less stabilised at a much lower level than in the first half of the 1980s. The priority given to domestic long-term security of supply after 1974 resulted in a loss of export contracts in favour of other gas producing countries (Norway, UK and Russia). Consequently, Netherlands gas exports steadily decreased. In 1970 the Dutch exported 11 bcm corresponding to a European market share of 92%. In 1975 this share was reduced to 76% although the volume of the export increased to 50bcm. In 1985 the Dutch share in European gas supply was further reduced to 45% and stabilised around 10% in

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the mid-1990s. 7 The 1989 White Paper on energy 8 therefore, allowed Gasunie to improve its commercial strategy to maintain and to improve its market position in the emerging European market, although within the continued b o u n d a r y of domestic long-term security of supply. 9 Although domestic security of s u p p l y continued as d o m i n a n t principle of the national gas strategy, the 1989 White Paper on energy for the first time pointed to international competition as a potential treat for the national gas industry. A major indication of this treat was the contract of the Dutch power industry (SEP) 1~ and the N o r w e g i a n c o m p a n y Statoil on gas s u p p l y for the Dutch largescale p o w e r generation. This contract was innovative in two regards. Firstly, the contract was agreed u p o n without any interference of Gasunie, a situation that was completely new at that time in the Netherlands. Until then, Gasunie was the only organisation contracting imports to and exports from the Netherlands. The p o w e r generation industry, however, 'exhausted' by the rather unpredictable policies of the Dutch g o v e r n m e n t with respect to fuel diversification in p o w e r generation during the 1970s to early 1980s, directly contracted N o r w e g i a n gas for domestic electricity production. 11 Gasunie, as the national gas coordinator was involved in this contract as gas transmitter only. Secondly, the price of the imported Statoil gas was not based on parity with oil prices, but with the costs of coal-fired electricity production. This coal-based parity of the price of natural gas was n e w in the Netherlands at that time. Until then the coal parity of gas prices was not attractive for gas producing countries, because of the relatively high oil prices. However, these circumstances had changed in the second half of the 1980s. Oil prices sharply decreased and this price-fall extended to coal. Coal became more attractive as parity base for setting the price of natural gas. For that reason, the 1989 White

7The development of export shares is taken from Correlj6, 1998, p. 82. 8White paper on energy policy, (Het energiebeleid nader bezien) Second Chamber of Parliament 1988-1989, 21061, nr. 1-2. 9This policy change followed an import contract Dutch electricity producers signed with Statoil in Norway, the first Dutch gas import contract signed without interference of Gasunie. The contract reinforced the need to calibrate Gasunie's position in European gas supply. I~ was the acronym of the association of Dutch electricity companies. In 1999 SEP was terminated. 11Fuel diversification in electricity production was part of the post oil crisis energy policy in the Netherlands, which was rather inconsistent for several years.

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109

Paper announced the adoption of the coal parity of prices for natural gas, especially for power generation. In fact what happened was that the 1989 White Paper provided for arguments to allow Gasunie for more flexibility in commercial strategies, in order not to endanger its position as national gas coordinator and dominant exporter and importer of natural gas. The adjustments announced in the 1989 White Paper, were basically responding to the new developments in the international environment, especially to face the emerging international competition in European gas supply. In export, the Netherlands were facing increasing competition from Norway and the Soviet Union at that time and the 1989 White Paper accounted for this increased competition on the European market. For that reason, Gasunie was allowed to develop a more flexible commercial strategy and to contract additional exports, next to the ongoing contracts agreed upon in the seventies. These adjustments of course, also protected the continuation of the gas revenues for the national Treasury. The EU energy market harmonisation debate forced the Netherlands to reconsider the prospects of Dutch gas production in the European context. With the prospect of emerging competition the Dutch tried to continue the highly centralised and integrated national gas industry with Gasunie as the central coordinator at the heart of it. In this way the Dutch tried to match the basic principles of the Dutch gas market property model with the demands of the European Gas Directive. However, during the 1990s it became clear that both ambitions had to be balanced. 6.3. The Prelude to Liberalisation

At the beginning of the 1990s the prospects for the Dutch gas industry were rather good. The Dutch reserve position on the short and the longer-term looked promising and gas had developed a strong domestic market position. About half of domestic energy needs were satisfied by natural gas. Dutch pipeline infrastructure was welldeveloped and highly reliable and Gasunie held a strong position as central coordinator. The Third White Paper on Energy published by the social-liberal government in 1995 held new ideas that would affect the harmony of the Dutch as market in the second half of the 1990s and beyond. 12

12Third White Paper on Energy, Second Chamber of Parliament, 1995-1996, 24 525, nrs. 1-2.

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National Reforms in European Gas

The White Paper did not announce any significant changes in the basic principles historically underlying Dutch gas policies, but calibrated these principles in the context of liberalisation. The 1995 White Paper facilitated Gasunie's developing and extending its commercial orientation in the European market. It was expected that the opening of the Dutch gas market by further reducing import restrictions for large industrial consumers should be responded to with increased gas exports of Gasunie. It was also expected that opening the Dutch market would attract Norwegian and British gas on account of Gasunie's present market shares. 13 Gasunie's obligation to forecast demand and supply developments for 25 years in advance was relieved, because foreign gas imports were expected to contribute to the long-term security of gas supply in the Netherlands. 14 Therefore, forecasting concentrated on the Dutch reserve position and strategic depletion instead of specifically on the long-term security of supply position. It was decided to keep the production of natural gas at an annual level of around 80 bcm. This production level would satisfy long-term domestic demand and at the same time would allow additional exports if Gasunie were to lose market share on the domestic market after the introduction of liberalisation. The 1995 White Paper did not announce significant changes regarding the small field policy established in 1974. The favoured depletion of smaller fields in coordination with the swing function of the Groningen field was expected to continue. The strategic depletion policy had been very successful until then and the Dutch government continued this policy to benefit as long as possible from the swing function of the Groningen gas field. However, in addition to this strategic depletion policy, the White Paper also announced increased imports of natural gas to facilitate the necessary long-term adoption of exhaustion of Dutch gas fields. Despite estimates of proven reserves, the Dutch reserve position was not eternal. By steadily increasing gas imports the Dutch economy could gradually adapt to imported gas. Finally, the White Paper confirmed the position of Gasunie in the new context of an open European gas market and suggested the introduction of new types of services Gasunie could offer in a competitive European environment, among others, storage capacity, transmission capacity and flexibility.

13In 1998 and 1999 Gasunie indeed lost market share as was anticipated in the 1995 White Paper. 14The 25-year gas forecast by Gasunie was part of the policy changes of 1974.

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111

The White Paper however, definitely set a course for liberalisation and summarised this trend in two major points: Third party access (TPA) under the authority of an independent regulator and stepwise opening of the gas market.

6.4. Liberalisation of the National Gas Market

In 1999 the Dutch government submitted the gas law holding the new regulatory framework for the liberalised gas market to Dutch Parliament. 15 Three points dominated the political debate surrounding the new gas act, all referring to dilemmas of the Dutch position in the emerging European gas market. The first point concentrated on the model of negotiated TPA in combination with prolonging of the central position of Gasunie. The three parties of the social liberal coalition criticised the suggested negotiated TPA model. Industrial consumers also criticised the new gas law on this point. They feared Gasunie would abuse its central market position despite the unbundling of its transmission and trade activities. 16 Gasunie anticipated the new gas law by opening transmission for third parties already in 1998, with a new set of conditions and tariffs for volume and transport separately (see below). The second point of debate concentrated on continuing the strategic depletion policy pursuing cost-effective exploitation of the small gas fields. Dutch Parliament worried about a possible increase of consumer tariffs to pay for continued small field policies in a liberalised gas market. Parliament did not want this 'stranded investment' to accompany the liberalisation of the Dutch gas market in the long-term. On the other hand, Parliament was advocating continuation of the small field policy, and invited the government to develop costeffective alternatives. The last, but not the least point of debate concentrated on the impact of liberalisation on gas revenues for the Treasury. According to the National Account Office, gas revenues would drastically decrease under liberalisation. In the worst case scenario of low gas prices, Gasunie drastically losing market share domestically and

15The gas law actually submitted was the first national gas market act in the Netherlands. Until 1999 all gas market arrangements were regulated by private law and public-private arrangements between the State and the gas industry. 16The Dutch association of industrial gas consumers (VEMW) was one of the strong opponents of the suggested system of negotiated TPA.

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lacking opportunities to compensate these losses by increased export, could result in a revenue-loss of 2 billion Dutch guilders a year. 17 Despite initial reservations, in August 2000, the Dutch Parliament passed the gas law including some revisions on the three points of discussion. Only the Green Party and the Socialist Party voted against the gas law. The gas law held rules for stepwise and gradual opening of the gas market, providing the first group of industrial consumers (>10mcm) free choice of supplier immediately after the law came into force, followed by the second group (>1 mcm to 10mcm) in 2002 and the rest of the market in 2004. Initially, the full market opening was planned for 2007, but the rapid changes in the electricity market accelerated the schedule for full opening of the gas market to 2004. In comparison to the initial proposals of the Dutch government, the lower level of the consumption range of the second group of eligible customers was increased from 170,000m 3 to 1 million, to continue beneficial gas tariffs for the Dutch horticulture industry until 2004.18 The Dutch scheme for market opening exceeds the opening of 33% in 2008 required by the EU Gas Directive. Gas supply to captives was licensed and subjected to tariff control and approval until 2004. After 2004 the licensing of gas supply to customers using up to 170,000m 3 annually continues but without further tariff-control. The licensing is bound to the obligation of the license holder to buy the gas for licensed supply from Gasunie on the basis of a long-term contract, and Gasunie is obligated to supply gas to the license holder. The Dutch government will determine the duration of this public service obligation. Gasunie as well as the gas distributors were obliged to unbundle transport and sales activities at least administratively. Initially, Gasunie opted for administrative unbundling, but this mode of unbundling soon moved in the direction of financial separation and at the end of 2002 towards legal unbundling. Negotiated TPA for the high-pressure pipelines of Gasunie was suggested as a model in the gas law, but fear of Gasunie's dominant position led to several amendments by Parliament. Negotiated TPA was combined with boundary setting regulation of the gas market

17Second Chamber of Parliament, 1999-2000, no. 26811, Aardgasbaten (Gas revenues), SDU The Hague, 1999. 18The Dutch horticulture industry always benefited favourable gas tariffs, which were threatened by liberalisation. For that reason the Dutch government continued the protected tariffs for this group of consumers until 2004.

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regulator in combination with the competition authority's competence to settle disputes. Furthermore, system operators were obliged to publish tariffs and conditions for transport of gas every year, only after consultation of representatives of the most important gas pipeline users (industry, power producers and the like). Therefore, the Dutch access regime in fact is a hybrid regime combining elements of the negotiated and the regulated access model. The gas act continued the small field depletion policy of 1974, by legally obliging Gasunie to buy all of the gas offered from the small fields on account of the depletion of the Groningen field. 19 To achieve continuous Groningen field swing function for as long as possible, the overall depletion of all national reserves stayed under the control of the state. Gasunie was allowed an annual supply to a maximum of 80 bcm. The state approved the conditions Gasunie offered to the suppliers of the small gas fields. Next to securing long-term supply, obliged intake of gas from the small fields was the second public service obligation that Gasunie was committed to under the new gas law. Another point arranged in the gas act, was privatisation of the gas distribution companies. As for electricity, gas companies were allowed to sell up to 49% of their shares to private companies, but until 2003, only after governmental approval. Privatisation was however, a politically high controversial issue. In 2001 the Dutch Parliament put a hold on the privatisation of Dutch energy companies by its refusal to sell networks to non-governmental owned firms. The parliament accepted additional rules allowing only the sale of the rights of use of the network up to 49% and not the entire property rights. The major argument to restrict privatisation in this way was to protect the network as an instrument of safeguarding security of supply. All energy companies strongly opposed this parliamentary argumentation and decision, stating that this would undermine their ability to develop a strong position in the European market. Without networks the companies would become cheap take-over targets. Finally, the law held some green provisions. Although the new gas law stressed the relative 'cleanness' of natural gas among fossil fuels, the act incorporated some specific 'green' provisions. The first obligated all gas companies supplying more than 10 mcm annually to end-users to develop a programme to stimulate an efficient and an environmentally benign consumption of natural gas by end-users.

19producers however are not obliged to sell the gas from the small field to Gasunie.

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The companies were also obliged to report their efforts in this field every two years to the Minister for Economic Affairs. Second, as for the electricity sector, the new gas act imposed a system of green certificates for the production and supply of 'green' gases. This provision was meant to contribute to the introduction of green gases (biomass) and to the long-term sustainability of the national energy provision. Certificates for green gases were exchangeable with those for green electricity and both types of certificates would develop into a system of green energy provision for the long-term, including all types of green energy provisions. Third, in line with the electricity act, the gas act provided guidelines for decision making on energy infrastructure in new residential areas. These provisions enabled specific judgements on environmental and green standards for the type of energy infrastructure to be constructed in new areas. Under the old regime, the type of energy infrastructure was not questioned and always included gas and electricity provision. Under the new gas and electricity regulation, connecting new residential areas to the national gas grid was no longer given if heat distribution in combination with electricity turned out to be a better alternative from the perspective of 'greenness'. So here too, the new act anticipated 'greenness' of gas supply. These are the core elements of the gas law as enacted by Dutch Parliament in August 2000, just before the formal deadline of August 10 set by the EU Gas Directive. The law ended four decades of central coordination of the Dutch gas market. The EU-requirements of the Gas Directive forced a compromise between the guiding principles of Dutch gas policies with the liberalisation of the national gas market. It soon became clear that the three principles did not match the idea of an open and competition based gas market. The new gas law forced Gasunie to dismantle its central coordinating role in the Dutch gas market, because of the required separation of transport and sales. Gasunie was obliged to continue its central role in gas sales, but within the restrictions set by national reserve policies. The gas law also obliged Gasunie to continue the preference intake of gas from the small gas fields and to balance its gas sales with the Groningen field. The national reserve policy set restrictions on Gasunie's maximum annual sales. During the gas act debate it had become clear that Gasunie lost market share for the segment of large (industrial) consumers, a not very surprising trend subsequent to the opening of a monopoly market. Gasunie was not the only shortterm loser of liberalisation, but also the Dutch Treasury. Gas revenues decreased because Gasunie was not able to compensate domestic loss of market share by increased exports as had been expected by

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the Dutch government during parliamentary debate. In short, it soon became clear that liberalisation as well as the newly enacted gas law induced significant changes in the centralised Dutch gas market.

6.5. Change in the National Gas Market 6.5.1. Gasunie's national and international trade and sales position

During the first half of the 1990s, Gasunie (as well as the Dutch government) held resigned positions vis-a-vis the emerging changes of the European gas market. The UK planned connection to continental Europe opted for Belgium instead of the Netherlands as the continental landing point for the British gas. Gasunie concentrated on establishing new export contracts that were allowed by the government in the 1989 White Paper. Domestically, Gasunie controlled the market and dominated supply and demand of gas, fully backed by the official Dutch gas policy at that time. In Europe Gasunie relied on its reputation of reliable and experienced gas supplier with relatively short transport lines to neighbouring countries and intersecting of transmission lines from north to central and south European countries. At the beginning of the 1990s there were indeed no signs of trends affecting the strong position of Gasunie in the Dutch and the European markets. By the end of the 1990s, with the prospect of liberalisation, circumstances had changed. Gasunie's domestic sales position was still strong, but not inviolable. As Fig. 6.3 indicates, Gasunie lost market share in the final years of the 1990s. According to Gasunie, this was an unsurprising result of opening up a monopoly market. The final year of the monopoly market, 1999, and the first year of the liberalised market, 2000, are illustrative. Compared with 1999,

Fig. 6.3. Gasunie sales 1991-2000.

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Gasunie lost about 10% in sales volume on the home market 2~ and export increased about 4% in 2000 as c o m p a r e d with 1999. In 2000, increase in export resulted from increased sales to Italy. By the end of 2000 Gasunie had also signed a new export contract with Distrigas and u p g r a d e d an existing contract with the UK. In the 2000 annual report it is noted that Gasunie sees further potential in sales to the British gas market. The Central and Eastern European gas markets, the second region that Gasunie had targeted for expansion, lagged behind, 'for a variety of reasons'. 21 One reason for the hesitance of these regions to contract gas from Gasunie was that Gasunie developed export plans for the Central and Eastern European region on the base of swap deliverance of Russian gas from Gazprom. Gasunie was in the race for contracting gas export to Poland, but lost the competition to the Danish c o m p a n y DONG. The Polish a r g u m e n t for choosing the DONG instead of the Gasunie contract was that the latter implied physical gas delivery from Russia based on a s w a p contract between Gasunie and Gazprom, whereas the Polish w a n t e d to decrease dependence form Russian gas. 22 To facilitate this kind of swap-based gas supplies, Gasunie signed a contract with the G a z p r o m subsidiary Gazexport in 1999 holding 80bcm gas, a contract that was renewed in September 2000. Another idea to strengthen Gasunie's European trade position was the planned construction of a second interconnector between Great Britain and the Netherlands. These vague plans to establish a kind of Dutch gas hub however were terminated because a second interconnector was deemed unfeasible. 23 In 2002 the prospects of a direct Dutch-British interconnector i m p r o v e d significantly because of a big deal between Gasunie and the British c o m p a n y Centrica. On June 25 2002 both companies signed a long-term contract for gas export to the United Kingdom of 80 bcm in ten years. At the time the contract was signed the feasibility of a direct new gas pipeline was still u n d e r review but considered as a serious option. The contract m a d e the United K i n g d o m the most important export market of Gasunie

2~ drop in volume sales is not caused by differences in temperature. Gasunie figures in this section are taken from the annual reports over the last 10 years. 21Gasunie Annual Report 2000, p. 12. 22Utilities Vol. 3, No 7-8, 2001, Gaskatern, p. I. 23One of the reasons for the unfeasibility of a second interconnector is that the interconnector between Bacton and Zeebrugge is still operating under its annual maximum capacity of 20 bcm. For the next five to eight years only 11bcm is contracted for the interconnector.

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Gasunie's domestic gas sales in 2000 and 2001.

Sector Industry Small consumers Large consumers Greenhouse horticulture Power stations

2000 Volume in bcm

2000 share total domestic sales

2001 Volume in bcm

2001 Share in total domestic sales

10.0 14.2 4.4 4.0 3.8

28% 39% 12% 11% 10%

9.7 15.7 4.2 4.0 4.9

25% 41% 10% 10% 13%

and will bring the annual volume of exported gas to a level of almost 50 b c m . 24

On the Dutch national market Gasunie lost some 10% market share in 2000, a drop in sales basically caused by switch in the large industrial segment and in the power sector. Table 6.1 gives an overview of domestic gas sales of Gasunie in 2000. In the large industrial and power station segment of the market, Gasunie lost 12% market share. As the annual report of 2000 indicates, 'Competing suppliers' gas sales, for which Gasunie provided the transport and other services, recorded commensurate growth' (p. 10). By 1998, two Dutch energy companies, Essent and Delta, initiated the construction of their own gas pipeline between Zelzate and the Belgian Dutch border to the region of Zeeuws Vlaanderen and Bergen op Zoom, for gas supply to large industries in both regions. In parallel with the Zebra pipeline of both energy companies, Gasunie constructed its own pipeline along the same track. Essent and Delta supply British gas to large industrial consumers, competing Gasunie's gas sales in the region. In 2001 Gasunie's domestic supply increased by 2 bcm compared with 2000. More importantly, for the first time in the history of Dutch gas, the annual volume exported exceeded the annual volume for domestic consumption in 2001. In 2001, the total supply was 80.7bcm, of which 42.2 bcm was exported and 38.5 bcm was supplied domestically. Financially, the drop in sales volume was compensated by an increase of the oil prices in 2000. As Fig. 6.4 indicates, gas prices increased steeply due to the oil price increase in 2000. Despite loss of sales volume, Gasunie, therefore, managed to increase sales in terms of finance. 25 In addition to gas sales, Gasunie also offers transport and

24Information taken from www.gasunie.nl 25Gasunie is allowed to have an annual fixed profit of 80 million Dutch guilders and therefore, the larger part of the money flow of Gasunie is redirected to the gas producers.

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Fig. 6.4. Gasunie sales in billion Dutch guilders 1990-2000. services independently from gas volume supply. The new gas law forces the unbundling of the sales and transport activities of Gasunie. For that reason, Gasunie split in two company units, Gasunie for gas purchase and sales and Gasunie Transport and Services for transport services both separated by the 'Chinese walls' as required by the gas law. The first year Gasunie operated in this new organisational environment was 2000. In 2001, Gasunie's turnover increased to 27billion Dutch guilders.

6.5.2. Gasunie Transport and Services After the introduction of the gas law in August 2000 Gasunie Transport and Services (Gasunie-TS) became the system operator of Gasunie's high-pressure gas pipelines. The gas law required third party access on the basis of a system of negotiated TPA, based on indicative conditions and tariffs for gas transport and services. Gasunie-TS offered transport and service facilities by its Commodity Services System (abbreviated in Dutch as CDS), a system first introduced in 1998. The gas law forced Gasunie-TS to publish indicative terms and tariffs for transport services as threshold for the negotiations in 2001. However, Gasunie-TS got involved in a strong debate with the Dutch gas market regulator Dte, about the 2001 tariffs, because Dte itself published provisional gas transmission and storage guidelines for 2001, which were more convenient for third parties as the conditions and tariffs of Gasunie-TS. Gasunie as well as the system operators of the medium and low-pressure gas pipelines strongly protested the provisional guidelines of Dte. According to the system operators, the Dte guidelines regulated TPA in a manner

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that left no room for negotiation. Dte and Gasunie came to an agreement for the year 2001 committing Gasunie to reduce its transmission tariffs by 6.5% and committing Dte not to intervene in the transport negotiations between Gasunie and third parties during 2001. This agreement was strongly protested by industry groups who argued that the agreement increased their costs of gas purchases by several hundred millions of Euro. 26 Not only the Dutch regulator criticised the tariff system of Gasunie-TS, CDS, but, even more strongly, the system was criticised by large industrial gas consumers and shippers buying only transport capacity and services of Gasunie-TS. CDS initially was a distancedependent and load-based system, with an hourly balance requirement. Industry criticised the transmission system in particular on four points: 1. CDS differentiated tariffs for Gasunie customers and third parties. Third parties only buying transport were charged separately for quality and back-up services, whereas these services were included in the commodity price in case of Gasunie gas sales. According to critics this was not in line with the legal requirement of transparency of tariffs. 2. CDS charged on the base of distance measured from five entry points in the country all located near large industrial conglomerates. This benefited Gasunie's gas sale because customers located in these industrial areas were only minimally charged for transport costs when they bought gas volume from Gasunie. 3. The cost of extra storage capacity was rather high, due to price calculations based on one storage facility at large distance of the important load centres. 4. The hourly input-output balance was demanding, with high penalties charged in the event of imbalance. Shippers were not allowed to make mutual capacity arrangements, because GasunieTS did not allow system-usage on an hourly basis. Since the introduction of CDS in 1998, Gasunie made several adjustments. According to Gasunie's 2000 Annual Report: 'The minimum term of transmission contracts has been reduced to one month (previously one year), capacity can be reserved for one year without incurring an additional surcharge and there is greater

26Utilities, Vol. 3, No. 6, 2001, Gaskatern p. II.

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freedom to vary capacity' (p. 8). According to Gasunie, these kinds of i m p r o v e m e n t s facilitate gas market competition. In general, Gasunie rejected all criticism of its tariff system for gas transport, referring to its comparative analysis of transportation tariffs in Europe, concluding: 'We have found in general that Gasunie's transport charges are the lowest or tend to be among the lowest of all gas transporters in Western Europe. For some cases in Italy, G e r m a n y and the UK, Gasunie's charges are higher'. 27 An EU review of changes and openness of EU gas markets during the first year of liberalisation concluded that third party access to Gasunie's pipeline system is rather good compared to other countries in Europe. Gasunie had already offered third parties access to its pipeline system in 1999 and in 2000 Gasunie's third party transport was 9.4 bcm and by 2000 this volume increased to 12.1. The overall EU evaluation of third party access of Gasunie's pipelines 'was rather favourable' the second best classification in the EU evaluation scheme. Of all European countries only the UK third party access to pipelines was ranked 'favourable but not perfect'. 28 A second clash between Gasunie-TS and the regulator a d d r e s s e d the storage capacity of the N A M and Gasunie. According to the regulator the three Dutch gas storage facilities all have an economic function and therefore should be opened to third parties. Gasunie maintains the position that the three facilities are not storage facilities, but production facilities and therefore not open to third parties. In A u g u s t 2001 the case was not closed yet. 29

6.5.3. Dismantling of Gasunie? Initially, Gasunie only u n b u n d l e d accounts. In 2002 the c o m p a n y split into two separate organisational and financial entities, i.e., Gasunie Trade & Supply and Gasunie Transport & Services, each located in

27NV Nederlandse Gasunie/PA Consulting Group, Gas Carriage and Third Party Transmission Tariffs in Europe, May 2001, p. 6. 28DRI-WEFA, Report for the European Commission Directorate General for Trade and Energy to determine changes after opening of the gas market in August 2000, Volume 2 Country reports, Brussels, 2001. 29Gasunie published a special note on the storage issue arguing the production function of the three storage facilities. Gasunie argues that its legally based public service obligation on the security of supply in all circumstances strongly depends on the gas produced by the three storage facilities and therefore the three do not hold an economic function which should be open for third parties. See position paper 'Ondergrondse bergingen NAM en Gasunie, April 2001.

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separate buildings. However, the discussion about a further, legal, separation of both parts of Gasunie continued and in April 2002 the state, Shell and Exxon, the shareholders of Gasunie agreed upon the termination of the holding Gasunie and its business units for transmission and trade. Gasunie Trade and Services would become the completely state-owned system operator and owner of the highpressure pipeline system in the Netherlands. Gasunie Trade and Supply would be dismantled and integrated into Shell and Exxon. Gasunie's public service obligation on preferential gas intake from the small Dutch gas fields was transferred to the concession-holder of the Groningen gas field, the holding Groningen, with NAM and the Dutch State as shareholders. In this way the commercial interests of the private companies involved in Gasunie no longer would interfere with the interests of good access conditions and the strategic reserve policy. Gas transport would become a state-owned activity of a completely independent system operator. Bringing the agreement between the three Gasunie shareholders into effect was blocked by political turmoil in 2002. The May national elections let to a change of coalition. Rather soon after its inauguration the new coalition already lost parliamentary support and had to resign. At the end of 2002 the dismantling of Gasunie as announced in a letter of the Minister for economic Affairs of April 2002, was not effectuated yet and waits for the new government that will take over after the national election in January 2003. The dismantling of Gasunie and all the other arrangements between the State, Shell and Exxon have been subject of debate in 2002. One of the crucial issues brought into discussion was who would be in control of the Dutch gas reserves, in particular the huge Groningen gas field. To date Gasunie's control has been and still is predominantly a function of swing and flexibility in gas supply additional to the gas supply from the small Dutch gas fields. Continuation of the control of the Groningen field by the state-owned independent system operator, therefore, would have been a logical decision. However, the agreement between the state, Shell and Exxon on Gasunie's dismantling was rather foggy on this point, g~ So at the end of 2002 Gasunie's status was still unclear, but the debate on the issue showed that a further dismantling of Gasunie probably is a matter of time. The overall impact of such a decision is far from clear yet as the debate on the control of the Groningen gas field showed.

3~

for instance, Energie Beurs, Vol. 6, Nr. 9, 2002.

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National Reforms in European Gas

6.5'4. Changes in industrial organisation of distribution and supply Until the 1990s Dutch gas distributors were relatively large in number, but rather small in business scale. Natural gas was distributed either by gas companies or by integrated gas/electricity companies. The major task of gas distribution was to supply natural gas to endconsumer, these being medium and small industrial consumers and private (household) consumers. Gas distribution was utility oriented and enjoyed local monopoly supply. Companies' turnover and profits were somewhat fixed and gas distribution concentrated on technical aspects of the gas distribution system and on the reliability of gas supply. These relaxed market conditions changed in the 1990s, due to concentration and integration, process initiated by the 1989 electricity law in the Netherlands. The 1989 electricity law forced vertically integrated electricity companies to separate production and distribution of electricity. This obligation initiated a process of horizontal integration both at the production and distribution levels. Power production merged into four regionally based power producers, and distribution started merging, drastically reducing the number of distribution companies in the 1990s. 31 See Fig. 6.5. By 1998, the number of distribution companies had reduced to 26, of which only 10 were distributing natural gas. Dutch gas and electricity distribution was concentrated into five relatively large distribution companies, leaving the other companies far behind in electricity and gas sales. Despite the mergers, the scale of the mono gas companies stayed relatively small. Only one mono-gas company exceeded the range of one bcm annual gas sale (see Table 6.2). The scale and reach of all the other companies was far more restricted. During the 1990s mono gas companies tried to protect their market position by establishing an independent organisation, ENERcom, to advocate the gas companies' interests and to purchase gas on behalf of its members. The creation of ENERcom also reflected the increasing diversity of interest between electricity and gas in the Dutch energy market. With the help of Gasunie the mono gas companies tried to respond to increased competition from electricity by developing and marketing new, gas-based, equipment and technology as an alternative to electricity-driven equipment. In this way they pushed the gas-fired heat p u m p and micro CHP as stand alone technologies for heat supply. 31The merger process has been analysed in more detail in Arentsen, Fabius and Kiinneke, 2001.

Gas Market Reform in the Netherlands

Fig. 6.5. Number of energy Netherlands in 1950-1998.

Table 6.2. in 1998.

distribution

companies

(gas and

123

electricity) in the

N u m b e r and size of mono gas distribution companies in the Netherlands

Name

Gamog Obragas GCN GGR-gas Intergas Amstelland Haarlemmermeer GZO NO-Friesland Westergo GMK

(106)M 3 Gas (sales)

Number of gas connections

Employees (total)

1168 757 622 544 501 421 247 207 184 178 126

329530 178063 183593 101902 133314 61287 43594 56859 54352 59063 48467

403 172 200 163 138 167 81 85 94 80 70

However, in 1998 and 1999 the merger process in Dutch energy distribution continued, further concentrating Dutch gas and electricity distribution. At the end of 1999 the market had consolidated in two large energy companies, one of them (NUON) holding Gamog the largest mono gas company. Gamog decided to merge with one of the two large energy companies in the Netherlands at the end of 1999. Although mono gas companies enjoyed protection of gas supply until 2004, their prospect as independent companies was quite uncertain. Mono gas companies saw little potential in competing with large

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integrated energy companies in the Netherlands, leaving them only with the merger alternative.

6.5.5. Gas consumption and gas price developments At the end of the 1990s, natural gas covered about half of the energy need in the Netherlands. As previously indicated, major consumer segments in the Netherlands are industry, electricity production, horticulture and households. The average gas consumption of households significantly decreased between 1980 and 1999 by about 37%, from 3.145m 3 to 1.980m 3 annually, due to reduced gas consumption for residential heating. The reduction followed the wide and large-scale introduction of high conversion equipment for residential heating and the introduction of extensive insulation programmes in the Netherlands. House insulation was one of the core elements of the energy saving programmes of the late 1970s and 1980s. During the 1990s insulation became a standard practice in house construction. New dwellings now must meet legally required energy performance standards, which imply strict wall, floor, window and roof insulation. More recently, energy performance standards for individual houses have been extended to the city-areas level. 32 Combined with improved heating systems, these measures reduced the average gas consumption of individual households significantly over the years. For two reasons, residential gas consumption is expected to decrease further in the next years. First, gas prices are expected to increase more steeply because of energy taxation (see below), and second because a gas provision in new residential areas is no longer a given fact. Contrary to electricity, connection to the gas network is not obligatory in the Netherlands. For that reason, gas for residential heating is facing increased competition from district heating systems, especially in new residential areas presently under construction. This kind of competition is supported by the new electricity and gas laws, obliging energy companies to ensure efficient energy consumption and providing municipal authorities with the ultimate power to determine the kind of energy infrastructure for new residential areas. Under these circumstances, gas supply is no longer obvious in new urban areas. Dutch greenhouse horticulture is another important consumption segment of the Dutch gas market. Thus far, Dutch horticulture 32The extension of the performance standard to the area-level implies other measures, next to insulation, and efficient energy equipment.

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benefited from special gas tariffs, but liberalisation will terminate these. The special tariff system for horticulture enabled a significant growth in the Dutch vegetable and flower industries in the western part of the country. The horticulture sector successfully lobbied to delay their eligibility under the new gas law, but the first group of big horticulture gas consumers became ineligible in 2002 and the rest of the sector will follow in 2004. The CDS tariffsystem of Gasunie-TS is disadvantageous for horticulture due to their low load factor (concentrated and irregular gas intake) causing relative high transmission charges. Horticulture sector anticipates its new position in the liberalised gas market in two ways. First, the sector is considering the construction of a new pipeline connection between the Zeebrugge gas hub and the horticulture area in the Netherlands, which they expect to stimulate for competition. Second, the horticulture sector joined AgroEnergy, the newly created organisation for contracting gas and electricity for the whole Dutch agricultural sector. AgroEnergy has ambitions to contract natural gas for the horticulture sector and to pool gas intake within the sector. By joining forces and by pooling the gas consumption, the sector hopes to reduce the cost increases of the liberalised gas market. 33 Large Dutch industrial consumers use natural gas as feedstock (fertiliser), as an energy source (aluminium), and in the electricity industry for power generation. Gas consumption in power generation increased during the 1990s due to an increase in CHP-investments. CHP generation capacity increased market share in power production to about 22% in 1997 (7000MWe). In terms of installed capacity, the Netherlands now holds the second position for CHP in Europe. Giant industrial consumers (>10mcm) already benefit from freedom of gas supplier choice and from 1998 on they increasingly started shopping among national and international gas suppliers. However, the prospects for a further increase of CHP under liberalisation are not that promising (ECN, Energy Market Trends 2000). Dutch gas prices slightly increased in all market segments at the end of the 1990s. See Fig. 6.6. After 2000 gas prices further increased due to energy taxation. In particular tariffs for private consumers have met strong tax increases in 2001 and 2002. The general expectation is that gas prices for households will increase further due to intensified energy taxation.

33Utilities Vol. 3, No. 6, 2001, pp. 12-15.

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National Reforms in European Gas

Fig. 6.6. Averagegas price (cents/m3) exclusive tax and VAT 1992-2000.

6.6. Conclusions and Prospects This chapter analysed the major developments of the Dutch gas market and the Dutch gas industry. After the discovery of the huge Groningen onshore gas field, the Dutch energy balance steadily shifted to natural gas away from the national coal mining industry, which was bound to disappear in a relatively short period of time. In just ten years a nationwide technical infrastructure was established transmitting and distributing the natural resource to almost every Dutch household, using the gas for residential heating, cooking and hot water supply. Natural gas became the dominant energy resource for power generation and a rewarding natural resource for branches of Dutch industry. Among others, Dutch gas reserves in combination with extensive innovation needs in Dutch agriculture were highly supportive of the fertiliser and Dutch horticulture industries. The Netherlands clearly developed as a nation of gas, both in terms of production and in terms of consumption. The mixed national focus on production and consumption of natural gas was institutionalised in a centralised public-private partnership model with Gasunie in a central coordinating position. Gasunie controlled production, high-pressure transmission, supply, export and consumption of Dutch gas for more than four decades. Public-owned gas companies took the gas from Gasunie on the basis of long-term supply contracts and distributed the natural gas downstream to industrial and private consumers. In this way the Dutch managed to combine the production, export and domestic consumption of natural gas in an effective and financially profitable way. For a long period, this dual position of producer and consumer was not problematic and the Dutch tried to maintain this duality under liberalisation as much as possible.

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However, preserving of the Dutch centralised gas model under liberalisation turned out to be difficult. From the perspective of effective depletion of Dutch gas fields and the Dutch export position, prolongation of Gasunie's centralised position was highly desirable. From the consumers' perspective, prolongation of Gasunie's central position was highly questionable and contradicted to the concept of liberalisation and competition. Several attempts have been made to cope with this duality trying to continue centrally controlled depletion of Dutch gas fields on the one hand, and the introduction of competition on the other. Under the Gas Act of 1999 Gasunie was obliged to continue the small gas field policy, combining the preferential intake of gas from small gas fields with the swing capacity of the Groningen gas field. The law did not specify depletion objectives other than in terms of maximum annual ceiling and Gasunie was no longer restricted in sales strategy. Except for a clearly defined obligation to continue supply to Dutch gas companies, and to serve gas consumption of captive customers, Gasunie was free to develop a trade strategy in context of the emerging European gas market. In 2001 Gasunie's sales strategy, indeed focussed more on the export market, in particular the Eastern European market. In this part of Europe, Gasunie tried to develop market share in cooperation with Gazprom. A step initiated by the opening of the Dutch gas market in 2000, putting pressure on Gasunie's position in the national market. The new law facilitated competition by introducing third party access of transmission and distribution pipelines, and by financially unbundling transmission/transport and trade activities. Initially, Gasunie met the unbundling requirement by means of 'Chinese walls' but during the first of January 2002, Gasunie split into two financially independent organisations: Gasunie Trade & Supply and Gasunie Transport & Services. A system of regulated TPA for distribution pipelines and a system of negotiated TPA of the high-pressure transmission pipelines accommodated third party access to the Dutch pipeline system. The Dutch gas market steadily opened, heading for full market opening in 2004. It showed that after the initial legal steps, the Dutch gas market indeed became more accessible to newcomers during 2000 and 2001, thus putting pressure on Gasunie's market share, in particular in 2000. Gasunie however did recover and managed to increase its trade volume in 2001 by about 7bcm compared with 2000. However, the Dutch market share for third party shipped gas is still growing, which has forced Gasunie to separate more clearly its trade and transmission activities.

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National Reforms in European Gas

As in other countries the introduction of the new access rules was accompanied by protest and legal disputes of all parties involved. Despite these adjustment problems the opening of the Dutch gas market is proceeding on schedule and will be completed in 2004. The full opening of the Dutch market definitely will change the position of the Dutch gas industry and the Dutch gas market in Europe. Dutch prospects to develop an attractive consumer market on the European level playing field seem better than the Dutch prospects to develop a strong supply position in the European market. The signals of increasing attractiveness as a consumer market are threefold. First, the matured Dutch technical gas pipeline infrastructure makes the Dutch gas market an attractive consumer market. Dutch industry, Dutch electricity production and Dutch households are gas minded and all connected to a dense, reliable and wellfunctioning gas infrastructure. Compared with other European countries the current state of openness of the pipeline system is already good and will further improve in the near future due to a rather tough Dutch gas market regulator in combination with consumer pressure. Several new traders are already operating in the Dutch gas market and their number is expected to increase after full opening of the market in 2004. Second, foreign companies are showing interest in the take over of Dutch gas companies. The German RWE Gas took over a Dutch gas distributing company NBH (Nutsbedrijf Haarlemmermeer) even before the formal passing of the new Dutch gas law. Infiltrating the gas market by take-over of gas distribution companies is however complicated by political decisions on the issue of privatisation. Dutch gas (and electricity) companies are not allowed to sell the actual property of their networks. They are only allowed to sell 49% of the economic use right of the networks and this makes Dutch companies less attractive for foreign take-over. These political decisions might result in very complex public-private ownership structures of Dutch energy companies in general, and Dutch gas companies in particular. The Dutch gas industry is not amused by these kinds of political decisions, which in their perception frustrate Dutch industry in its ambition to achieve a good position within the European gas market. The political argument for continuation of public ownership of pipelines concerns the security of domestic supply in combination with insufficient confidence in market forces with regards to investment for maintenance of current and new gas infrastructures. Energy companies complain of the political attack on their European market position. In their view they have become cheap targets in the European race for take-overs and are thus powerless actors in the

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European take-over game. Despite all debates, politics blocked privatisation of the Dutch gas industry in the short-term and it is unclear what the future will bring in this regard. Prospects for the Dutch position as both gas producer and gas supplier at the European level falters for several reasons. There is a clear ceiling on the annual Dutch gas production for depletion reasons. An annual production of about 80 bcm would allow effective and efficient depletion of all Dutch gas reserves until 2024. After 2024 the Dutch are expected to have some gas fields, but the depletion of these fields can no longer be matched with the depletion of the Groningen field, which is expected to be empty by 2024. An annual production of 80bcm is however rather small compared to European gas demand and provides no basis for developing a strong position in European gas supply. Even if the share of domestically consumed Dutch gas decreases in favour of exports, Dutch gas production is still too small to develop a strong position in European supply. Dutch gas production is facing increasing resistance with regards to environmental concerns. NAM, the major Dutch gas production company, holds several life-time licenses for exploration and exploitation in the Northern part of the country, among others, the Waddenzee region. The exploitation of the significant gas fields located in this region is politically blocked for reasons of protecting the ecological value of the Waddenzee region. Ecological values increasingly overshadow economic interests of the Dutch gas. For that reason the short and medium-term prospects of improvement of Dutch reserve position are not promising. The general trend is currently more contra than pro gas production. Some environmental groups in the Netherlands have even suggested constructing a largescale wind park on the Dutch part of the continental shelf to replace gas production. The Dutch supply position in Europe has for many years been overshadowed by British, Norwegian and Russian gas, with supply from these regions expected to increase in context of a harmonised internal gas market. Europe is investing in more connections with Russian and Norwegian gas fields and increased supply from these regions would put Dutch gas back into a niche position for the European market. The niche position of Dutch gas in European gas supply is also caused by the typical quality of the Dutch gas (see also Chapter 2 of this book). Matching of the Dutch gas quality with the European standard will increase costs and in conjunction with typical Dutch gas quality, the gas is facing a double handicap in European gas supply.

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National Reforms in European Gas

Therefore, Dutch gas will continue its niche position in the harmonised internal European gas market. Finally, the trading position of the Dutch market at the European level field is not that promising, for at least the short-term. There is no reason to expect radical developments such as a Dutch gas hub. The country missed a golden opportunity to host the continental landing of British gas. In this way, the Netherlands missed developing a strategic position for European gas flows. Belgium instead has benefited and Zeebrugge has already developed an important hub function on the European continent. Zeebrugge is clearly in a strategic position for European gas flows developing a strong trading function in the European gas infrastructure. The North South gas flow in Europe neglects the Netherlands. The Nordic gas fields are connected to continental Europe in Germany, one of the biggest gas consumers in Europe. A Dutch connection with this major European gas infrastructure would be a dead-end initiative. For the eastern side of Europe, markets are connecting to markets east and south of the Netherlands to Russian gas fields. In the south, Europe is connecting to North African gas fields, connecting large gas markets south of the Netherlands. From a geographical point of view the Netherlands indeed is located at the centre of the European gas market, but the country has not succeeded in developing competitive advantages out of its position. At the end of 2002 the prospects of the Dutch position in the European gas market have become a bit clearer again. There are obvious indications of the Dutch ambition to further open up the gas market and to strengthen the conditions for competition. Gas policy as well as market regulation is quite clear in this respect. The once central position of Gasunie has been systematically dismantled and has entered the final stage of decision making regarding its complete dismantling. The establishment of an independent, state-owned, national system operator is a matter of time. In between Gasunie Transport and Services systematically improved the access conditions and lately made a further improvement by introducing a more flexible entry-exit based access system. The Dutch progress in liberalisation is well in line with the EU ambition. But there are still some unsolved issues on the national agenda. A first issue not yet finally decided is the privatisation of the Dutch distribution networks. The debate concentrates on the question whether these networks should or should not be considered as a political instrument to safeguard security of supply. At the same time, Dutch energy companies feel blocked in their business ambitions by these kinds of political considerations. The scale of the Dutch market

Gas M a r k e t Reform in the Netherlands

131

in combination with the already existing degree of market concentration forces at least the two big Dutch energy companies, to focus on Europe for business expansion. However, their negotiating position is politically w e a k e n e d by the restrictions on privatisation. Consequently, on the issue of privatisation public and commercial interests are still unbalanced. The same holds for the second unsolved Dutch issue, i.e., the control of the Groningen gas field. In the prospect of the unfolding competition-based internal gas market the commercial interests of the oil companies and the national interest of strategic depletion policy no longer match as they did for almost forty years. Gasunie always has been the spill in balancing the commercial and the national gas interests at stake. In a competitive gas market the a d d e d value of an organisation like Gasunie in gas trade is no longer obvious. Shell and Exxon both are strong actors in global gas business and continuation of Gasunie's commercial activities have probably no priority. The dilemma involved in the termination of the commercial activities of Gasunie in fact brings back the debate on Dutch gas to the point where it once started in the early 1960s. At that time the debate on w h o controls Dutch gas, could be decided by establishing Gasunie. Now, some 40 years later, the question is u n c h a n g e d but definitely needs a new answer to cope with the dilemma in the emerging commercial gas market.

Literature Algemene Rekenkamer, (1999) Aardgasbaten, Second Chamber of Parliament, 1999-2000, no. 26811, SDU The Hague. Arentsen, M.J.J., Fabius, J.W. and K~inneke, R.W. (2001) Dutch Business Strategies Under Regime Transition, in Atle Midttun, European Energy Industry Business Strategies. Elsevier, Oxford, pp. 151-195. Correlj6, A. (1998) Hollands welvaren. De geschiedenis van een Nederlandse bodemschat. Hilversum. Correlj6, A.F. and Odell, P.R. (2000) Four decades of Groningen production and pricing policies and a view of the future, Energy Policy 28: 19-27. DRI-WEFA (2001) Report for the European Commission Directorate General for Trade and Energy to determine changes after opening of the gas market in August 2000, Volume 2, Country reports, Brussels. EnergieNed (2000) Energy in the Netherlands 1999 and 2000. Arnhem. Ministry of Economic Affairs (1962) White Paper on Natural Gas. Dutch Parliament 1961-1962 6767, no. 1. Ministry of Economic Affairs (1975) White Paper on Energy. Second Chamber of Parliament 1974-1975, 13 122, nrs 1-2. Ministry of Economic Affairs (1989) Het energiebeleid nader bezien. Second Chamber of Parliament 1988-1989, 21061, nrs. 1-2.

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Ministry of Economic Affairs, (1996) Third White Paper on Energy. Second Chamber of Parliament, 1995-1996, 24 525, nrs. 1-2. NV Nederlandse Gasunie/PA Consulting Group, (2001) Gas Carriage and Third Party Transmission Tariffs in Europe, May, p. 6. NV Nederlandse Gasunie (2001) Ondergrondse bergingen NAM en Gasunie, Groningen. NV Nederlandse Gasunie, Annual Reports 1990-2001, Groningen.

Chapter 7 The Russian Gas Sector: Survival of the Planned Economy or Evolution of Market M e c h a n i s m s ? 1 HELLA ENGERER

7.1. Introduction

The 'European gas markets in transition' headline used to apply exclusively to the West European countries in economic studies on this topic. Since the fall of communism, however, Eastern European countries have attracted increasing attention. In these countries, reforms undertaken in the energy sector are closely intertwined with other economic issues, and are one part of the overall economic transition from a planned to a market economy. Therefore, the question for the transition countries is not simply how to transfer familiar, tried and tested principles of a functioning market economy from other parts of the economy to the gas sector, as is possible in Western European countries. Rather, the central issue is how to foster the emergence of markets, competition and private ownership in the whole economy. This is particularly crucial for Russia, where after 10 years of transition, important reform steps still remain to be taken, especially in the gas sector. In contrast to other transition countries, the Russian gas sector is not an ordinary part of the economy, but a major earner of foreign currency and a major taxpayer. Moreover, Gazprom, which dominates the Russian gas industry, is an important player in designing Russian (energy) policy. This fact alone shows that

1I wish to thank the referees and my colleagues for comments. Technical assistance: Wolfgang H/irle and Uta Kreibig.

133

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National Reforms in European Gas

the separation between politics and economics that is assumed to exist in market economies has yet to emerge in Russia. 2 A comprehensive theory of economic transition still does not exist. A flood of articles has been published providing deep insight into the various issues that lie ahead (e.g., liberalisation, privatisation and structural reforms). Among them, only a few studies venture to make a connection between (Russia's) overall economic transition and reforms in the energy or gas sector. Sagers et al. (1995), for instance, emphasise the importance of the Russian energy sector for overall economic reform, thereby criticising the way resource rent from gas production is extracted and distributed. Kryukov and Moe (1996) find the kind of corporatism within the Russian gas industry to be representative of other branches as well. They also stress the gas sector's inefficiency, which affects the whole economy. Locatelli (1999), by assuming an environment characterised by non-monetary relations, has come to the conclusion that Gazprom, like other companies, plays a role as social regulator. Others (e.g., Stern, 1995; Quast and Locatelli, 1997) analyse the Russian gas industry's potential to increase natural gas production and exports, as well as the consequences thereof for Russian foreign currency earnings and West European gas markets. All in all, the studies mentioned above indicate that Russian gas sector reforms have various dimensions, e.g., Gazprom as an example for industrial restructuring, as a social regulator, and as a producer of overall economic wealth. The purpose of this chapter is twofold: first, to provide an overview of the development and structure of the Russian gas sector as well as its role in the Russian economy; and second, to find an answer to the question of whether Russian gas sector restructuring is really oriented towards market-styled reforms. Instead of prescribing a pre-defined 'model' that allows investigation of industrial, social or overall economic issues, it seems appropriate to take a pragmatic and processoriented approach. A pragmatic point of view takes into account the peculiarities of the Russian economic transition overall, as well as gas sector transformation in particular, as has been outlined elsewhere (von Hirschhausen and Engerer, 1998). The Soviet planned economy has left its mark, politicians as well as economic agents do not easily change their behaviour, and Russia's gas sector reforms will obviously not follow the models discussed or introduced in Western Europe.

2This is not to say that a strict separation exists in all West European countries. Here, the degree of separation differs largely, e.g., between Germany and France.

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A thorough analysis of the Russian gas market is still severely hampered by the lack of information. Additionally, in today's Russia, it is not always clear who actually holds the decision-making powers or who the real actors are. Furthermore, energy policy during the 1990s was established by presidential decrees that were often enacted hastily in response to particular energy-related or general economic problems that arose during the transition process. A draft Energy Strategy was finally published in the year 2002, but it remains unclear when it will actually be implemented. Therefore, while it is difficult to predict where the Russian gas industry is heading, it is useful to show where it has come from in order to shed light on current events. This chapter starts with an historical overview of the gas sector in the Soviet planned economy. In Section 7.3, the changes that have taken place in the organisation and regulation of the gas industry during transition are analysed against this historical background. This is followed by a presentation of supporting facts and figures and a discussion of the projects of natural gas production and exporting. Section 7.5 looks at the future of the gas industry. The last section summarises the main findings. 7.2. The Soviet Legacy: An Historical Overview

Until the 1990s, the Russian gas industry was part of the planned economy. Enterprises were state-owned with little or no scope for their own decision-making. Instead, gas production, distribution, and consumption were planned by state authorities, and prices were centrally controlled. Energy exports were regulated by the state's monopoly on foreign trade. Some of these characteristics of organisation, pricing and export regulations seem to have survived in Russia's present-day gas policy. Therefore, it seems useful to start by tracing the development of the Russian gas industry. An autonomous gas sector was first created in 1943, when a special directorate for the gas industry was established, Glavgazprom, whose first task was to construct the pipeline from Saratov to Moscow (Kryukov and Moe, 1996) that was completed in 1946. At the end of the 1950s, Krushchyov attempted to introduce what he called the 'territorial principle'. The management of the gas industry was decentralised and enterprises engaged in gas production were put under the control of regional economic councils. An important reorganisation took place in 1965, when the Ministry of the Gas Industry of the USSR was established, laying the foundation for the hierarchical structure of the whole gas industry. Although the Ministry was initially entrusted with the responsibility

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National Reforms in European Gas

of managing only the transport system and construction, it took over

de facto the management of all the activities of the gas industry, from production to consumption. In the 1970s and early 1980s, the 'industrial associations' were created, changing the direct ministerial subordination of gas enterprises, now termed 'productive associations', into a three-tier organisational structure (ministry, industrial associations and productive associations). The industrial associations were, on the one hand, departments of the Gas Ministry. On the other, they functioned as accounting units. They administered and distributed specialised funds (e.g., for the 'material stimulation' of the workforce) to the productive associations. This vertical structure within the energy industry was a precondition for reaching planned production targets and for implementing energy programmes aimed at fostering the long-term development of the entire industry. The last Soviet Energy Program was formulated in 1982 (parts were published two years later, Ekonomicheskaya gazeta, No. 12/1984, 11-14). At the end of the 1980s it was modified somewhat, mainly extending the time schedule, but not the content. It was expected that oil reserves would be depleted earlier than gas reserves. Furthermore, it was assumed that oil production could be stabilised during the 1980s, a decrease was not expected before the next decade. Meanwhile gas production would be increased, especially by developing the huge gas fields (e.g., Yamburg, Yamal) in the northern territories. The programme intended to gradually replace domestic oil consumption with natural gas consumption, in order to stabilise or even increase petroleum exports. It was also envisaged that overall energy consumption, which in all planned economies was high per capita, should be reduced, but this goal could not be achieved. Instead, cheap energy deliveries to domestic suppliers, including energyintensive industries, continued. As a result, it was necessary that supply-side measures in particular be implemented in the years that followed. 3 Since the mid-1980s, organisational restructuring took place under the catchword 'Perestroika' in the whole economy, among other things, to strengthen the position of the productive associations. The law 'On State Enterprises (and Productive Associations)', which came into force in 1988, provided for 'self-financing' and 'self-management' of enterprises, thus broadening their rights of independent decision-making. 3This is due to the fact that in a centrally planned economic system it was principally easier to increase production than to achieve energy savings by having decentralised customers. To improve energy efficiency, the energy programme also provided for technological innovations that could not be realised.

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In the place of planned targets, 'state orders' were introduced, which state enterprises were obliged to obey. The 100-percent state orders were to be reduced later, thus enabling the enterprises to freely choose their customers. In the energy industry, however, production and trade remained regulated by 100-percent state orders until as late as 1991. Changes in organisation occurred in 1989, w h e n the formerly separate ministries for oil, petroleum processing, and gas were united and the Ministry of the Oil and Gas Industry was established. At the same time, projects were initiated to create a 'concern' in the gas as well as in the oil industry. One of the proponents of a special gas concern ('Gazprom') was Viktor C h e r n o m y r d i n , w h o had been Minister of the old Gas Ministry, but w h o only temporarily held the position of First D e p u t y Minister in the n e w Ministry of Oil and Gas Industry. After G a z p r o m had been in existence just a few weeks, the Ministry lost most of its supervisory functions in the n e w concern (Kryukov and Moe, 1996). Hence, the centralisation of the gas industry was maintained or even increased. The centralised organisation assured that the ambitious gas production targets could be realised. In order to achieve production targets, the energy sector was granted preferential treatment. One example of this were the growing centralised investments in gas exploration and production during the second half of the 1980s, w h e n the overall economic growth rate was on the decline and early signs of economic recession were beginning to appear in other industrial branches. It was mainly the investment increase 4 that m a d e it possible to develop the huge gas fields in the northern territories with their unfavourable climatic conditions. Development and production costs, however, were not a p r e d o m i n a n t factor in financial resource allocation. The efficient exploitation of operating fields was neglected at the expense of a rapid expansion of gas production from new fields. The historical success in gas production (see Table 7.1), which in the Russian Republic peaked at 643 billion m 3 in 1991 (for the whole USSR about 810billion m 3) - just before the dissolution of the Soviet Union - should be evaluated against the backg r o u n d of the still-functioning planning system in the gas industry. 5

4In 1980 about 33% of industrial investment was directed to the energy sector; in 1988 the share was 40%. In the period 1980-1988 absolute volumes also increased. 5With investments channelled into promotion of field discovery and exploitation, other much-needed investments were neglected. Equipment in the energy sector, as in other industrial branches, was and still is to a large extent outdated. Apparent signs of insufficient equipment replacement and technical problems were gas pipeline accidents reported by the mass media. Given the lack of metering, exact figures for the past are not available.

(,o oo

Table 7.1.

Gas balance in b c m 1.

Production Imports Exports of which: C.I.S. others Stock changes Domestic consumption 2

1985

1990

1991

1992

1993

1994

1995

1996

1997

1998

1999

2000

2001

20023

462.0 67.9 -166.5 n.a. 363.4

640.5 70.2 -249.0 140.0 109.0 -5.0 456.7

643.0 69.0 -247.0 164.0 83.0 -2.5 462.5

640.4 7.0 -189.0 101.0 88.0 -1.1 457.3

618.3 6.5 -171.0 75.0 96.0 -10.1 443.7

607.3 1.5 -185.0 75.0 110.0 -10.0 413.8

595.0 3.9 -192.0 70.0 122.0 -13.0 393.9

601.0 4.7 -197.0 70.5 126.5 n.a. 408.7

570.0 2.7 -200.0 80.0 120.0 n.a. 372.7

591.0 3.0 -203.0 78.4 125.0 n.a. 391.0

592.0 4.1 -205.0 74.3 130.7 n.a. 391.1

583.6 n.a -193.8 60.0 133.8 n.a. 389.6

581.2 n.a -181.0 50.0 131.0 n.a. 400.2

593.0 n.a. -187.0 60.0 137.0 n.a. 396.0

1Until 1991 RSFSR. 21985 a n d 1996 - 2002 including u n k n o w n stock changes. 3Estimates. Sources: Goskomstat: Statistical Yearbook of Russian Federation, various issues; Goskomstat: Sotsial'no ekonomicheskoe polozhenie Rossii 2002 god, XII/2002; OECD: E n e r g y Statistics a n d Balances of Non-OECD Countries, various issues.

~,~~

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139

The preferential treatment of the energy sector was partly due to its role as an important earner of foreign currency. At the end of the 1980s, oil and gas exports accounted for half of the currency receipts; at the beginning of the decade this share had amounted to 80%. The fall in energy export earnings during the 1980s was mainly due to the decrease in world market prices. To counterbalance the price decrease, the Soviet Union attempted to increase export volumes to western countries, fuelling the need for growing production and, as a result, forcing investment increases. In contrast to deliveries to western countries, exports and imports within the so-called Council for Mutual Economic Assistance (CMEA), the trade association of the socialist countries, were carried out by a special trade regime. This entailed the Soviet Union delivering energy according to special agreements concerning volume and prices to those Eastern European countries which have only limited energy reserves and which were dependent on energy imports. 6 With the dissolution of the CMEA in 1991, the special trade and payment systems were abolished and Eastern European countries had to pay for their energy imports from Russia in foreign currency. This was one reason for the trade collapse between former CMEA countries at the beginning of the 1990s. Energy deliveries also declined within the Commonwealth of Independent States (CIS), which was established after the dissolution of the Soviet Union in late 1991. Here, national gas concerns were established, partly out of the former industrial associations (Ukrgazprom, Turkmengazprom). Although Russia lost direct control over the gas industry in the other former Soviet Republics at that time, it did keep indirect influence in so far as most of the CIS countries remained dependent on Russian imports. All in all, the peculiarity of Soviet energy trade provides one vivid example of how overall economic objectives (e.g., high currency earnings 7) and political considerations dominated Soviet energy policy. The centralised structure of the energy industries, including the gas sector, served as a means to achieve these goals.

7.3. The Gas Industry in Transition In general, transition from a planned to a market economy means farreaching changes in the economic system. Privatisation, liberalisation 6In intra-CMEA trade, energy prices were set by a sliding five-year average of world market prices. In periods when world market prices fell, the price paid by the CMEA countries was higher than that paid by western countries. 7Another example is energy-related taxes, which were an important source of governmental receipts.

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National Reforms in European Gas

and deregulation are the main measures used to achieve the transformation. In the Russian Federation, transition started in 1992, when prices and markets were liberalised and other reform programmes (e.g., privatisation, deregulation) were developed. In the following years, many enterprises were privatised, mainly by voucher privatisation. In addition, competition was introduced in m a n y sectors of the economy. However, during the 1990s, measures to liberalise, deregulate, and privatise the economy were only partly applied to the gas industry. In 2000 the new government presented its economic reform programme including some remarks on gas industry (see Pravitel'stvo Rossiyskoy Federatsii, 2000, Centre for Strategic Research, 2000). A draft of a new Energy Strategy was elaborated in late 2001 (Ministerstvo Energetiki, 2001). However, these reform measures were only partially implemented. Then, in a u t u m n 2002, a revised version of the Energy Strategy was published (Ministerstvo Energetiki, 2002). In the following, we analyse the development of gas industry during the 1990s, presenting recent reform projects and pointing out the shortcomings thereof.

7.3.1. Ownership and structure of gas industry The Russian gas industry is dominated by Gazprom, which controlled about 88% of natural gas production in 2001 (see Table 7.2). Gazprom inherited all high-pressure pipelines. Furthermore, it is licensed to develop about 70% of the natural gas reserves of the Russian Federation which were estimated at the beginning of 2001 at about 47 trillion cubic metres. 8 Besides its gas sector activities, Gazprom also owns companies in other business fields, e.g., mechanical engineering, food processing, and the hotel industry. The second most important gas producer and trader today is Itera, 9 which was already founded in 1992, but which gained increasing importance up to the end of the decade. 1~ Thus, a description of the ownership of the Russian gas industry during the 1990s is mainly a portrait of Gazprom. 8The Subsoil Law of 1992 establishes that all mineral resources remain in the ownership of the Russian Federation. It also regulates the licensing procedure. 9Some speculations have been made in the past about non-transparent links between Gazprom and Itera. Investigations of Russia's Audit Chamber and PriceWaterhouseCoopers in 2002 could not confirm legal violations in the two companies' relationship, however. 1~ gas is also produced by oil producing associations and the gas producing associations, Yakutgazprom and Norilskgazprom, which operate regional isolated gas systems. Besides these enterprises, some small gas firms exist, most of them only producing up to 1 billion m 3/a.

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Table 7.2. Gazprom: Production and Exports in bcm. Production Export C.I.S. Baltic States Eastern European Countries Others

1998

1999

2000

2001"

553.7 172.9 48.1 4.3 42.02 78.5

545.6 173.9 43.9 3.3 38.3 88.5

523.2 172.4 43.4

512 174 43

129

/

131

*Estimates. Source: www.gazprom.ru.

Gazprom gained its predominant position through its unique process of development during the 1990s. While other branches of the economy were privatised and deregulated, the entire gas industry was assumed to be a strategic sector and to constitute a natural monopoly. Therefore, special regulations concerning privatisation of gas enterprises and introduction of competition in the gas industry were applied which are addressed in the following. In June 1992 Gazprom was transformed into a 'concern of the Russian state' and a decree released in November provided for its transformation into a state-owned joint-stock company, with the Russian state retaining 40% of the shares for the following three years, a period which was later extended. 11 Thus, theoretically, only 60% of the shares could be privatised. In addition to these legal regulations, two decrees were published, asserting the rapid development of the gas system as an important task for the national economy and declaring the gas supply system to be exclusively federal property (Kryukov and Moe, 1996). This attitude towards the privatisation of the gas industry was confirmed by the privatisation programme (Ekonomicheskaya gazeta No. 29/1992, 15ff). A privatisation ban on pipeline transportation was imposed, and energy production associations could only be privatised with the consent of the government of the Russian Federation. By a further decree, the state was given a 'golden share', which provided it with the power of veto in important enterprise decisions. From these legal regulations it became clear that rapid privatisation and deregulation of the gas industry as one of the 'strategic' sectors of the economy was not envisaged.

1lit seems to be no coincidence that these important steps were taken in the second half of 1992. After the resignation of V.M. Lopukhin as Energy Minister in May, the post of minister was vacant and the functions were carried out by Deputy Prime Minister Chernomyrdin.

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National Reforms in European Gas

During the period from 1992 to mid-1994, voucher privatisation was carried out in the Russian Federation (Engerer, 2001). About 100,000 companies in industry and other branches of the economy were transformed into joint-stock companies and their shares partly distributed to the workforce and population. The early years of this privatisation wave, however, passed over the energy industry. Privatisation of energy companies first began in spring of 1994. But it covered only that part of equity which the state had not legally reserved for itself. In 1994, the 60% stake of Gazprom's equity was sold or distributed as follows: 9 workers and management of Gazprom purchased 15% at preferential prices; 9 the population exchanged privatisation vouchers for 33.9% of equity, and a special part was offered to the population of the Yamal-Nenetz region, where the large gas fields are located; 9 1.1% was contributed to the chapter capital of Rosgazifikatsiya; 9 Gazprom itself bought 10%; of this, 9% was planned for sale to foreign investors starting in 1995. The project of selling shares of Gazprom to foreign investors in early 1995 was postponed. Foreigners were first allowed to buy GazpromADR (American Depositary Receipts) in 1996. However, at that time, only a small stake was offered. In the following years, sales to foreigners were delayed again and again. The first important sale occurred in December of 1998, when 2.5% was purchased by the German Ruhrgas AG (DIW/IfW/IWH 1999). This, however, was not the starting signal for a flood of sales to foreigners. The maximum stake for foreigners was limited to 9% until 1998, when it was first slightly increased to 14%. A further increase to 20% was allowed in 1999. At the end of 2000, foreigners owned 10.31%, Russian legal entities 33.64% and Russian individual shareholders 17.68%. The state's share, which was now legally allowed to decrease to a minimum of 35% only slightly diminished to 38.37%. The state, however, only played a passive role in corporate governance. It transferred its votes to Gazprom's management. At the same time foreign owners had little power to influence Gazprom's business activity. Additionally, in the initial years following privatisation, small Russian shareholders had been prevented from exercising their ownership rights; their opportunity to trade shares on the secondary market was regulated. 12 Thus, Gazprom's management maintained a strong position.

12This, by the way, has been one reason why the price performance on the Moscow stock exchange has only insufficiently reflected investors' estimations of Gazprom's business activities.

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During the 1990s measures to foster competition in the gas sector remained half-hearted. The regulation on natural m o n o p o l y (Rossiyskaya gazeta, M a y 7th 1997, 3) emphasised the advantages of an integrated c o m p a n y which w o u l d guarantee secure domestic supply and export earnings. At the same time, however, it declared that the gas sector should be restructured and that competition in the gas industry should be introduced by opening up the market for i n d e p e n d e n t gas companies. These provisions were challenged by the IMF. In the following period, some restructuring of the gas industry actually did take place. Whereas 'Gazexport', a G a z p r o m affiliate, maintained the exclusive right for export to western European countries, third party access (TPA) was officially introduced for interregional transmission and CIS exports. However, it is unclear what conditions i n d e p e n d e n t gas companies had to fulfil in order to actually get access to the pipelines. 13 In addition, G a z p r o m ' s companies were first transformed into w h o l l y - o w n e d limited companies. A special G a z p r o m sale division, 'Mezhregiongaz', was established. According to IEA (2002) Mezhrigiongaz buys gas from production companies and pays the transportation companies for their services. However, the prices paid to production companies are not cost-related and transport prices are below the regulated prices (see below). It is this system of subsidised prices which has ensured G a z p r o m ' s d o m i n a n t position and m a d e it difficult for outsiders to enter the gas market. The so-called unified system of gas s u p p l y and price setting was even confirmed by federal law (Ekonomika i zizn', No. 18/1999), although the IMF had challenged gas sector reforms again in 1998. Since then, i n d e p e n d e n t companies have gained some importance: Itera increased its production from 2 billion m 3 in 1998 to 18 billion m 3 in 2000 and 23 billion m 3 in 2001. Nevertheless, G a z p r o m ' s vertical structure and its major role in the gas market still remain. 14

13According to IEA (2002, 121) transmission tariffs officially amounted to 95/1000 m3/ 100 km for deliveries to domestic customers and 80 cents/1000 m3/100 km for deliveries to CIS customers. In July 2000 a single tariff of 60 cents to 1 $/1000 m3/100 km was introduced. 14Gazprom even has somewhat strengthened its position in low-pressure distribution. The organisation of low-pressure distribution changed during the 1990s. A special organisation (Rosgazifikatsiya) was established in 1989 as a unified gas distribution company. In 1992 the local offices of this organisation became independent and most of them were transferred into joint-stock companies and privatised. Due to problems of non-payment many companies became insolvent. Their number declined to about 378 in 2000 (IEA 2002). Gazprom, however, aquired distribution companies which were indebted to it. By 2000 Gazprom owned about 10% of the distribution network.

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National Reforms in European Gas

Only at the end of 2000 was a draft proposal for gas sector reform elaborated. Gas sector deregulation was now envisaged to be carried out in several stages (OECD 2002). In the first stage (2001-2003), entry of independent producers will be promoted and prices liberalised for them. Gazprom's production companies will be converted into joint stock companies, prices for Gazproms' affiliates will remain regulated. In the second stage (2004-2006), a wholesale market will be established. In the third stage (2007-2013), competition on the domestic market will be created, Gazprom then will concentrate its activities on exports. All in all, the long implementation phase and the still important role of Gazprom in export activities point to a general hesitancy as regards gas sector reform. The OECD (2002, 150f) even feared that Gazprom would, among other things, gain implicit dominance of the market through control of the pipelines and a subtle means of discriminating among producers, and therefore demanded "[...] a much more active role by the state in the affairs of Gazprom and a closer monitoring of the firm's activities." The state, which up to then had only played a passive role as Gazprom's main shareholder, gave initial signs of taking a more active role in June 2001, when an important change of Gazprom's board of directors was initiated. Chief executive R. Vyakhirev was replaced by A. Miller, an ally of President Putin. Other members of the management were also replaced. Soon afterwards the government announced that, among other companies, Gazprom will be restructured and competition in the gas sector fostered. However, further measures (e.g., price deregulation) and a binding timetable to restructure Gazprom and deregulate the gas market still remain to be designed. According to the Energy Strategy (Ministerstvo Energetiki, 2002), a concept on the development of the domestic gas market is to be elaborated only by late 2003.

7.3.2. Price and export regulation In the Eastern European countries, prices were fixed on a special costplus principle. The principle of establishing the fixed prices was changed over time. However, in general, costs included labour costs, material costs and a kind of 'capital costs'. A fixed 'profit' was then added. Demand-side factors were taken into account only insufficiently if at all. In Russia, this pricing policy was abolished in most sectors of the economy in 1992 by price liberalisation. However, the entire energy sector and the gas sector in particular were initially exempted from this. Whereas oil prices were liberalised during the 1990s, gas prices remained fixed by state authority on the basis of the cost-plus principle. Due to high inflation, wholesale and retail prices for natural gas were first increased by absolute amounts. In February 1993, the

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prices for industry were fixed at 3600 Rbl/1000 m 3 and for households at 6 0 0 R b l / 1 0 0 0 m 3. In August 1993, the wholesale price was indexed to m o n t h l y price increases in industry (Rossiyskaya gazeta, July 24th 1993, 5). The retail price has also been increased since then, but remains low in real terms. After the financial crisis of 1998 and devaluation of the rouble, prices for industry were fixed at about $13.7/ 1000m 3 and for households at $ 4 / 1 0 0 0 m 3 (IEA 2002, 127). Prices were increased slightly thereafter. In spring 2002, gas prices increased by 20% to about $ 1 9 / 1 0 0 0 m 3, which was less than initially planned. 15 Price regulation has important negative consequences: First, in contrast to western markets, where gas tariffs for small private customers are higher than those for industry, in Russia households pay less than industrial consumers. As early as February 1998, the Federal Energy Commission, 16 which is responsible for price setting, proposed eliminating the price difference, but nevertheless, household tariffs have remained far below prices for industrial consumers. Second, due to the low price of domestic gas as compared with other fuels, customers have an incentive to switch to gas. Thus, in principle, the share of gas in domestic energy consumption, which is currently more than 50%, can be expected to increase further. Third, domestic gas prices are low compared with international prices. On the one hand, the low price level does not encourage energy savings, and due to the high level of per capita energy consumption, improving energy efficiency should be given priority. On the other hand, as long as gas prices remain low and do not ensure profitability, i n d e p e n d e n t gas companies have little incentive to enter the domestic gas market. In the past there had been no serious attempt at gas price reform. Substantial gas price increases for households have been avoided first and foremost for social reasons. A substantial increase in household prices has been seen as untenable for families living in bad social conditions, however, these groups could have been compensated for 15Gazprom was allowed to increase wholesale domestic prices in rouble terms by another 15% in the second half of 2002. As inflation is expected to reach 12%, real price increases will be small. 16TheFederal EnergyCommission(FEK)was established in 1995(SobranieZakonodatel'stva Rossiyskoy Federatsii, No. 49/1995). Besides its task to set the basic price it has some regulatory authority. FEK is headed by a chairman who is appointed by the President of the Russian Federation. In recent years other members of FEK were representatives from the Ministry of Economy and the price committee as well as representatives from important industrial branches (e.g., electricity and transport). Therefore, it has to be questioned whether the FEK actually performed its task as an independent regulatory supervisor. In 2001 the FEK was reorganised as a unified price regulatory authority responsible for electricity, gas and rail transport prices (DIW 2002, 92).

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price increases by direct transfers. In contrast to households, there had been increases of gas prices for industry during the 1990s. These increases, however, only led to increases in non-payment and barter transactions, which had been a widespread phenomenon in the Russian economy. 17 According to the IEA (2002, 129), at the end of the 1990s only 18.5% of gas payments were made promptly in cash; barter accounted for about 30% and other types of non-payment for about 25%. This had resulted, among other things, in Gazprom's reduced ability to invest (e.g., in field development). The largest single debtor to Gazprom was the Unified Electricity System (UES), which itself was confronted with non-payment of customers. In principle, by tolerating the chain of different kinds of non-payment within the economy, bankruptcies of firms in bad conditions and increasing unemployment were avoided and the former policy of cheap energy supply was continued. This became visible when, in the summer of 1998, Gazprom threatened to reduce deliveries to the power sector, and the g o v e r n m e n t - as an owner of G a z p r o m - forced the company to maintain a cheap gas supply. 18 The situation changed completely in 2000/2001, when Gazprom firmly declared that it would reduce its gas deliveries to UES. In turn, UES threatened those debtors who were not paying promptly and in cash with disconnection. As a result, cash payment in the electricity sector increased. This also included payment for gas deliveries. Governmental organisations, which until then had failed to pay their bills promptly and in cash, also improved their payment behaviour. All in all, the problem of non-payment diminished drastically. 19 The underlying problems with gas price reform, however, have still not been solved. For example, it is still unclear whether enterprises that stand to suffer from a substantial increase in gas prices will be forced into bankruptcy or kept alive by subsidisation. Further gas price differentiation between industry and households will probably continue. In January 2002, the government decided to postpone shifting the entire burden of housing costs (including gas) to households until 2010. Until then there will be a limit on household expenditures for housing costs, and if costs exceed the limit, direct

17For discussions of non-payment see IEA (2002, 128ff) and OECD (2002, 121ff). 1SAt the same time the government tolerated Gazprom's large tax arrears to the federal budget. Gazprom formally accounts for 25% of federal tax revenues. 19Even in cases of non-payment and regardless of profitability, Gazprom must provide a certain minimal level of gas deliveries to sustain the safe operation of the consumer's equipment (see OECD 2002, 127 and Pravitel'stva Rossiyskoy Federatsii 1998).

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transfers will be paid to vulnerable groups. 2~ Thus, at least for residents, gas tariffs will not drastically increase in the near future. The Energy Strategy (Ministerstvo Energetiki, 2002) also confirms a gradual increase in gas prices. Price increases, however, should take into account macroeconomic development (e.g., inflation). Although gas price reforms are seen as a centrepiece of gas sector reform, the Energy Strategy remains vague with regard to the time horizon and scope of price increases. The low price level on the domestic market gives incentives for the energy industry to sell natural gas abroad. The government is interested, on the one hand, in energy exports that generate high currency earnings. On the other hand, however, it supports the delivery of stable and cheap energy resources to domestic consumers. Thus, the government seeks to establish a balance between domestic supply and exports. As energy trade is easier to regulate than domestic energy consumption, various schemes for export restriction were developed during the 1990s. After the abolition of the state's monopoly in foreign trade, energy exports were first restricted by licenses and quotas. Energy trade with CIS countries was regulated by intergovernmental agreements. In 1994, for instance, intergovernmental agreements with CIS countries covered about 57billionm 3 of natural gas. Gazprom's quota for gas exports to western markets amounted to 117billion m 3, and during that year the quotas for deliveries to western countries were abolished. Customs duties, however, continued to be levied until mid-1996, thereby reducing the profitability of exports, and were only abolished due to pressure from the IMF. Gas export tariffs were temporarily reintroduced in 2000. Besides the regulation of export volumes, restrictions on export earnings were applied. Gas exporting companies are allowed to retain only part of their earnings and have to convert foreign currency at the official exchange rate. A special regulation was imposed on Gazprom's gas export earnings (Kryukov and Moe, 1996): income from exports was valued at domestic prices and the difference between that and the actual receipts had to be contributed to the stabilisation fund, which was not taxed (the tax exemptions, among other things, allowed Gazprom to maintain its internal accounting and refunding practice). The mandatory exchange of 75% of export earnings in foreign currency was reduced in summer 2001 to 50% and thus to the level before the 1998 financial crises (DIW 2002, 92). Export

2~

Bank of Finland, Russian & Baltic Economies. The Week in Review, No. 1/2002.

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taxes on gas sold to Europe, which amounted to 2.5 Euro minimum per 1000m 3 in 1999, have been temporarily increased to 5 Euro minimum per 1000m 3 in 2001 (OECD 2002, 120). Additionally an excise tax on gas exports amounting to 30% is now levied. Regulation of export earnings and export-related taxes remains an important source of revenue for the federal budget. Therefore, liberalisation of gas trade is related to overall economic issues. The Energy Strategy (Ministerstvo Energetiki, 2002) provides for a certain degree of liberalisation of the gas market, assuring all gas producers a fair share of export earnings. At the same time, however, it emphasises that the 'single export channel' should be maintained in order to achieve maximal benefits for the Russian economy. All in all, the new Energy Strategy provides for ambiguous reforms of the Russian gas market. On the one hand, it calls for restructuring Gazprom, liberalisation of the gas market and fostering competition by encouraging independent gas companies and reforming gas prices. On the other hand, however, it emphasis that gas sector reforms (e.g., price increases) are dependent on overall economic development and will be carried out only step by step. 7.4. More Facts and Figures

In the 1990s, many branches of the Russian economy were affected by the so-called transition crisis, whose characteristics were sharp contractions of production, investment and employment. In contrast to other branches, the gas industry has faced a relatively small decline in production. The reason for this is obviously not that the gas sector has been successfully restructured. Rather, the gas industry has benefited from special treatments as it has been assumed to be a strategic sector. Russia is the world's largest producer and exporter of natural gas. In the following, some of these impressive figures are presented. However, providing figures on the Russian economy is not an easy task. Although statistical information has improved in recent years, data often remains dubious and in part contradictory. Figures on the energy sector, in particular, do not always reflect the exact development; but do show rough trends.

7.4.1. Gas reserves, production and consumption Data on energy reserves is one example of figures that should be interpreted with great care. During the Soviet era, energy reserves were treated as a national secret. In addition, the Russian definitions of

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Table 7.3. Projections on gas balance (bcm). 2010 projection

Production Imports Exports of which: C.I.S. Others Stock changes Domestic consumption

2020 projection

I

II

I

II

615 34 -204 50 154 -6 439

655 34 -230 50 180 -6 453

660 45 -225 50 175 -9 471

700 45 -244 50 194 -9 492

Source: Ministerstvo Energetiki RossiyskyFederatsii (MinEnergo) (2002).

various reserves differed from western standards. Today, western companies have begun to audit Russian gas reserves applying international standards. 21 The gas reserves examined have thus been reduced somewhat, to 47 tcm. 22 Most of the reserves, however, are concentrated in the huge fields of the northern territories, e.g., Urengoy and Yamburg, which already account for 73% of Gazprom's production (Gazprom 1999). It is difficult to predict when these fields will be exhausted. According to western (pessimistic) estimations, however, the easily extracted reserves will be depleted within the next 10-15 years. The first draft of the Energy Strategy forecast the production at existing fields to be about 142 billion m 3 in 2020. In order to meet the projected production level of 660-700 billion mB/a in 2020 (see Table 7.3), new deposits must be explored and developed in the long run. The development of deposits on the Yamal peninsula has been a major project but has been delayed for many years. Although one reason for the delay was the ecological damage the project might cause, it must, however, also be questioned whether those development plans are economically justified. According to Locatelli (1999), the development of the large deposits in the Yamal region is costly compared with other fields in Western Siberia. In addition, the first draft of the Energy Strategy emphasises that the development of the Yamal Peninsula is more expensive than the development of the offshore field Shtokmanovskoye, which is now on the agenda of further development projects. However, according to IEA (2002, 115) the projection, that production already will start in 2010 from were obviously overestimated by Soviet figures. Western estimates put them at 8-11billion tonnes (IEA 1995). 22According the IEA (1995) potential reserves are estimated at 212 tcm.

21Oil reserves

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Shtokmanovskoye is ambitious given the organisational and financial problems ahead. 23 In the end, the development of new deposits or the exploitation of deeper horizons of operating fields will be a question of financing. In recent years, investment in the energy sector has fallen on the whole. Although figures for the development of investments in the gas industry alone are not available, it must be assumed that in the gas industry, too, replacement or even modernisation of the existing capital stock has remained low. According to the Energy Strategy, investment needs (including field development) until 2020 will amount to 180billionS; current investment outlays, however, will not be sufficient to meet this target. 24 All in all, the realisation of the development projects and thus the production target for 2020 are to be questioned. It must be noted, however, that the Energy Strategy emphasises gas price increases as a precondition for investment plans. This is a novelty of Russian energy policy. In the years following the break-up of the Soviet Union and the beginning of economic transition in Russia, natural gas production declined from 640billionm 3 in 1992 to 571 billion m 3 in 1997 (see Table 7.4a-c). This decline was far less pronounced than in other industrial branches. In 1998, gas production increases could even be reported despite the so-called financial crisis that affected the whole economy. In 2002 gas production amounted to 593 billion m 3. During the 1990s, the structure of energy p r o d u c t i o n - calculated on the basis of petajoule - changed significantly in favour of natural gas. The reason for this is that the decline in production of crude oil, coal and electricity from hydroelectric and nuclear power stations was far more pronounced than that of natural gas during this period. Therefore, natural gas is currently the most important energy source, accounting for almost one-half of primary energy production. According to the Energy Strategy (Ministerstvo Energetiki, 2002) the share of gas in domestic energy production will stabilise in a first variant or decline to 42% according to the second variant. Primary gas consumption also declined to a lesser extent than oil (and coal) consumption changing significantly the consumption structure (see Table 7.5a-c): whereas at the beginning of the 1990s 2310 develop the Shtokmanovskoye field Gazprom has formed a venture with a Western consortium (Conoco, Total Fina Elf, Norsk Hydro and Fortum). As in other joint ventures (e.g., with Shell and ENI) decisive steps have not not been underaken thus far (see IEA 2002, 118). 24The investment programme for 2002 amounts to 157 billion Rbl. (5.7 billion), see Bank of Finland, Russian & Baltic Economies. The Week in Review, No. 14/2002.

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Table 7.4. Primary energy production.

Lignite mn t

Coal mn t

Electricity Hydro Nuclear bn kWh

Crude Oil 2 mn t

Natural Gas bcm

516.2 461.1 396.4 354.4 317.8 307.0 301.0 305.8 303.3 305.2 323.4 348.1 379.0

640.5 643.0 640.4 618.3 607.3 595.0 601.0 571.0 591.0 592.0 583.6 581.2 593.0

166.8 168.5 172.0 175.0 176.9 176.4 155.0 158.0 159.0 161.0 165.0 175.0 164.0

118.3 120.0 119.5 119.1 98.0 99.5 108.8 109.0 104.0 122.0 131.0 137.0 142.0

54.3 51.2 48.2 45.0 42.2 41.2 40.9 39.9 40.2 40.9 41.6 43.0 44.3

(b) Structure of Production in %1 1990 3.1 10.8 39.8 1991 3.1 9.9 37.7 1992 3.2 10.1 34.5 1993 3.2 9.6 33.0 1994 3.1 9.0 31.5 1995 3.0 8.9 31.2 1996 3.0 8.7 30.8 1997 2.9 8.6 32.1 1998 2.7 8.1 31.6 1999 2.8 8.7 31.3 2000 2.8 8.8 32.5 2001 2.8 9.1 34.0 2002* 2.6 9.2 35.8

41.1 43.8 46.4 47.9 50.1 50.4 51.2 49.9 51.3 50.5 48.9 47.2 48.7

3.0 3.2 3.5 3.8 4.1 4.1 3.7 3.8 3.8 3.8 3.8 3.9 3.6

2.1 2.3 2.4 2.6 2.2 2.3 2.6 2.6 2.5 2.9 3.0 3.1 3.1

100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0

100.0 101.0 103.1 104.9 106.1 105.8 92.9 94.7 95.3 96.5 98.9 104.9 96.3

100.0 101.4 101.0 100.7 82.8 84.1 92.0 92.1 87.9 103.1 110.7 115.8 120.0

100.0 94.4 88.7 82.9 77.8 75.9 75.3 73.5 74.0 75.3 76.6 79.2 81.6

(a) Production Volumes I 1990 137.3 257.4 1991 130.5 222.9 1992 124.5 212.5 1993 116.0 189.0 1994 105.5 165.7 1995 101.0 161.0 1996 98.5 156.5 1997 94.0 150.0 1998 87.0 143.0 1999 93.0 155.0 2000 95.0 161.0 2001 98.0 171.0 2002* 93.0 160.0

(c) Development of Production in % (1990= 100) 1 1990 100.0 100.0 100.0 100.0 1991 95.0 86.6 89.3 100.4 1992 90.7 82.6 76.8 100.0 1993 84.5 73.4 68.7 96.5 1994 76.8 64.4 61.6 94.8 1995 73.6 62.5 59.5 92.9 1996 71.7 60.8 58.3 93.8 1997 68.5 58.3 59.2 89.1 1998 63.4 55.6 58.8 92.3 1999 67.7 60.2 59.1 92.4 2000 69.2 62.5 62.7 91.1 2001 71.4 66.4 67.4 90.7 2002* 67.7 62.2 73.4 92.6

Total Exa-Joule

*Estimates; 1Until 1991 RSFSR; 2Including gas condensate. Sources: Goskomstat: Statistical Yearbook of Russian Federation, various issues; Goskomstat: Informacija o sotsial'no-ekonomicheskom polozhenii Rossii, XII, god, janvar'-dekabr' 2002 god.

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Table 7.5.

Consumption volumes. 1 Lignite mn t

Coal mn t

Oil 2 mn t

Natural Gas bcm

Electricity bn kWh

Total Exa-Joule

(a) Consumption Volumes I 1990 137.3 264.7 1991 130.5 238.7 1992 124.5 228.4 1993 116.0 207.5 1994 105.2 178.6 1995 101.0 151.9 1996 98.5 152.9 1997 94.0 143.4 1998 87.0 134.0 1999 93.0 143.0 2000 95.0 143.0 2001 98.0 151.0 2002* 91.0 145.0

258.7 274.6 233.8 204.5 152.2 147.6 127.0 127.4 121.0 125.8 122.8 122.4 120.0

456.7 407.3 457.3 443.7 413.7 393.9 408.7 372.2 391.0 391.1 389.6 400.2 396.0

276.7 276.4 275.2 275.4 255.4 256.3 244.3 247.3 244.9 268.9 282.0 292.6 295.0

37.2 35.4 35.1 32.9 28.6 27.1 26.6 25.1 25.2 25.9 25.9 26.5 26.7

of Consumption in % 1 4.5 16.3 29.2 4.5 15.4 32.5 4.4 14.9 27.9 4.3 14.4 26.1 4.5 14.2 22.3 4.6 12.8 22.8 4.5 13.1 20.0 4.6 13.0 21.2 4.2 12.2 20.1 4.4 12.6 20.3 4.5 12.6 19.9 4.5 13.0 19.3 4.3 12.7 19.3

42.8 40.1 45.4 47.1 50.4 50.7 53.5 51.6 54.1 52.6 52.5 52.6 52.9

7.2 7.5 7.6 8.1 8.6 9.1 8.9 9.5 9.4 10.0 10.5 10.6 10.9

100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0 100.0

100.0 99.9 99.5 99.5 92.3 92.6 88.3 89.4 88.5 97.2 101.9 105.7 106.6

100.0 95.3 94.6 88.4 77.1 72.9 71.7 67.6 67.8 69.7 69.6 71.5 71.9

(b) Structure 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002*

(c) Development of Consumption in % (1990= 100) 1 1990 100.0 100.0 100.0 100.0 1991 95.0 90.2 106.1 89.2 1992 90.7 86.3 90.4 100.1 1993 84.5 78.4 79.0 97.2 1994 76.6 67.5 58.8 90.6 1995 73.6 57.4 57.1 86.2 1996 71.7 57.8 49.1 89.5 1997 68.5 54.2 49.2 81.5 1998 63.4 50.6 46.8 85.6 1999 67.7 54.0 48.6 85.6 2000 69.2 54.0 47.5 85.3 2001 71.4 57.0 47.3 87.6 2002* 86.3 54.8 48.4 86.7

*Estimates; 1Until 1991 RSFSR; 2Including gas condensate. Sources: Goskomstat: Statistical Yearbook of Russian Federation, various issues; Goskomstat: Sotsial'no-ekonomicheskoe polozhenie Rossii 2001 god, XII/2001.

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Fig. 7.1. Energy Intensitiy in toe/thousand US $ (at constant 1995 prices, converted by official exchange rates and purchasing power parities). Source: The World Bank, 2002 World Development Indicators CD-Rom. oil a c c o u n t e d for a b o u t 30% a n d gas for a b o u t 43% of c o n s u m p t i o n , in 2002 oil accounts for less t h a n 20% a n d n a t u r a l gas for 53%. 25 The E n e r g y Strategy foresees l o w e r i n g the share of gas c o n s u m p t i o n (about 45-47% in 2020), w h e r e a s the share of coal c o n s u m p t i o n will slightly increase. Total gas c o n s u m p t i o n will increase by about 20% a n d total final c o n s u m p t i o n by 25-38% by the year 2020 ( a s s u m i n g the realisation of a potential on e n e r g y savings a m o u n t i n g to 360-430 toe). At the s a m e time it is a s s u m e d that G D P will increase by 180-190% c o m p a r e d w i t h 2000. This s h o u l d enable e n e r g y intensity (see Fig. 7.1), w h i c h in Russia is still c o m p a r a t i v e l y high, to be r e d u c e d by one half. 26 H o w e v e r , a s s u m p t i o n s on G D P g r o w t h , e n e r g y savings a n d e n e r g y c o n s u m p t i o n are over-optimistic given the p r e s e n t state a n d prospects of the Russian e c o n o m y a n d the lagging r e f o r m m e a s u r e s in the e n e r g y sector. 27 It is true that economic g r o w t h has recovered 25Data on consumption by sectors is scarce and the rare figures presented by various organisations are not comparable due to different statistical concepts. Power generation is obviously the single largest gas consumer. According to IEA (2002) about 33% of total final gas consumption is used by industry, 27% by road and pipeline transport and the remaining share by other sectors, including private households whose gas consumption is obviously low compared with western countries. A further increase by decentralised customers would only be possible if the transmission and distribution system were to be extended. If investment costs are taken into account, however, it is more reasonable to expand gas supplies to huge industrial users first. 26An analysis on energy intensity in transition countries is provided by the EBRD (2001, 91ff). 27The scenarios of the Energy Strategy cannot be discussed here in detail. For an analysis of the scenarios provided in the first draft of the Energy Strategy see G6tz (2002).

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s i g n i f i c a n t l y a n d that t h e r e is g r e a t p o t e n t i a l for e n e r g y s a v i n g s . I m p r o v i n g e n e r g y efficiency, h o w e v e r , is o n l y possible if the price s y s t e m is c h a n g e d . If this can be c a r r i e d out, a n i m p r o v e m e n t of the o v e r a l l e c o n o m i c s i t u a t i o n will n o t n e c e s s a r i l y b r i n g w i t h it a s i g n i f i c a n t increase in c o n s u m p t i o n .

7.4.2. Gas exports T h e v o l u m e of n a t u r a l gas e x p o r t s fell d r a s t i c a l l y f r o m 2 4 7 b i l l i o n m 3 in 1991 to 189billion m 3 in 1 9 9 2 - the y e a r w h i c h m a r k e d the start of t r a n s i t i o n in Russia. After a slight r e c o v e r y d u r i n g the 1990s, gas e x p o r t s a m o u n t e d to a b o u t 187 billion m 3 in 2002 (see Table 7.6). N e v e r t h e l e s s , b e s i d e s p e t r o l e u m exports, n a t u r a l gas e x p o r t s are i m p o r t a n t for c u r r e n c y e a r n i n g s (see Table 7.7). As r e v e n u e s f r o m e n e r g y e x p o r t s a c c o u n t for a b o u t 52% of total e x p o r t e a r n i n g s , the R u s s i a n t r a d e b a l a n c e is h i g h l y v u l n e r a b l e to c h a n g e s in i n t e r n a t i o n a l e n e r g y prices, especially p e t r o l e u m prices. This c o u l d , for i n s t a n c e , be o b s e r v e d in 1998, w h e n prices fell a n d it w a s n o t p o s s i b l e to fully offset this fall b y e x p a n d i n g e x p o r t v o l u m e s . In r e c e n t years, h o w e v e r , the r e v e r s e has b e e n true: w i t h e n e r g y prices u p o n w o r l d m a r k e t s , R u s s i a h a s g a i n e d a d d i t i o n a l i n c o m e t h r o u g h e n e r g y exports. This Table 7.6. Export volumes. Region 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002* Crude Oil mn t Total 235.0 161.0 139.0 122.8 128.2 122.3 125.6 127.1 137.1 134.8 144.5 160.0 175.0 C.I.S. 104.0 72.8 42.9 32.8 26.1 20.6 17.1 19.2 18.8 16.9 22.5 18.0 Others 56.0 66.2 79.9 95.4 96.2 105.0 110.0 117.9 116.0 127.6 137.5 157.0 Total C.I.S. Others

Petroleum 54.0 50.0 42.8 45.1 47.3 47.5 30.0 23.0 17.5 10.0 8.2 3.5 24.0 27.0 25.3 35.1 39.1 44.0

Products mn t 57.0 60.6 53.8 50.7 61.9 71.0 75.0 2.0 2.2 2.6 2.9 3.5 2.5 2.0 55.0 58.4 51.2 47.8 58.4 68.5 73.0

Total Petroleum mn t Total 289.0 211.0 181.8 167.9 175.5 169.8 182.6 187.7 190.9 185.5 206.4 231.0 250.0 C.I.S. 127.0 90.3 52.9 41.0 29.6 22.6 19.3 21.8 21.7 20.4 25.0 20.0 Others 83.5 91.5 115.0 134.5 140.2 160.0 168.4 169.1 163.8 186.0 206.0 230.0 Natural Gas bcm Total 249.0 247.0 189.0 171.0 185.0 192.0 197.0 200.0 203.0 205.0 193.8 181.0 187.0 C.I.S. 140.0 164.0 101.0 75.0 75.0 70.0 69.0 80.0 78.0 74.3 60.0 50.0 50.0 Others 109.0 83.0 88.0 96.0 110.0 122.0 128.0 120.0 125.0 130.7 133.8 131.0 137.0 *Estimates. Sources: Goskomstat: Statistical Yearbook of Russian Federation, various issues; Gosudarstvennyi tarnozhenyi komitet Rossiyskoy Federatsii (http://www.customs.ru/ stat_show.xpml?mds_objectid-4092.

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Table 7.7. Export earnings in US-$ bn. 1994 1995 1996 1997 1998 1999 2000 2001 2002* Crude Oil Petroleum Products Total Petroleum Natural Gas Petroleum and Natural Gas Export share %

10.5 4.1 14.8 10.8 25.2 37.4

13.3 5.0 18.3 12.1 30.5 37.0

15.9 7.5 23.4 14.7 38.1 42.5

13.8 7.3 21.1 16.4 37.5 43.1

10.3 4.3 14.5 13.4 27.9 37.5

14.2 5.4 19.6 11.4 31.0 41.0

25.3 10.9 36.2 16.7 52.9 50.3

24.6 9.4 34.0 17.0 51.8 51.0

28.3 10.9 39.2 15.9 56.1 51.9

*Estimates. Sources: The Central Bank of the Russian Federation, Balance of Payments of the Russian Federation, http://www.cbr.ru, January 2003. a d d i t i o n a l c u r r e n c y e a r n i n g is said to be o n e of the factors w h i c h h a v e c o n t r i b u t e d to the r e c o v e r y of the R u s s i a n economy. D u r i n g 1992-2002, the direction of gas as well as oil e x p o r t s h a v e c h a n g e d drastically. Gas sales to CIS c o u n t r i e s that are u n a b l e or u n w i l l i n g to p a y their gas bills w e r e r e d u c e d b y a l m o s t one-halL w h e r e a s deliveries to non-CIS countries i n c r e a s e d b y 50% (see Table 7.6). The E u r o p e a n U n i o n t o d a y receives a b o u t 27% of its n a t u r a l gas i m p o r t s f r o m the f o r m e r Soviet U n i o n (see Table 7.8). 28 A c c o r d i n g to G a z p r o m , w h i c h has a de facto m o n o p o l y o n deliveries to W e s t e r n E u r o p e a n countries, its major c u s t o m e r is G e r m a n y w i t h i m p o r t s a m o u n t i n g to a b o u t 33 billion m 3 in 2001, f o l l o w e d b y Italy ( 2 0 b i l l i o n m 3) a n d France (11billion m3). In contrast to W e s t e r n E u r o p e a n countries, G a z p r o m ' s exports to CIS a n d Baltic countries h a v e b e e n r e d u c e d . Today, Itera is the m a i n d e l i v e r e r to CIS a n d Baltic countries. In 2001 its e x p o r t s a m o u n t e d to a b o u t 70 billion m 3, including deliveries of T u r k m e n gas via the R u s s i a n p i p e l i n e n e t w o r k . 29 O n e r e a s o n for Itera's d o m i n a n t p o s i t i o n in CIS m a r k e t s is that it has u s e d b a r t e r in a v a r i e t y of w a y s to deal w i t h the n o n - p a y m e n t p r o b l e m of CIS countries (IEA 2002, 116f). In the past, the central p r o b l e m for R u s s i a n gas exports to w e s t e r n countries has b e e n that a l m o s t all e x p o r t s h a v e m o v e d t h r o u g h U k r a i n i a n pipelines. U k r a i n e has officially p a r t l y p a i d for its o w n gas

28In most statistics no figures are given for Russian exports to the EU. There is, however, no significant difference between Russian and Former Soviet Union exports, as other CIS countries' exports to western Europe are marginal. 29In 2001 Turkmenistan's natural gas production amounted to about 48 billion m 3. Before the construction of an export pipeline to Iran, Turkmenistan had been dependent on Russian gas export lines. Because of a pricing dispute Gazprom limited Turkmen exports via Russia until 1998 (see United States Energy Information Administration (EIA), 2002a).

156

National Reforms in European Gas

Table 7.8. European Union: Petroleum and Natural Gas Imports. 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002* Crude Oil mn t of which: from former Soviet Union in mn t in %

534.7 538.5 526.0 548.0 559.4 582.8 547.9 565.9 567.0 569.2

63.2 71.2 64.1 72.6 75.1 74.5 87.5 98.1 110.3 135.8 11.8 13.2 12.2 13.2 13.4 12.8 16.0 17.3 19.5 24.3

Petroleum Products mn t 187.4 181.6 183.1 188.6 188.1 191.2 200.6 212.3 220.2 221.0 of which: from former Soviet Union 17.8 15.4 17.4 23.9 24.4 25.7 26.9 27.0 32.6 40.4 in mn t 9.5 8.5 9.5 12.7 13.0 13.4 13.4 12.7 14.8 18.3 in % Total Petroleum mn t of which: from former Soviet Union in mn t in %

722.1 720.1 709.1 736.6 747.5 774.0 748.5 778.1 787.2 780.2

Natural Gas bcm of which: from former Soviet Union in bcm in %

163.4 167.2 180.1 201.9 206.1 201.8 226.3 244.4 249.1 256.2

81.0 86.6 81.4 96.4 99.5 100.2 114.3 125.1 142.9 176.2 11.2 12.0 11.5 13.1 13.3 12.9 15.3 16.1 18.2 22.6

33.0 71.2 77.9 75.9 73.7 69.9 75.7 77.9 69.9 68.5 20.2 42.6 43.2 37.6 35.8 34.7 33.5 31.7 28.1 26.7

*Estimates. Sources: IEA: Oil, Gas, Coal and Electricity, Quarterly Statistics, various issues. i m p o r t s f r o m R u s s i a w i t h t r a n s i t fees. H o w e v e r , U k r a i n e a c c u m u l a t e d l a r g e d e b t s to G a z p r o m . 3~ I n r e s p o n s e , G a z p r o m t e m p o r a r i l y r e d u c e d o r e v e n c a n c e l l e d d e l i v e r i e s . I n r e s p o n s e , U k r a i n e h a s t h r e a t e n e d to i n t e r r u p t e x p o r t s to w e s t e r n c o u n t r i e s a n d i n s o m e c a s e s h a s e v e n a c t e d in its o w n i n t e r e s t . A f t e r a l o n g d i s p u t e , i n s u m m e r 2002 R u s s i a a n d U k r a i n e s i g n e d a n a g r e e m e n t o n t r a n s i t c o n d i t i o n s (110 b i l l i o n m g / a b e t w e e n 2003-2013). A l t h o u g h , this m i g h t e n h a n c e the reliability of U k r a i n i a n t r a n s i t , G a z p r o m , h a s b e g u n to d i v e r s i f y its e x p o r t r o u t e s . T h e f u t u r e of R u s s i a n g a s e x p o r t s as a w h o l e is h a r d to p r e d i c t . W h a t is c l e a r is t h a t , as l o n g as CIS c o u n t r i e s r e m a i n u n r e l i a b l e c u s t o m e r s , R u s s i a w i l l t r y to e x p a n d its d e l i v e r i e s to o t h e r c o u n t r i e s , i n p a r t i c u l a r to t h e EU. O n e s t e p in t h i s d i r e c t i o n h a s b e e n G a z p r o m s ' long-term contracts with western companies on gas deliveries;

3~ to Gazprom's figures on January 1, 1999, debt of the CIS countries amounted to US-$1.57 billion (Gazprom, 1999). The current payments were fulfilled by only 65% (taking into account Russian payment for gas transit through Ukraine). Cash payments have remained at a low rate of 6.6%.

The Russian Gas Sector

157

Gazprom also owns shares in companies engaged in distribution and transportation. 31 Another step is the 'strategic energy partnership' concluded between the EU and Russia in autumn 2000 which, among other things, envisages building a new pipeline from Russia via Belarus, Poland and Slovakia to Western Europe (projected capacity: 30 billion m3; if the option of an additional pipeline is realised: 60 billion m3). The gas pipeline from Yamal to the border between Poland and Germany was already opened in autumn 1999 and has since been connected with the German pipeline network (full capacity of the Yamal pipeline in 2004:30 billion m3). Projects exist to build a second Belarus-Poland line parallel to the first, either as a sea route with spur lines for delivering gas to Finland and Sweden or as a combination land and sea-route through Finland and Sweden (IEA 2002, 139). All in all, these new pipelines (see Fig. 7.2) should enable transit via Ukraine to be avoided at least in part and transmission to be diversified further. One must, however, also look at the downside of these plans: above all, they entail high transportation and transit costs (Engerer et al., 1999). Gazprom, therefore, criticises the European Union's plan to liberalise the western gas markets, to strengthen competition and introduce new kinds of contracts (short-term contracts and spot transactions). According to Gazprom, field development projects and further investments have to be reconsidered if the 'take or pay condition' is no longer guaranteed. Russia also wants to expand its deliveries to South-East Europe. A potential market is Turkey, which expects a large increase in natural gas demand. During the 1990s, exports to Turkey were affected by the Russian-Ukrainian transit dispute. Then, in autumn 1999, Gazprom and the Italian ENI signed a contract to build the Blue Stream Pipeline connecting Russia directly with Turkey via the Black Sea (capacity: 16 billion m3). The first line was already completed in March 2002; the second line will follow at the end of 2002. Negotiations on pipeline construction are also underway with other countries of South-East Europe (e.g., Romania). If the economic situation in South-East European transition countries recovers, their gas consumption will probably rise as well. The dependence on Russian energy supply and bad experiences in the past, however, make many transition countries

31Gazprom, for instance, owns shares in companies from Germany (Wintershall Gas GmbH) and Finland (Gasum Oy). It has a long-term delivery contract with the German Ruhrgas AG. Together with Neste Oy Finland, it is working on a study for gas transportation. See for joint venture activities of Gazprom with Western Europe Opitz et al., 2002, 305.

158

National Reforms in European Gas

Fig. 7.2. Russian Oil and Gas export routes.

reluctant to significantly increase imports from Russia. They would rather attempt to diversify their supply structure. Some of them, however, also stand to gain from their position as transit countries. 32 Outside Europe, Russia has projects to export gas to Asian countries. One proposal is to build an export pipeline from Eastern Siberia to China (with an extension to South Korea). However, Russian-Chinese negotiations in s u m m e r 2002 did not produce concrete results (one point of controversy is the gas price). In sum, these projects are unrealistic. Nevertheless, the Energy Strategy mentions the Asian market as another potential export region in addition to European and CIS countries. At the same time, however, projections on gas exports in 2020 were reduced to 225-244 billion m 3, compared to 270-275 billion m 3 in the first draft of the Energy Strategy. Thus, Russia itself more carefully assesses its future gas export potential.

32Examples are the long-term agreements for gas transit with the Bulgarian company Bulgargaz and the Czech company Transgaz.

The Russian Gas Sector 7.5. U n k n o w n

159

Future

The question of where the Russian gas industry is headed is first and foremost a matter of the overall economic development. The Russian gas sector is not an ordinary field of activity. Instead, it is an important earner of foreign currency and a major tax payer. Therefore, gas sector reforms cannot be undertaken insulated from the rest of the economy. This might be the reason why the Energy Strategy does not outline clear reform measures. Instead, it outlines vague and, in some areas, ambiguous reform steps. This holds true in particular for price reforms, which are urgently needed if independent producers are to expand and carry out their activities profitably. So far, however, while price reforms are seen to be the key point of gas sector reforms, only a step-by-step increase of domestic gas prices is envisaged - without a binding t i m e - t a b l e - and the underlying problems are not solved. Another point is Third Party Access, which today is obviously not guaranteed in practice. Although Gazprom has been put under pressure to open up its export lines, it has successfully defended its de facto monopoly. It remains unclear what the 'balance' of a certain degree of liberalisation of gas exports and maximal benefits for the Russian economy, as proposed by the Energy Strategy, will actually look like. These are only two examples of the ambiguous reforms proposed. The development of the Energy Strategy itself mirrors the difficulties of gas sector reform on the whole. In recent years the new government has actually played a more active part in gas sector reform, presenting plans for restructuring and liberalisation and for fostering competition that have been generally unpopular. It has, however, also become embroiled in discussions with the various interest groups opposing reforms. One result of this is that the first draft of the Energy Strategy has been revised only one year later, delaying the elaboration of concrete reform measures until 2003 and their probable implementation for an indefinite period. It is, however, also possible, that even the second draft of the Energy Strategy will not be approved by the Russian parliament. In this case, the current process of muddling through will continue. However, even if comprehensive reforms of the gas sector were to be implemented in the near future, restructuring and introduction of competition would still take some time. In particular, independent gas companies will first have to assert themselves against Gazprom's dominant position. A final remark is on the evaluation of overall economic transition and gas sector transformation in Russia. Western experts probably expect too many and too rapid reforms from Russia. One has to keep

160

National Reforms in European Gas

in m i n d that there is resistance to gas market reform in Western Europe, too, and that reforms have progressed slowly in recent years here as well.

7.6. Summary During the Soviet era the gas industry was part of the planned system. Production and export volumes were regulated by state authorities and prices were centrally administered. Regulations were maintained even after the policy of Perestroika had given enterprises in other branches some independence from state authorities. The energy ministry only lost its influence on the gas industry at the end of the 1980s, w h e n G a z p r o m came into being. During the 1990s, G a z p r o m maintained its d o m i n a n t position on the domestic market. In contrast to other branches of the economy, competitive structures have still not actually been introduced in the gas industry, nor have energy prices and trade been sufficiently liberalised. Thus it has been difficult for i n d e p e n d e n t gas companies to carry out their activity profitably. Then, in 2000, the new g o v e r n m e n t presented its gas reform ideas, calling for comprehensive restructuring, liberalisation and introduction of competition. However, it did not implement concrete reform measures. Instead, the urgently needed gas sector reforms were further delayed. As it remains highly uncertain whether the n e w draft of the Energy Strategy will be implemented in the near future, more time and more resources will go to waste. The present process of m u d d l i n g through is not sustainable indefinitely, and no one k n o w s h o w long it can last.

Literature Bank of Finland (BOFIT) (2002) Russian & Baltic Economies. The Week in Review, No. 1/ 2002. Bank of Finland (BOFIT) (2002a) Russian & Baltic Economies. The Week in Review, No. 14/2002. Centre for Strategic Research, (2000) Strategy of the Russian Federation through 2010. Social and Economic Aspect, Moscow, mimeo. DIW (German Institute for Economic Research), (2002). Russia's Economy Steering a Risky Course, DIW Economic Bulletin, 39(3): 81-94. DIW/IfW (German Institute for Economic Research, Berlin (DIW), Institute for the World Economy at the University of Kiel (IfW), (2001) Russian Economic Recovery in Jeopardy, DIW Economic Bulletin, 38(2): 53-72. DIW/IfW/IWH (German Institute for Economic Research, Berlin (DIW), Institute for the World Economy at the University of Kiel (IfW) and Institute for Economic Research Halle (IWH), (1999) The Economic Situation in Russia, DIW Economic Bulletin, 36(6): 17-32.

The Russian Gas Sector

161

Engerer, Hella (2001) Privatisation and Its Limits in Central and Eastern Europe. Property Rights in Transition, Basingstoke, Hampshire and New York, Palgrave. Engerer, Hella and Christan von Hirschhausen, (1998) The Energy Sector in the Caspian Sea Region: Disappointed Hopes -Uncertain Prospects, DIW Economic Bulletin, 35(9): 21-32. Engerer, Hella; Petra Opitz and Christian von Hirschhausen (1999) Russia's Energy Sector in the Wake of the Financial Crisis, DIW Economic Bulletin, 36(7): 21-28. Ekonomika i zhizn', No. 33/1999, 1. Ekonomika i zhizn', No. 18/1999, 10-12 (Rossiyskaya Federatsiya, Federal'nyy zakon 'O gazosnabzhenii v Rossiyskoy Federatsii'). Ekonomicheskaya gazeta, No. 29/1992, 15-18 ('Gosudarstvennaya programma privatizatsii gosudarstvennych i municipal'nych predpriyatiy v Rossiyskoy Federatsii na 1992 god'). Ekonomicheskaya gazeta, No. 12/1984, 11-14 ('Osnovnye polozheniya energeticheskoy programmy SSSR na dlitel'nuyu perspektivu'). European Bank for Reconstruction and Development (EBRD) (2001) Transition Report 2001. Energy in Transition, London. Gazprom (1999) Annual Report 1998 and Annual Report 1997 (www.Gazprom.ru/html/ english / corpInfo / default.htm, August 1999). G6tz, Roland (2002) Russtands Erdgas und die Energiesicherheit der EU, [Stiftung Wissenschaft und Politik (SWP), SWP-Studie, S. 12], Berlin. Gosudarstvennyy komitet Rossiyskoy Federatsii po statistike (Goskomstat) - Statistical Yearbook of Russian Federation, various issues, Moscow. - Sotsial'no-ekonomicheskoe polozhenie Rossii, various issues, Moscow. von Hirschhausen, Christian and Hella Engerer (1998) Post-Soviet Gas Sector Restructuring in the CIS: A Political Economy Approach, Energy Policy, 26(15): 11131123. International Energy Agency (IEA) (2002) Russian Energy Survey 2002, Paris. International Energy Agency (IEA) (1995) Energy Policies of the Russian Federation, Paris. International Energy Agency (IEA), Oil, Gas, Coal and Electricity, Quarterly Statistics, various issues. Kryukov, Valery and Arild Moe (1999) Gazprom under Pressure, International Association for Energy Economics (IAEE), New Equilibria in the Energy Markets: The Role of New Regions and Areas, 1: 415-423. Kryukov, Valery and Arild Moe (1996) The New Russian Corporatism? A Case Study of Gazprom (The Royal Institute of International Affairs, Russia and Eurasia Programme), London. Locatelli, Catherine (1999) The Dynamics of Industrial Organisation in Economies in Transition: The Example of the Russian Gas Industry, paper presented at the International Conference on 'Institution in Transition', Maribor, 8-9 October 1999. Ministerstvo Energetiki Rossiyskoy Federatsii (MinEnergo) (2002) Osnovnye Polozheniya Energeticheskoy Strategii Rossii na Period do 2020 goda. Projekt, Moscow (www.mte. gov.ru/oficial/strateg_energ.htm Ministerstvo Energetiki Rossiyskoy Federatsii (MinEnergo) (2001) Osnovnye Polozheniya Energeticheskoy Strategii Rossii na Period do 2020 goda. Projekt, Moscow www.mte. gov. ru / oficial / strateg_energ, htm. Opitz, Petra, Hella Engerer and Christian von Hirschhausen (2002) The Globalization of Russia Energy Companies: A Way Out of the Financial Crisis?, International Journal of Global Energy Issues, 17(4): 292-310. Organisation for Economic Co-Operation and Development (OECD) (2002) OECD Economic Surveys 2001-2002. Russian Federation, Paris.

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Organisation for Economic Co-Operation and Development (OECD), Energy Statistics and Balances of Non-OECD Countries, various issues. Quast, Oliver and Catherine Locatelli (1997) Russian Natural Gas Policy and its Possible Effects on European Gas Markets, Energy Policy, 2(25): 125-133. Pravitel'stvo Rossiyskoy Federatsii (2000), Plan Deystviy Pravitel'stva Rossiyskoy Federatsii v Oblasti Sotsial'noy Politiki i Modernizatsii Ekonomiki na 2000-2002 gody, Sobranie Zakonodatel'stva Rossiyskoy Federatsii, 33: 6809-6857. Pravitel'stva Rossiyskoy Federatsii (1998) Pravila Postavki Gaza v Rossiyskoy Federatsii, Sobranie Zakonodatel'stva Rossiyskoy Federatsii, 6: 1522-1528. Rossiyskaya gazeta, May 7th 1997, 3 (Ukaz Prezidenta Rossiyskoy Federatsii 'Osnovnye polozheniya strukturnoy reformy v sferach estestvennych monopoliy'). Rossiyskaya gazeta, July 24th 1993, 5 (Postanovlenie Soveta Ministrov Pravitel'stva Rossiyskoy Federatsii 'O gosudarstvennom regulirovanii tsen na prirodnyy gaz i drugie vidy energoresursov'). Russian European Centre for Economic Policy (RECEP), Russian Economic Trends, Monthly Update, various issues. Sagers, Matthew J., Valery A. Kryukov and Vladimir V. Shmat (1995) Resource Rent from the Oil and Gas Sector in the Russian Economy, Post-Soviet Geography, 389-425. Sobranie Aktov Presidenta Rossiyskoy Federatsii, No. 19/1992 (Ukaz Prezidenta Rossiyskoy Federatsii 'O preobrazovanii Gosudarstvennogo gazogo kontserna 'Gazprom' v Rossiyskoe aktsionernoe obshchestvo 'Gazprom'). Sobranie Zakonodatel'stva Rossiyskoy Federatsii, No. 33/2000 (Rasporyazhenie Pravitel'stva Rossiyskoj Federtsii: 'Plan deystvii Pravitel'stva Rossijskoy Federatsii v oblasti social'noy politiki i modernizatsii ekonomiki na 2000-2001 gody', 6809-6857; Strategiya razvitiya Rossiyskoy Federtsii do 2010 goda (proekt)', Moscow 2000). Sobranie Zakonodatel'stva Rossiyskoy Federatsii, No. 49/1995, No. 8818 (Ukaz Prezidenta Rossiyskoy Federatsii 'O Federal'noy energeticheskoy komissii Rossiyskoy Federatsii'). Stern, Jonathan P. (1995) The Russian Natural Gas 'Bubble'. Consequences for European Gas Markets (The Royal Institute of International Affairs, Energy and Environmental Programme), London. The World Bank (2002), 2002 World Development Indicators CD-Rom, Washington D.C. United States Energy Information Administration (EIA) (2002), Russia www.eia.doe. gov/emeu / cabs/russia.html, April 2002. United States Energy Information Administration (EIA) (2002a), Central Asia: Turkmenistan Energy Sector (www.eia.doe.gov/emeu / cabs/russia.html, May 2002. United States Energy Information Administration (EIA) (1998), Russia www.eia.doe. gov / emeu / cabs / russia.html, October 1998.

Chapter 8 Gas as a Public Property. The U K Gas Market 1965-86: Maximising the Value of a Limited National R e s o u r c e STEVE THOMAS

8.1. Introduction Production of natural gas from the British sector of the North Sea began in 1970. The known reserves were then limited, so natural gas was used mainly to replace town gas (manufactured from coal and naphtha) in the British market. Its use was restricted to 'premium' uses rather than bulk steam-raising in the British market, and exports were not allowed. It was sold at low prices to benefit British consumers and industry through the nationally owned monopoly gas supplier, British Gas. This policy continued until 1986 when British Gas was privatised and since then, gas has increasingly been treated as just another commodity, rather than as a limited national resource. This chapter examines how Britain successfully exploited its gas reserves through nationally controlled and owned organisations. It identifies the political, technical and economic factors that led to the dramatic change of policy in 1986, when government chose a marketled, private sector structure to replace the previous centrally planned system.

8.2. The Policy Rationale and its Implementation Natural gas was found in significant quantities in the Southern Basin of the UK sector of the North Sea in 1965. Further finds of gas in this area and, later, oil and gas in the Northern Basin of the North Sea 163

164

National Reforms in European Gas

meant that by the mid-70s, natural gas from British fields was a major energy source in the British market. By 1975, it was clear that selfsufficiency in oil could be achieved within a few years (see Tables 8.1, 8.2 and 8.3). However, oil and gas reserves were seen as limited, and selfsufficiency in oil was expected to last about a decade before production began to tail off. The volume of international trade in gas was then extremely small and reliance on large-scale imports of natural gas was not a viable option. Britain's natural gas was therefore seen as a national resource that should be used in Britain for the overall benefit of the British economy, providing cheap, clean energy for as long as possible. Natural gas was targeted at markets where its special qualities of cleanliness, ease of use, and lack of need for on-site storage would be most valued. These 'premium' applications were mainly the residential market and some industrial processes. Britain's status then as a 'gas island' not connected to mainland Europe meant that supply and demand had to be planned together so that no imbalances emerged. It was expected that natural gas would be supplemented and eventually replaced by substitute natural gas (SNG) made from British coal, then believed to have huge reserves. While the Oil Crisis of 1974/75 derailed most energy industry plans, it only strengthened the objectives set for the British gas industry, reinforcing its status as a 'noble' fuel and increasing its value to the British economy. British coal, via the 'Plan for Coal '1 and nuclear power, formed the other main prongs of the energy strategy. Coal was expected to meet bulk heat applications, such as power stations and industrial boilers, and would be the feedstock for synthetic oil and gas products. At the heart of the government's strategy to meet the aims for gas was the creation, under the Gas Act of 1972, of a vertically integrated, state-owned gas company, British Gas. This was achieved by merging the twelve regional Gas Boards with the Gas Council, which had been a coordinating body for the industry. British Gas was given responsibilities to supply final consumers, and develop and expand the natural gas network. It was also able to compete with private sector oil and gas companies to carry out exploration and production of gas resources. It had monopsony purchase rights over the gas produced in the UK sector of the North Sea.

1National Coal Board (1974) 'Plan for Coal', National Coal Board, London.

Table 8.1.

Primary fuel balance in the United K i n g d o m - 1965-2001 (million therms). Coal

Petroleum

Natural Gas

Electricity

r

Total

Production Consumption Production Consumption Production Consumption Production Consumption Production Consumption 1965 1970 1975 1980 1985 1990 1995 1998 2001

49096 36837 31430 31163 22458 22913 13515 10326 7945

48052 39299 29264 29106 25734 26856 19933 16400 16474

35 66 665 34502 55341 39830 56642 57578 50726

26453 37615 34259 30710 29167 30955 30057 29681 30361

66 4153 13578 13619 15752 18133 28247 35782 41998

326 4486 13913 17587 20565 20900 28443 33852 37720

1891 2727 2982 3537 5583 6169 8625 9569 8412

1894 2746 2985 3537 5583 7291 9181 9994 8767

51088 43783 48655 82821 99134 87049 107032 114101 110140

76725 84146 80421 80940 81050 86006 87618 90821 94336

Notes: 1. Primary electricity is mainly nuclear power production with a small amount of hydroelectric. Net imports of power from France represent the difference between production and consumption. 2. Total consumption is the total energy consumed for energy use, i.e., excluding feedstock use. 3. The fall in oil production after 1985 was largely accounted for by a major fire in 1988 at the Piper Alpha production platform, one of the major fields. This put the field out of action for several years and it was not until 1994, that oil production from this field returned to pre-accident levels. 4. British gas statistics are generally given in therms. One million therms are equivalent to 105.5 terajoules or 29.31 gigawatt hours. Conventionally in UK statistics, one million therms is equivalent to 2.52 thousand tonnes of oil equivalent or 2.75 million cubic metres of gas. Source: Digest of UK Energy (various), HMSO.

~,.a~ r

r

I

Table 8.2

UK Continental shelf gas reserves and production (billion cubic metres). Dry Gas

Proven 1975 1980 1982 1985 1987 1990 1992 1996 1998 2000 2001

892 1017 1076 1055 1165 1355 1425 1480 1510

Probable

101 320 331 310 350 280 260 190 200

Total

Condensate and Associated Gas

Possible

141 360 291 280 205 210 195 150 155

Total

1134 1697 1699 1645 1720 1845 1880 1820 1870

Proven

174 167 190 240 395 540 635 745 785

Probable

207 274 323 345 395 480 325 270 245

Possible

385 413 359 300 305 330 265 285 240

Total

Proven

766 854 873 890 995 1350 1225 1300 1265

982 1121 1066 1184 1266 1295 1465 1895 2065 2255 2320

Probable Possible 325 362 308 594 654 655 740 660 585 460 445

290 458 526 773 652 580 515 540 455 430 395

Total

Cumulative production

Remaining reserves

1597 1930 1900 2551 2572 2535 2720 3095 3105 3145 3160

167 382 433 536 622 752 855 1136 1311 1518 1625

1430 1548 1467 2015 1950 1780 1865 1960 1795 1630 1535

Sources: Department of Trade and Industry (1997) 'The Energy Report Volume 2: Oil and gas resources of the United Kingdom' The Stationery Office, London and Department of Energy (various) 'Development of the oil and gas resources of the United Kingdom, various years' HMSO, London.

~o

Gas as a Public Property. The UK Gas Market 1965-86

167

Table 8.3. UK continental shelf oil reserves and production (million tonnes).

1975 1980 1985 1990 1995 1998 2001

Proven

Probable

Possible

Total

Cumulative production

Remaining reserves

1350 1388 1580 1910 2520 2995 3290

960 575 480 660 765 575 350

880 600 650 620 520 535 475

3190 2910-3910 2710 3190 3805 4105 4115

1 263 825 1374 1917 2306 2687

3190 3175-4175 1880 1815 1890 1800 1430

Note: Proven reserves are defined as those which, on available evidence, are virtually certain to be technically and economically producible, i.e., those reserves which have a better than 90% chance of being produced. Possible reserves are those which are not yet 'proven" but which are estimated to have better than a 50% chance of being technically and economically producible. Possible reserves are those that at present cannot be regarded as 'probable' but are estimated to have a significant but less than 50% chance of being technically and economically producible. Sources: Department of Trade and Industry (1997) 'The Energy Report Volume 2: Oil and gas resources of the United Kingdom' The Stationery Office, London and Department of Energy (various) 'Development of the oil and gas resources of the United Kingdom, various years' HMSO, London.

8.3. The Development of Supply 8.3.1. Government policies F r o m 1965 to 1979, s u c c e s s i v e g o v e r n m e n t s t o o k a n u m b e r of m e a s u r e s to o b t a i n c o n t r o l of t h e N o r t h Sea r e s o u r c e a n d m a x i m i s e its b e n e f i t to t h e B r i t i s h e c o n o m y . T h e s e i n c l u d e d : 9 T h e c r e a t i o n of a n a t i o n a l l y o w n e d h y d r o - c a r b o n e x p l o r a t i o n a n d p r o d u c t i o n c o m p a n y , B r i t i s h N a t i o n a l Oil C o r p o r a t i o n ( B N O C ) in 1976; 9 T h e c r e a t i o n of t h e U K O f f s h o r e S u p p l i e s Office (OSO), a m a j o r o b j e c t i v e of w h i c h w a s to g i v e a 'full a n d f a i r ' o p p o r t u n i t y to U K c o m p a n i e s t e n d e r i n g for w o r k in e x p l o r a t i o n a n d p r o d u c t i o n activity; 2 9 A G o v e r n m e n t r i g h t - o f - v e t o o v e r i m p o r t s a n d e x p o r t s of gas, i n c l u d i n g a r e q u i r e m e n t t h a t all B r i t i s h - p r o d u c e d g a s w a s l a n d e d in t h e U K .

2Initially, the OSO was part of the Department of Trade and Industry but in 1974 it was substantially strengthened and was moved to the Department of Energy.

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A complex tax regime was set up to optimise revenue to the Treasury. Taxes were tuned to ensure that they were high enough to prevent oil and gas companies getting excessive profits from their North Sea operations, while providing sufficient incentive for continued exploration and production at levels best for the British economy. In addition to ownership of British Gas and control over trade in gas, the government could have used specific depletion policies, and the exploration and production licensing system to control the rate of depletion of gas reserves. The early priority was to stimulate activity to bring production up to a level that would provide enough gas for household and specialised industrial uses. In 1974, under the so-called 'Varley Assurances', Minister Eric Varley controlled the rate of depletion of oil. For gas, given the monopsony buying power of the state-owned British Gas, its gas sales monopoly, and the Minister's right of veto over imports and exports, there was no need for powers to control the rate of depletion of British natural gas. British Gas' status changed with the loss of its monopsony buying power in 1982 but the Conservative Government did not take additional powers over depletion to compensate for this loss of control. British Gas carried out its obligations in exploration and production of oil and gas through two subsidiaries, Gas Council (Exploration) Limited and Hydrocarbons Great Britain Limited. These operated mainly through partnerships with oil companies, but the Morecambe Bay field was British Gas' own responsibility (through Hydrocarbons GB Ltd). It also bought out the Rough field when it was partially depleted in order to develop it as a seasonal gas storage facility. Under the 1982 Oil & Gas Enterprise Act, British Gas was required to dispose of its interests in oilfields and to confine its future licence applications to areas expected to yield gas rather than oil. Its oil activities were transferred, without compensation, to a new company, Enterprise Oil, subsequently privatised. Nevertheless, its exploration subsidiaries remained active up to the time of privatisation.

8.3.2. The licensing and exploitation regime The 'Law of the Sea Conference' in 1959 made exploration in the North Sea possible and led to quite rapid agreement on sectoral boundaries among the various countries bordering the North Sea. 3 3The UK continental shelf currently represents a designated area of about 600,000 square kilometres in which the UK has rights over natural resources in respect of the seabed and subsoil.

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Exploration in the British sector was inspired by the discovery of huge quantities of gas in the Netherlands in 1962. Exploration licences for survey and shallow drilling (not exceeding 350 metres depth) for any area not covered by a production licence can be applied for at any time. The licenses are for three years, renewable for a further three years at the discretion of the relevant government minister (Table 8.4). Production licences grant the holder exclusive rights to explore and produce oil or gas in one or more blocks. They can only be applied for in response to an invitation (known as a Round of Licensing) from the government, which awards the licences on a discretionary basis. The duration and terms of these licences have varied from round to round. Typically, they are for an

Table 8.4.

Licensing rounds in the North Sea.

Round/Year

Blocks on offer

Blocks applied for

Blocks a w a r d e d

Term (Years)

1 (1964) 960 394 348 6 then further 40 2 (1965) 1102 127 127 6 then further 40 3 (1970) 157 117 106 6 then further 40 4 (1971/1972) 436 286 282 6 then further 40 5 (1976 / 1977) 71 51 44 4 + 3 then further 30 6 (1978/1979) 46 46 42 4 + 3 then further 30 7 (1980/1981) 1 97 90 6 then further 30 8 (1982 / 1983) 184 84 70 6 then further 30 9 (1984/1985) 195 120 93 6 then further 30 10 (1986/1987) 127 61 51 6 then further 30 11 (1988/1989) 212 115 105 6 then 12 then 182 12 (1990/1991) 161 116 07 6 then 12 then 182 13 (1992/1993) 11 tranches inc. 6 tranches inc. 6 tranches 9 then 15 plus (Frontier round) 117 blocks 66 blocks extension 3 14 (1992/1993) 484 128 110 6 then 12 then 182 15 (1994) 81 34 29 6 then 12 then 182 16 (1994/1995) 164 82 79 6 then 12 then 182 17 (1996/1997) 68 tranches inc. 28 tranches inc. 25 tranches inc. 3 then 6 then 275 blocks 127 blocks 114 blocks 15 plus 242 18 (1998) 602 82 78 6 then 12 plus 18 19 (2000/2001) 44 12 12 6 then 12 plus 18 Notes: 1. In the 7th round, a specified area of the Northern North Sea was offered, with 80 other blocks. 2. Licence continues only if development approval imminent. 3. Acreage retained in extension period dependent on wells drilled, e.g., 2 wells drilled, 50% of acreage retained. Source: Department of Trade and Industry (annual) 'Development of the oil and gas resources of the United Kingdom', The Stationery Office, London.

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initial period, after which, they can be renewed but with some proportion surrendered. By 2000, there had been 19 completed rounds. The licensing process has generally required an application fee, an initial payment on allocation of a block, followed by an annual rental payment, with a royalty on any production. In 1964, the first production licences for oil and gas for the British sector were awarded in a process that saw a huge amount of offshore territory allocated. About a thousand blocks (defined by lines of latitude and longitude), each of about 250square kilometres, were offered and about 350 allocated. A second round a year later saw even more blocks on offer (1102), but with a much lower allocation rate (127). These large rounds were to get some momentum for exploration activity in an unknown area. Most of the blocks were in the Southern Basin and licences were only issued to UK citizens who were resident in the UK, or to UK corporate bodies. These rounds resulted in the discovery in October 1965 of the West Sole field by BP, followed within a year by the Viking field (Conoco/ National Coal Board), the huge Leman Bank field (Shell/Esso), Indefatigable (Amoco/Gas Council) and Hewitt (ARCO). These fields had supplied nearly half the cumulative gas production from the North Sea by 1998 with Leman Bank alone providing more than 20%. They are all dry gas fields in shallow waters, and are cheap and easy to operate compared with later Northern Basin fields. Typically, Southern Basin gas fields are in about 20-40 metres water depth, while early Northern Basin oil and gas fields were in about 120metres of water, rising in later fields to about 180metres. The oil fields now being developed in the Western Approaches are in water depths of up to 480 metres. The second round also led to the discovery in 1970 by BP of the largest North Sea oil field, the Forties field. By 1998, this field alone had supplied 15% of cumulative North Sea oil production. A gap in licensing rounds of about five years followed, after which (1970-72) a further two rounds saw about 600 blocks offered of which about 400 were taken up, with more attention this time being paid to the Northern Basin. This was triggered in part by the discovery of the large Ekofisk field in the Central North Sea in December 1969 in the Norwegian sector, close to the boundary with the British sector. The first oil discoveries in the Northern North Sea resulted, of which the most important was Brent in 1971 by Shell/Esso (11% of cumulative oil production to end 1998). The major Morecambe gas field, the first find in the Irish Sea, was discovered in 1974 by a subsidiary of British Gas, Hydrocarbons Resources Ltd. By 1975, all the major oil and gas fields that had been discovered were a result

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of these first four licensing rounds, including two large fields in the Northern North Sea, Statfjord (oil) and Frigg (gas) that straddle the boundary with Norway. Another five-year gap in licensing was followed by two more rounds (1976-79) in which 117 blocks were offered, of which 97 were taken up. In 1976, the Government created the British National Oil Corporation (BNOC) intended to become a fully integrated national oil company. BNOC was given the National Coal Board subsidiary NCB (Exploration) Ltd. that had a 50% share in the Viking gas field. On the gas side, the existence of the British Gas Corporation (BGC) meant there was no need to create a new company to take a comparable position in gas. BNOC and the BGC were allowed to apply for production licences at any time and BNOC took a 51% equity stake (unless BGC was involved) in all licences and in some cases was the operator. BNOC and BGC were given first refusal on any licence interest being disposed of. The Government announced its intention for subsequent rounds to be more frequent and for relatively small numbers of blocks, reflecting a desire to regulate activity at a reasonably manageable and stable rate. The election of the Conservative Thatcher Government, replacing the previous Labour Party regime, saw a change in focus. For the Seventh Round, companies were able to select their own blocks within a defined area of the Northern North Sea, subject to a higher than normal initial licence payment, and new areas of deeper water were included to get experience in these extreme conditions. BNOC no longer took a mandatory majority share in new licences but had the option to negotiate up to 51% of petroleum produced from new licences. In 1981, proposals were published to dispose of BNOC's oil-producing business to the private sector, that would leave BNOC as an oil trader based on its 51% shares in production. The production business was transferred to a new company, Britoil, which was then privatised. BNOC was finally abolished in 1985. The only major new area discovered after 1975 was West of Scotland, with the first commercial discoveries in 1992 and 1993 by BP-Amoco. These oil fields are in very deep water (more than 400metres) and have required state-of-the-art technology to bring them into production. No major gas finds in this area have been reported yet. 8.3.3. Gas council and British Gas procurement policies- 1965-77

The first five fields to enter production, Hewitt, Indefatigable, Leman, Viking and West Sole were discovered in 1965-66 and started

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Table 8.5. UK gas production, billion cubic metres (number of fields).

1970 1975 1980 1985 1990 1995 1998 2000

Southern BasinI

Northern Basin2

Irish Sea

Onshore 3

Total

11.1 (3) 36.3 (6) 29.5 (6) 27.3 (10) 34.5 (24) 31.8 (47) 38.5 (56) 43.4 (63)

0 0 7.8 (3) 15.5 (11) 10.1 (15) 32.3 (42) 44.6 (44) 55.9 (48)

0 0 0 0.09 (1) 4.8 (1) 10.1 (2) 11.6 (3) 15.2 (4)

0 0 0 0.01 0.05 0.3 0.3 0.7

11.1 (3) 36.3 (6) 37.3 (8) 42.9 (22) 49.5 (40) 74.5 (91) 95.1 (104) 115.0 (115)

Notes: 1Southern Basin production excludes the output of the Markham (from 1992) and Windermere (from 1997) fields, all of which is exported to the Netherlands. 2Northern Basin production includes only the 'British' part of the output of Murchison and Frigg. Much of the output of the Northern Basin is delivered through four pipelines. These are the Central Area Transmission System (CATS) serving 13 fields, the Far-north Liquids and Associated Gas System (FLAGS) serving 9 fields, the Scottish Area Gas Evacuation system (SAGE) serving 10 fields and the Fulmar pipeline serving 12 fields. gin 1998, there were 7 onshore gas fields in production. Source: Department of Trade and Industry (annual) 'Development of the oil and gas resources of the United Kingdom', The Stationery Office, London.

p r o d u c i n g in 1967-72 (Table 8.5). Gas f r o m these fields w a s b o u g h t ashore at three n e w terminals, Bacton, T h e d d l e t h o r p e , a n d Easington, w i t h Bacton receiving the gas f r o m the m a i n fields. By 1985, these five fields still p r o v i d e d nearly 60% of UK gas production. In 1998, they w e r e all in decline a n d p r o d u c e d less than 10% of U K gas production. The Gas Council h a d m o n o p s o n y rights f r o m N o r t h Sea gas fields. The relevant UK G o v e r n m e n t minister h a d right of veto over i m p o r t s or exports of gas. The UK w a s therefore the only possible m a r k e t for gas f r o m the British sector of the N o r t h Sea. Given the Gas Council's m o n o p o l y position, the i m p r o b a b i l i t y of exports of gas being allowed, e v e n if m a r k e t s existed, a n d the low p r o d u c t i o n cost of these fields, it w a s in a strong position to contract for supplies from these fields. The Gas Council w a s able to contract for the o u t p u t of the early large S o u t h e r n Basin fields soon after their d i s c o v e r y at v e r y low prices. This a l l o w e d rapid d e v e l o p m e n t of the S o u t h e r n Basin. The next major decision in 1974 w a s the contract to b u y gas f r o m the Frigg field. The Frigg field is c o m p a r a b l e in resource scale to L e m a n a n d entered p r o d u c t i o n in 1977 (Table 8.6). It is the only major d r y gas field in the UK N o r t h e r n Basin to h a v e been exploited a n d the pipeline from it to a n e w gas terminal in Scotland, St Fergus, a l l o w e d gas from two other m e d i u m sized fields, Tartan a n d Piper to

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Table 8.6. UK gas trade (million cubic metres) -imports.

1970 1975 19801 1985 1990 1995 1997

Algeria

Norway2

Exports3

Net Imports 4

916 921 842 -

10069 13805 7491 1825 1319

1054 2033

916 921 10911 13805 7491 771 --714

Notes: 1Data for 1985 onwards are converted from million therms assuming I million therms are 2.75 million cubic metres. 2Imports from Norway are the Norwegian output of the Frigg gas field (61%, start-up 1978) and the Murchison oil field (22%, start-up 1980), which straddle the border between the countries. 3Exports are the output of the Markham (from 1992) and Windermere (from 1997) fields to the Netherlands and supplies to the Republic of Ireland (from 1996). 4No data on volumes of gas trade have been published after the opening of the Interconnector. Source: Department of Trade and Industry (annual) 'Digest of UK Energy Statistics' The Stationery Office, London. be landed. While just over 60% of Frigg's o u t p u t is d e e m e d to be N o r w e g i a n , British Gas negotiated that the gas w o u l d all be l a n d e d in the UK. Gas f r o m Frigg a c c o u n t e d for nearly all the gas i m p o r t s until the o p e n i n g of the Interconnector in 1998. While associated gas w a s f o u n d w i t h all central a n d n o r t h e r n N o r t h Sea oil finds, for s o m e time it w a s not clear w h e t h e r a n y field other t h a n Brent w o u l d p r o d u c e sufficient gas to justify a pipeline to bring the gas ashore. In 1975, construction w a s started on a gas pipeline c o m p l e t e d in 1982, k n o w n as FLAGS (Far-north Liquids a n d Associated Gas System) f r o m the Brent field, but also n o w serving eight other fields. The Frigg, S o u t h e r n Basin a n d Brent contracts m e a n t that British Gas h a d little n e e d to w o r r y a b o u t major n e w supplies for several years forward. In the event, gas f r o m Brent b e g a n to be delivered several years later than p l a n n e d . The final resource of significance at that time w a s M o r e c a m b e Bay in the Irish Sea. Gas p r o d u c t i o n a n d c o n s u m p t i o n increased r a p i d l y a n d reached a p l a t e a u w i t h i n a b o u t five years of first gas supplies arriving, w i t h g r o w t h in the residential m a r k e t m a t c h e d by decline in the industrial market. The r a p i d g r o w t h of N o r t h Sea p r o d u c t i o n w a s s u p p l e m e n t e d by i m p o r t s of liquefied n a t u r a l gas (LNG) f r o m Algeria, a l t h o u g h these w e r e p h a s e d out by the mid-1980s.

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8.3.4. British Gas procurement policies- 1977-86 By 1977, British Gas was beginning to plan its options for gas supplies as the early discoveries began to be depleted, especially how to exploit the associated gas from Northern Basin oil fields. Its strategies began to bring it into conflict with Thatcher's Conservative government, elected in 1979. British Gas's plans to increase its supplies were vetoed on two occasions by government decisions that seemed to favour private sector oil and gas companies. The bargaining position of British Gas for the Northern Basin of the North Sea was very different to that for the Southern Basin. The Northern Basin is primarily an oil province and, prior to exploration, it would not be known what would be the nature of any finds - oil, gas, or condensate. Production in the Northern Basin is much more challenging than the Southern Basin being in deep hostile waters. Exploration and production in this area has frequently been at the technological limit. Apart from Frigg, gas finds have been in the form of condensates or in association with oil. In these circumstances, gas discovery and production are often driven by conditions in the oil market. Discovery and production of gas were therefore somewhat insulated from gas market conditions and more difficult to regulate, and gas finds continued even when there was no immediate market for the gas. Investigations into a gas-gathering pipeline for the Northern Basin fields were begun by British Gas in 1977, but no decision was taken. In 1980, British Gas was under pressure to meet demand, a situation exacerbated by the late completion of the FLAGS pipeline. It accelerated development of its Morecambe Bay field and began to look at gas fields in the Norwegian sector of the North Sea. The gas-gathering pipeline was an ambitious project which would collect gas from fields along a North-South line over more than 400 kilometres, landing the gas at St Fergus. The plan appeared to have been accepted by government in 1980 and British Gas completed its proposal in 1981. But this was rejected in 1982, in favour of a more piece-meal approach led by the oil companies apparently because there was insufficient private sector participation. Much of the gas that this pipeline was meant to bring ashore was, in the event, supplied using spare capacity in pipelines built by the oil companies. It was not until 1986 that gas from other oil fields began to come ashore at St Fergus via the Fulmar pipeline, serving 12 fields. The Central Area Transmission System (CATS) was completed in 1993 serving 13 fields and landing at a new terminal at Teesside. Scottish

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Area Gas Evacuation (SAGE) followed in 1996 serving 10 fields and landing at St Fergus. In the early 1980s, British Gas was also negotiating to buy the Norwegian part of the gas output of Statfjord, an oil field in the Northern Basin on the border between UK and Norway, but N o r w a y chose to bring the gas ashore in Norway. Soon after, British Gas began negotiations with N o r w a y to buy some of the gas output of the Sleipner gas field. Agreement was reached between the companies in 1984, but the UK government vetoed the plan in 1985. The 1982 Oil & Gas Enterprise Act was passed by the first Thatcher Government and should be seen as part of that government's programme to open up monopolies and remove the privileges nationalised industries enjoyed. It contained three main provisions of relevance to British Gas: 9 It removed British Gas's right to buy all gas produced in the North Sea; 9 It allowed private companies to sell their output to large final consumers, using British Gas's network; 9 It required British Gas to dispose of their interests in six North Sea oil fields to private companies. British Gas was also required under the terms of an earlier Act to dispose of its interest in an onshore oilfield. Private suppliers wishing to use the British Gas network had, in the first instance, to negotiate with British Gas and if these negotiations failed, the Secretary of State could impose a settlement. However, these provisions did not lead to any significant opening of the market. It was the easing of the gas supply position from the North Sea that allowed production and sales of gas to begin to rise again slowly.

8.4. The development of demand In the decade 1965-75, the gas industry was transformed from a regionally based, relatively high-cost industry selling gas manufactured from coal, to a modern, national industry selling natural gas. 4 The pre-existing 'town gas' infrastructure was of major assistance in 4During the early 1960s liquid natural gas deliveries from Algeria began and this was turned into town gas. Also gas-making from naphtha was introduced. The role of coal in the gas industry was already diminishing by the time natural gas was discovered in the North Sea, but the process was certainly speeded up and the switch from town to natural gas became inevitable.

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Table 8.7. Statistics for the Gas Industry- 1966-86. Consumers Year

million

65/66 70/71 75/76 80/81 85/86

12.9 13.4 13.9 15.5 16.8

Sales (m therms)

Turn- ProfitI Employees 2 over Domestic Industrial Commercial Total (s (s (thousand) 2005 3653 5941 8380 10047

928 1704 6072 5859 5915

551 776 1441 2147 2739

3484 6133 13454 16386 18701

529 695 1581 4295 7687

11 106 197 381 688

121.7 116.3 101.7 106.0 89.7

Notes: 1profits for different years are not strictly comparable. For 1965/66, the figure shown is described as the 'surplus', for 1970/71 and 1975/76 the profit shown is the 'historical cost operating profit', and for 1980/81 and 1985/86, it is the 'current cost operating profit'. 2Employees numbers are as at the end of the financial year. Source: British Gas Annual Report and Accounts. a l l o w i n g this transformation, as a high p r o p o r t i o n of u r b a n h o u s e holds w a s a l r e a d y connected to the gas n e t w o r k . 5 Nevertheless, British Gas h a d to u n d e r t a k e a h u g e e n g i n e e r i n g p r o g r a m m e to convert existing appliances to use n a t u r a l gas a n d f r o m 1970 to 1975, a b o u t 2 million c o n s u m e r s per year w e r e c o n v e r t e d f r o m t o w n gas to n a t u r a l gas. The regional s y s t e m s also h a d to be connected via a h i g h - p r e s s u r e n e t w o r k bringing gas f r o m the N o r t h Sea b e a c h h e a d s to d e m a n d centres. Table 8.7 illustrates the i n d u s t r y t r a n s f o r m a t i o n d u r i n g the t w e n t y years from the d i s c o v e r y of n a t u r a l gas to the p r i v a t i s a t i o n of British Gas. Sales of gas increased m o r e t h a n five-fold. While e m p l o y m e n t declined slowly, p r o d u c t i v i t y per employee, e x p r e s s e d as v o l u m e of gas sold per e m p l o y e e , over the 20-year period increased by a factor of seven. Despite h u g e i n v e s t m e n t r e q u i r e m e n t s , a n d the write-off of often quite n e w gas m a n u f a c t u r i n g plant, the i n d u s t r y r e m a i n e d profitable. Sales to the industrial sector increased r a p i d l y at first, b u t by 1974-75 they reached a plateau. British Gas focussed on the less pricesensitive residential a n d c o m m e r c i a l sectors, w h i c h c o n t i n u e d to g r o w strongly. Gas sales for b u l k heat p r o d u c t i o n in furnaces a n d boilers w e r e u n d e r t a k e n m a i n l y as a w a y to balance s u p p l y a n d d e m a n d t h r o u g h sales u n d e r 'interruptible' contracts. At p e a k d e m a n d times in winter, these supplies could be i n t e r r u p t e d to e n s u r e sufficient gas could be delivered to the residential sector. Supplies to p o w e r stations 5In 1965/66, 12.3 million households were connected to the gas network, compared with 17.1 million household consumers then connected to the electricity grid and 16.5 million residential consumers connected to the gas network by 1998.

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Table 8.8. Price of household energy. Year

Gas

1965/66 1970/71 1975/76 1980/81 1985/86

10.6 10.6 14.3 24.2 42.7

p/therm Electric Coal 22.6 24.6 49.0 112.0 160.4

4.2 6.1 12.1 28.3 42.3

Income (s

Gas/Electric

Gas/Coal

Gas/Income

1019 1383 3000 5682 8141

0.47 0.43 0.29 0.22 0.27

2.52 1.74 1.18 0.86 1.01

100 73.4 45.8 40.9 50.5

Notes: 1. The gas, electricity and coal prices quoted are the average net selling value in pence per therm to residential consumers in Great Britain. For electricity, the figures refer to the calendar year; e.g., 1970/71 refers to calendar 1970, while gas figures refer to the fiscal year. The coal figure is the typical price for house coal in London for December. 2. The income shown is the average income per household after taxes and benefits and the ration of gas price to income is an index number with 1965/66 = 100. Source: Digest of UK Energy (various), HMSO. w e r e m a d e available in the late 1960s o n a small scale to test the b u r n i n g qualities of n a t u r a l gas. H o w e v e r , b u l k sales w e r e not u n d e r t a k e n , m u c h to the a n n o y a n c e of the m a i n g e n e r a t i n g c o m p a n y , the Central Electricity G e n e r a t i n g Board. 6 This de facto b a n on use of gas in p o w e r stations w a s reinforced b y the E u r o p e a n C o m m u n i t y ' s decision in 1974 to b a n n a t u r a l gas use in p o w e r g e n e r a t i o n that w e r e not t h e n b u r n i n g gas. Gas' r a p i d e n t r y into the residential m a r k e t w a s assisted b y t w o factors (Table 8.8). In 1965, o w n e r s h i p of central h e a t i n g in Britain w a s at a l o w level a n d this w a s a m a r k e t that w a s ideally suited to gas. By 1979, a b o u t 10 million British h o u s e h o l d s (52%) h a d central heating, of which, a b o u t 60% w e r e gas-fired. A b o u t 80% of n e w central h e a t i n g installations w e r e gas-fired. 7 The i m p r o v e d s t a n d a r d of c o m f o r t b r o u g h t large w e l f a r e gains to the p o p u l a t i o n . The s e c o n d factor w a s the price relative to other e n e r g y sources for h o u s e h o l d s . The price of gas h a l v e d , relative to the prices of h o u s e coal a n d electricity b e t w e e n 1970 a n d 1980. The price of gas also rose m u c h m o r e s l o w l y t h a n incomes. O n the d e m a n d side, f r o m 1975 to 1985, British Gas c o n s o l i d a t e d its p o s i t i o n as the d o m i n a n t e n e r g y source for h o u s e h o l d s (Table 8.9). It r e p l a c e d coal, off-peak electricity a n d p e t r o l e u m ,

6The CEGB commented 'It is invidious that natural gas cannot be purchased direct from producers and that the Board have to rely on a supply controlled by their major competitor in the energy field' CEGB (1971) 'Annual report and accounts, 1970-1' CEGB, London, p. 34. 7British Gas (1980) Annual Report and Accounts 1979-80, HMSO, London.

National Reforms in European Gas

178 Table 8.9.

Residential energy use in the U K - 1965-2001 (million therms).

Natural Gas Town Gas Electricity Solid Fuels Petroleum Total

1965

1970

1975

1980

1985

1990

0 1869 1953 9697 969 14488

627 2915 2625 7137 1335 14639

5396 495 3045 4343 1434 14731

8420 19 2939 3313 1093 15784

9682 . 3010 3030 974 16696

10250 . . 3200 1822 989 16261

1995

1998

1 1 1 2 5 12142 . . 3488 3739 1134 890 1189 1407 16936 18269

2001 12937 3935 922 1393 19296

Source: Digest of UK Energy (various), HMSO.

in the space heating market and competed strongly against electricity for cooking and water heating.

8.5. Privatisation

In May 1985, the Secretary of State for Energy, Peter Walker, announced the privatisation of British Gas. There was some urgency to the process, as the proposed privatisation of British Airways (BA) had been delayed. The Treasury had included the expected proceeds of the BA flotation in its revenue projections and a replacement privatisation was needed. There was some pressure within the Conservative Party from free market enthusiasts for the company to be split up into competing fragments. However, others in the party wanted to see British Gas retained as a powerful company so that it could be a strong force in international markets. After a long and determined battle by British Gas, led by its Chairman, Sir Dennis Rooke, the pressure to split the company up was successfully resisted. Like British Telecom (BT) in 1984, the company was to be privatised with no restructuring. However, unlike BT, where an attempt to introduce competition was made through the promotion of a private sector competitor, Mercury, the Government relied on the oil companies and the provisions of the Oil & Gas Enterprise Act to bring in competition. While the Minister's statement did speak of competition for all consumers, the privatisation prospectus stated that the company would have a monopoly of customers using less than 25,000 therms for 25 years. Few envisaged that small consumers could be given choice, and competition for them was not seriously contemplated until 1993. Privatisation was seen by some in British Gas management as a positive development. British Gas seemed likely to retain strategic control over the gas market, but would be freed of the government 'interference' that had characterised its relationship with the Conservative government of Thatcher. The Labour Party opposed

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privatisation of British Gas, but this had no impact on the government's plans. British Gas did not conform to the stereotype of an inefficient, lossmaking nationalised company. It had a fund of good-will from the successful transformation of the British gas industry and from the consumer benefits that exploitation of Britain's natural gas had brought. There would have been strong opposition to the destruction of a successful company. Most people probably expected that it would be 'business-as-usual' with British Gas. Many were also looking forward to the likelihood that shares would be offered to the public at well below market value bringing windfall gains to those lucky enough to be allocated shares. The appointment of a regulator to set prices, the Director General of Gas Supply, James McKinnon, assisted by the Office of Gas Supply (Ofgas) excited little comment. As might be expected for such a momentous change, commentators on all sides found things to criticise in the government's proposals. After a famous advertising television campaign, 'Tell Sid', the shares were sold in November 1986 raising s for the British Treasury, making it then the largest privatisation undertaken by the British government. The share subscription was oversubscribed by a factor of four and the shares, sold for s immediately rose on the first day of trading to s Sir Dennis Rooke stayed on as Chairman until his retirement in 1989. 8.6. C o n c l u s i o n s

By the time Thatcher's Conservative government was elected, the North Sea oil and gas province was mature and all the major fields had been found. Her Government's decisions on resources were much more to do with 'tuning' supply than with developing a resource. The exploitation of the resource was under the control of government through nationally owned companies and a strict system of licensing. The OSO provided a framework for ensuring that a high proportion of the work arising from exploitation of the North Sea came to British companies. The overall structure was comparable to that which largely remains in place in Norway, with the obvious difference that the British gas resources were ear-marked for the British economy while the Norwegian gas resources, necessarily, were for export. It would have been hard to argue at that time that this arrangement had not served Britain well. British Gas had gained immense prestige from the way it had brought natural gas to the market efficiently and with huge welfare benefits. Ownership and control of the resources at a time when the public was still acutely aware of the vulnerability of

180

National Reforms in European Gas

international fuel markets seemed no more than good sense. The British economy was fragile despite the income from oil and gas with inflation and unemployment beginning to rise and the industrial opportunities afforded by the North Sea were a welcome. Breaking the power of British Gas and relinquishing control of the resources would not have appeared a prudent policy. It is clear that the Conservative government was not following any master plan in its various conflicts with British Gas from 1980 onwards, culminating in its privatisation. The main force was a dislike of the power of large nationally owned companies had and a belief in the effectiveness of discipline that private ownership puts on companies. The large oil companies had their own agenda, wishing to wrest control of resources in the North Sea away from British Gas. The vetoing of the gas-gathering Pipeline and the Sleipner deal, and the removal of the British Gas monopsony all served the interests of the oil companies well. The actual decision to privatise British Gas was clearly largely driven by a need for government r e v e n u e - as events have subsequently demonstrated, creating a de facto private sector monopoly made no sense in any other terms. Ideas on creating a gas market were barely formed. During the period up to privatisation, the world context for gas resources evolved significantly. The extent of world gas reserves was becoming clearer and huge gas resources from Algeria, Russia, and Norway appeared increasingly viable as supply sources for Europe. Fossil fuel markets seemed much more secure and the limited impact of the Iranian revolution showed that the power of OPEC was much reduced. The old ideas about gas as a limited and special resource were ripe for reappraisal. Literature

National Coal Board, (1974) Plan for Coal, National Coal Board, London. Central Electricity Generating Board (CEGB),(1971) Annual report and accounts, 1970-1 CEGB, London. British Gas, (1980) Annual Report and Accounts 1979-80, HMSO, London.

Chapter 9 Gas as a Commodity. The U K Gas Market: From Nationalism to the Embrace of the Free Market STEVE THOMAS

9.1. Introduction

In 2000, 30 years after the discovery of gas in the British North Sea, British gas production was more than double the levels that applied through the 1970s and 1980s. Yet reserves, which for more than 20 years only appeared to be adequate for 10 more years may be sufficient for more than a decade even at this higher level of consumption. British Gas, the nationally owned company that masterminded the development of the resource for 15 years, has been privatised and dismantled. Gas is no longer reserved for premium markets and now competes with oil and coal in bulk heat-raising applications, including power generation. In 1998, Britain ceased to be a 'gas island' when two-way trade in large quantities of natural gas between Britain and mainland Europe began. This chapter examines the political, technical and economic factors that have underpinned the transformation since 1986 of the British gas resource from one firmly controlled by the state to one determined largely in competitive markets. Despite the emergence of a competitive industry structure, British Gas and its daughter companies still continue to dominate much of the industry. The history since privatisation falls into three periods: 1986-93, following British Gas' privatisation when it still controlled the market but a series of inquiries and concerted regulatory activity put in place measures to break up its market dominance and take away its strategic role; 181

182

National Reforms in European Gas

9 1994-96, when preparations for the introduction of competition in the residential market were made, British Gas had to make internal changes to separate the monopoly businesses from the competitive businesses and when its retail business ran into serious difficulties caused by over-purchasing of gas and the collapse of the wholesale gas price; 9 1997 onwards, when competition for all end-consumers was introduced, the separated retail arm of British Gas, Centrica, was struggling for survival and Britain's status as a 'gas island' was ended with the completion of a large pipeline for trade with mainland Europe.

9.2. 1986-93: Continued Dominance by British Gas

9.2.1. Regulation Under the 1982 Oil and Gas Enterprise Act's provisions consumers using more than 25,000 therms per year (most industrial and larger commercial users) were to have choice of gas supplier. British Gas was required to allow new gas retail suppliers access to the gas network at non-discriminatory prices. For British Gas' captive consumers the retail price was to be set using a mixture of market prices and R P I - X . For the monopoly elements of the bill, use of the natural gas network, prices were allowed to rise by the rate of inflation (Retail Price Index or RPI) minus an incentive term, 'X'. This formula (RPI-X) means that the income for each unit of gas transported that the operator of a monopoly network can earn must fall in real terms by X per cent each year. The government set X at 2 for a period of at least the first five years. For monopoly consumers, British Gas was allowed to pass through its gas purchase cost. Regulation, including price setting for monopoly activities (setting the X factor), was carried out by a new regulator, the Director General of Gas Supply (DGGS), assisted by his staff at the Office of Gas Supply (Ofgas). 1 In the event that the DGGS and British Gas could not agree on the formula, the matter would be resolved by the Monopolies and Mergers Commission (MMC) 2 whose decision was expected to be

1In 1999, the Office of Gas Supply was merged with the Office of Electricity Regulation to form the Office of Gas and Electricity Markets (Ofgem). In 2000, a panel of five executive directors known as the Gas and Electricity Markets Authority replaced the Directors General of Gas and Electricity. 2In 1998, the Monopolies and Mergers Commission was renamed the Competition Commission. In this chapter, this body is referred to as the MMC.

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binding. The MMC also had a role in more general issues of competition. If there were suspicions that markets were not operating as they should, the regulator could request, or the minister overseeing matters could require the MMC to make a broadly based investigation. The MMC would submit its report to the minister who has some discretion over the implementation of these recommendations. An MMC inquiry can be lengthy and disruptive, and the recommendations of the MMC could be radical, for example, they might recommend the break-up of a company. A referral to the MMC was therefore not a course that any company would choose lightly. The DGGS was required to promote competition, a duty that he took more seriously than many expected when the position was created. The budget for Ofgas in 1987-88, the first year in which the organisation was fully active was s m and it employed 21 people. McKinnon expected that a staff of 30 would be sufficient. Nearly all the initial Ofgas employees were drawn from the Department of Energy. This meant they did not initially have sufficient knowledge of the gas industry for the job. McKinnon later acknowledged that it took more than two years for Ofgas to have the skills to begin to regulate British Gas effectively. 3 In 1999, gas and electricity regulation were merged. Ofgas was merged with the equivalent body for the electricity industry, the Office of Electricity Regulation (Offer) to form the Office of Gas and Electricity Markets (Ofgem) with the DGGS appointed to be the Director General of Electricity Supplies (DGES). In 2001, the singleperson regulator was replaced by the Gas and Electricity Markets Authority, a body with five executive and five non-executive directors with the DGGS/DGES as managing director. 9.2.2. Pressure for competition in retail gas supply

By mid-1987, British Gas was attracting bad publicity. Its first year's profits were s m, 46% up on the previous year despite a reduction in turnover. This caused anger with the public, unhappy at being exploited by what it saw as a private monopoly. At the same time, McKinnon was becoming increasingly frustrated at the reluctance of British Gas to supply him with the information he felt was needed to allow price regulation. A long and bitter battle was fought between British Gas and Ofgas, with Ofgas taking powers to acquire the information it felt it needed.

3Ofgas (1991) 'Ofgas Annual Report, 1990', HMSO, London.

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National Reforms in European Gas

But, it was a large industrial customer, Sheffield Forgemasters, which caused more serious problems to British Gas by complaining about the gas price it had to pay. This complaint, made a year after British Gas was privatised, was taken up by the Office of Fair Trading (OFF), the government body that looks after consumers' interests in markets. The OFT referred it to the MMC, which carried out an investigation into British Gas pricing policies. The emergence of these price issues and the growing unease about the creation of privately owned companies with strong monopoly powers were major factors in the decision by the Conservative Party to promise, in its 1987 election manifesto, that the electricity industry would not be privatised intact. The MMC report was published in October 1988, and in January 1989, the government approved its major proposals, which were meant to remove British Gas' dominance of the industrial gas market. 4 The MMC proposed that British Gas should: 9 Publish price schedules for large consumers; 9 Not price discriminate between customers or on the use the gas was to be put to; 9 Contract for no more than 90% of the output of the UK continental shelf (the so-called '90/10 undertaking'); 9 Publish clearer information on the costs competitors would pay to use its network. The OFT was required in July 1991 to start a review of progress towards introducing competition in the gas contract market, with the expectation that if a competitive gas market had not emerged, the government would restructure the gas industry. By preventing British Gas from targeting particular markets, and pricing according to the use the gas was put to, these provisions effectively ended the status of gas as a 'premium' fuel. The requirement to publish price schedules for consumers using more than 25,000 therms annually led to an averaging of prices in this sector, with many of the British Gas' largest consumers angry at losing out. There was resentment within British Gas that this would hamstring against its competitors, who could pick and choose their customers and price their contracts individually.

4Monopolies and Mergers Commission (1988) 'Gas: a report on the matter of the existence or possible existence of a monopoly situation in relation to the supply in Great Britain of gas through pipes to persons other than tariff customers', Cm 500, HMSO, London.

Gas as a Commodity. The UK Gas Market

185

There was mixed success for these measures. Ofgas seemed satisfied that the new third party access arrangements along with arrangements for back-up supplies, would allow access to the system to entrants. It also felt able to announce that, from March 1990, competition in the industrial and commercial sector had opened. However, it acknowledged that because British Gas controlled such a large proportion of gas contracted from the North Sea, it would not be until 1993, when the removal of British Gas' monopsony powers could begin to have an effect that anything approaching a real market could exist. Over the period 1989-1993, 36 new gas fields were contracted for, but only nine went to British Gas, the other 27 being split amongst 18 different companies. 5 In order to introduce competition in the industrial gas market, Ofgas asked British Gas to release sufficient gas to competitors to allow them to acquire 30% of the firm contract market by October 1993. British Gas did this by 'swapping' gas, supplying competitors with gas to be repaid with new supplies later. The incentive for British Gas to cooperate with this scheme was a hint that it would be allowed to withdraw its price schedules for this market. 9.2.3. The market for gas in power generation

The liberalisation of the British electricity generation market and the lifting in 1989 of the European Union ban on burning gas in power stations created a new gas market. Entrants to the generation market and the two large, privatised generation companies were keen to order new gas-fired plants. In the two years to mid-1991, 10GW of new gas-fired capacity was ordered. The 'dash for gas' was possible because of a spate of gas discoveries in the North Sea that sprang from changes in the tax and licensing regime in the late 1980s. These changes were meant to counteract the disincentive to invest that the collapse of the oil price in 1986 produced. The 'dash for gas' had a dramatic impact on British Gas, its emerging competitors and on exploitation of the North Sea. The oil companies saw the power station market as a way to expand their direct gas sales. It provided the long-term contracts, volume and predictable prices that were necessary to make the risk of developing new fields tolerable. The MMC's requirement that 10% of gas from

5M. Parker and J. Surrey (1994) 'UK gas policy: Regulated monopoly or managed competition?' Steep Special Report 2, SPRU, Brighton, p. 38.

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National Reforms in European Gas

the UKCS should go to companies other than British Gas was easily met. British Gas saw power generation as a good market. Its longterm interruptible (LTI) contracts were attractive to electricity distribution companies, which saw owning a gas generation plant as a way to reduce the dominance of the two large generation companies and to expand their businesses into an unregulated area. It was priced at levels (about 16 p/therm) believed to be below beach-head prices for new gas contracts then being signed, leading to suspicions, voiced by the Regulator, that British Gas was indulging in predatory pricing. The electricity distribution companies were quick to see this apparent bargain. But, interest was so great that by March 1991, British Gas felt obliged, in order to maintain supply security, to raise the interruptible gas price by 35% to choke off demand only five months after LTI2 had been launched. Disputes over the withdrawal of these terms arose between British Gas and potential customers. British Gas settled these disputes and effectively withdrew from this market.

9.2.4. The monopoly prices Ofgas' other line of attack on British Gas was on the monopoly business. In 1990, Ofgas announced it was beginning a review of the X factor. In spring 1991, Ofgas published its proposals, which increased the X factor to 5, introduced an incentive to ensure British Gas purchased gas as cheaply as possible and included a small surcharge on bills to pay for energy efficiency measures. The gas purchase incentives allowed British Gas to recover its forecast gas purchase costs, minus 1 per cent. British Gas protested that the X factor was too tough and tried to negotiate it down. However, mindful of the risks of challenging the formula, which could have led to another damaging MMC inquiry and also of the damage it could do to the verdict of the OFT review, in April 1991, it accepted them for implementation from April 1992. The review introduced two important changes of practice. First, the regulatory formula was to apply for five years, rather than being open-ended. Second, the calculations behind the X factor were made explicitly on rate-of-return grounds rather than in the way incentive regulation was expected to work. Much of the negotiation was around the appropriate rate of return to be allowed and on the valuation of existing assets. A lower rate of return, 4.5% real, was allowed on existing assets, than on new investment (7%).

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187

9.2.5. Competition and restructuring The 1991 OFF Report was a further blow to British Gas. 6 It concluded that British Gas had broadly complied with undertakings given to the MMC, but that these undertakings had been ineffective in encouraging self-sustaining competition. A particular problem was that the new p o w e r station market for gas, not envisaged in the 1988 MMC Report, had allowed British Gas to meet the 90/10 undertaking without opening up the general industrial and commercial market. It concluded that further remedies were required if competition was to develop more strongly. It r e c o m m e n d e d that a m u c h larger volume of gas be released (sold not swapped) to competitors; the threshold for the competitive market be reduced from 25,000 to 2,500 therms per year; competition for residential consumers be introduced; and British Gas' gas trading and transportation activities be separated. The Trade and Industry Minister, Peter Lilley, endorsed these recommendations. British Gas agreed to them and, in a consultation d o c u m e n t in February 1992, promised to release sufficient gas to enable competitors to take 60% of the industrial interruptible and firm gas market, and reduced the competition threshold to 2,500 therms per year. 7 The OFF report also concluded that a further reference to the MMC was justified, but that the reference should be delayed to see what undertakings British Gas might voluntarily make to the Minister. British Gas was alarmed by the combined effect all these provisions w o u l d have on the viability of its business. In July 1992, at the instigation of British Gas, the MMC was commissioned to carry out an investigation of the gas market u n d e r the 1973 Fair Trading Act, and, at the instigation of Ofgas, it was commissioned to carry out a narrower investigation on the issue of transportation and storage. The two reports were published a year later and the government's decisions were a n n o u n c e d in December 1993. 8 The MMC reports m u s t be taken together, as m a n y of the arguments

6Office of Fair Trading (1991) 'The Gas Review', HMSO, London. 7In 1994, there were about 300,000 consumers using more than 2,500 therms per year. 8Monopolies and Mergers Commission (1993) 'Gas: Volume 1 of reports under the Fair Trading Act 1973 on the supply within Great Britain of gas through pipes to tariff and non-tariff customers, and the supply within Great Britain of the conveyance or storage of gas by public gas suppliers', Cm 2314, HMSO, London and, Monopolies and Mergers Commission (1993) 'British Gas plc: Volume 1 of reports under the Gas Act 1986 on the conveyance and storage of gas and the fixing of tariffs for the supply of gas by British Gas plc', Cm 2315, HMSO, London.

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were common. It r e c o m m e n d e d that: 9 The threshold for competition be reduced to 1,500 therms by March 31, 1997; 9 The X factor be reduced from 5 to 4 to compensate British Gas for the loss of profit resulting from the lower competition threshold; 9 British Gas' trading business should become a separate subsidiary and fully divested from the transmission business by March 31, 1997; 9 British Gas' market share limit should be 55% of the market above 2,500 therms rather than 40% of the market above 25,000 therms. The Secretary of State, Michael Heseltine broadly a p p r o v e d these measures, but required only an internal separation of the trading business from transportation and storage. He a n n o u n c e d a timetable for the introduction of competition for residential consumers starting with 5% of the residential market in April 1996, completing the process within two years. Ofgas was required to make some detailed decisions, including the X f a c t o r - it a p p r o v e d the reduction to 4 - and to w o r k out the details of h o w the market opening for the residential sector w o u l d be carried out. One consolation for British Gas m a n a g e r s was that McKinnon 9 came to the end of his period of office in N o v e m b e r 1993, and was replaced by Claire Spottiswoode. During this period, the structure of British Gas was in transition (Table 9.1). In 1989, it was split internally into three divisions, the largest was Gas Business in Great Britain. Exploration & Production (E&P) was an international business that by 1990 was active in eighteen countries. The Global Gas business was intended to acquire interests in overseas gas transmission and distribution businesses. The increase in competition and the impact of the small reduction in prices for m o n o p o l y services u n d e r the regulatory formula m e a n t that the UK Gas Business declined in real terms. 1~ Nevertheless, profitability

9The enmity between McKinnon and British Gas can be gauged from the tone of McKinnon's last Ofgas annual report. He states: "The message becomes clear by examining the gas supply business in Britain from 1986. Ofgas has made the running in terms of innovation and change and has forecast the onset of competition and has virtually set the agenda. British Gas has brushed aside all advice and warnings that action was needed. It now tries to blame others for the position into which it has voluntarily placed itself. This is the classic case of failure to bring about a change in monopoly." Office of Gas Supply (1993) 'Report of the Director General of Gas Supply for the period 1 January to 31 December 1992', p. 4, HMSO, London. 1~ trend is masked somewhat by variations in weather, for example, 1989-90 figures for UK Gas were significantly depressed by the very warm winter.

Table 9.1.

British G a s - 1986-96.

Turnover (s UK Gas E&P Global Gas Operating Profit (s UK Gas E&P Global Gas Pre-tax Profit (s Exceptional Charge (s Employment R&D (s

1985--86

1986-87

1987-88

1988-89

1989-90

7687 7593 94 . 706

7610 7421 189

7364 7140 224 . 1053

7526 7169 357

7983 7361 622

1120

1095

1078 42

946 149

1054

.

. 1001

1990-91

1991

1992

1993

1994

1995

1996

9491 8135 978 378 1249

10485 8626 980 879 1268

10254 8376 995 883 1103

10386 8202 1219 965 (310)

9698 7526 1161 1011 987

8601 6512 1268 821 583

9453 7081 1491 881 (182)

1051

917 264 68 1556

953 190 125 1469

753 213 137 846

(732) 260 162 (613)

579 289 119 (918)

291 441 (149) 617

(492) 555 (245) (237)

0

83

1138

55382 66

43106 54

.

r 731 (25) . 782

982 19 1062

1029 24 . 1008

0

0

0

0

0

0

0

320

1683

91876 76

88469 74

84587 77

81832 80

80481 75

81805 86

84540 90

84023 89

79358 80

.

.

.

69971 75

Notes: 1. Profits are calculated on a current cost accounting basis. 2. Employment is the average number of employees employed during the year in the UK and outside. 3. From 1991 onwards, the accounting year was changed to calendar year. There is therefore some overlap between the figures for 1990-91 and 1991. Source: Annual Report and Accounts.

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National Reforms in European Gas

would have been maintained throughout the period had it not been for exceptional charges of s m in 1992 and s m in 1993 most of which was to cover the costs of restructuring. The highly profitable E&P business grew strongly in the five years after privatisation and its profits were able to compensate for the stagnation of the UK business. The Global Gas business was somewhat less profitable. Its first major acquisition was Consumers' Gas of Canada, then the largest gas distribution company in Canada, in 1990 for s m. This was followed by smaller acquisitions in Spain and Argentina, but in 1993, British Gas decided to sell Consumers' Gas claiming that it was looking for more profitable investments in less regulated markets. Two other commitments that would prove to be important were made. In 1992, during the privatisation of the Northern Ireland electricity industry, British Gas bought the 1000MW Ballylumford power station. Part of the deal was that British Gas would build a gas pipeline to Northern Ireland from Scotland by 1996 and convert the station to gas. The pipeline would allow the introduction of natural gas to Northern Ireland using the disused town gas network. The second commitment, in 1992, was to take part in investigations into the construction of a gas pipeline from the UK to Belgium.

9.2.6. The gas industry in 1993 With hindsight, British Gas misjudged the impact of privatisation. It believed that the decision not to break it up meant that its monopoly powers would be left intact. It assumed that regulation would have little impact on its operations and it would retain its position as the strategic body controlling markets and exploitation of the UKCS. In the period up to privatisation, its battles had been with government ministers. After privatisation, it was at arm's length from the government bodies such as OFT, MMC and Ofgas that it came into conflict with. However, since government was the final arbiter on disputed issues, it must be assumed that ministers agreed with these decisions and the government's vision of the industry had changed since its privatisation. British Gas believed that they could successfully withhold information from Ofgas. How far the power taken by Ofgas can be attributed to the particular interpretation by McKinnon of his role, and how far it was an inevitable consequence of creating an independent regulatory body with a duty to promote competition is difficult to judge. While Spottiswoode still faced a British Gas company with most of its markets intact, much of the groundwork for

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191

the creation of competitive markets had been done. This included the information that McKinnon had forced British Gas to reveal, the internal split of British Gas into a monopoly transport and a competitive supply business, and the political backing for the extension of gas competition to all consumers. British Gas' dominance of supplies from the UKCS began to become a liability rather than a strength. It had contracted long-term for quantities of gas for markets it was likely to lose and at prices that then seemed very high. Its image with the public was beginning to suffer from bad publicity due to increases in directors' pay. 9.3. 1994-96: The Break-up of British Gas

Three processes dominated the period from 1994-96. The first was the opening of the market for gas consumers using more than 2,500 therms per year, and the preparations for the introduction of competition for residential consumers. The latter was scheduled to begin in 1996 and be completed by 1998. The second was the impact on British Gas of the collapse of the North Sea gas price and the emergence of a surplus in its contracted gas volumes. These developments left British Gas oversupplied with gas, purchased at prices that entrants could easily undercut: 'stranded contracts'. The third was the internal adjustments to British Gas necessary to comply with the requirements of the 1995 Gas Bill that its monopoly businesses be run separately from its competitive businesses. In 1996, the stranded cost problem and the strictness of the internal separation meant that British Gas felt obliged to make the split complete spinning off the trading division into a separate company. 9.3.1. The introduction of competition

By 1990, when electricity was privatised, it was clear that the gas privatisation structure was not appropriate if competition for final consumers was to be introduced. The electricity industry was privatised with competition in mind and as a result forged ahead of the gas industry in the introduction of competition. However, the announcement by the government in 1993 that competition for residential consumers would be progressively introduced beginning in 1996 and to be completed by April 1998 put gas in line with electricity in terms of competition. For electricity, medium-sized consumers were allowed to choose their supplier from 1994 onwards with the bulk of consumers planned to be given this choice in 1998. In the event, the 1998 opening for residential consumers started six

192

National Reforms in European Gas

months late and was not completed until mid-1999.11 By contrast, whatever other problems were encountered with gas, it stuck broadly to its timetable and all consumers had choice within a month of the date at which the roll-out of competition was scheduled to be completed. To some extent, introducing competition in gas markets is simpler than for electricity markets because metering requirements are much less stringent. Because electricity cannot be stored, electricity is priced on a half-hourly basis with the result that consumers' consumption must be measured (or estimated) for each half-hourly period if costs are to be correctly allocated. This vastly increases the data processing requirements. For gas, the relative ease of storage does mean that supply and demand need only be balanced on a daily basis and the metering problems are therefore much less severe. Nevertheless, supply and demand must balance and there must be precise arrangements to ensure that each supplier puts into the system the amount of gas its customers use. Also because of the risk that individual North Sea fields might suffer some technical problem, there must be arrangements for back-up supplies. One possible solution would have been to follow the example of electricity and de-integrate wholesale supply and retail demand, creating a field of competitors in both the wholesale and retail sectors. It would also have required the creation of daily trading arrangements equivalent to the electricity pool. However, British Gas was already in the midst of complicated restructuring to separate internally the monopoly business from the competitive businesses and this option was not chosen. A 'Network Code' was opted for, which was to be a series of contractual obligations to ensure that gas supply and demand would balance on a daily basis. It included arrangements for back-up supplies and penalties for failure to meet contractual obligations. Ofgas was charged with overseeing this process and its priority was to avoid deterring new competitors, a situation that might happen if too heavy financial burdens were placed on entrants before the market had developed more fully. The Network Code was implemented four months late in March 1996, but just in time to meet the 1993 target that residential competition should begin in April 1996. In the market for large consumers, British Gas was heavily constrained by measures imposed by Ofgas to promote a competitive market. These were based

11For an account of the problems encountered in 1994 and 1998, see D. Maclaine (1999). The electricity supply market, Financial Times Energy, London.

Gas as a Commodity. The UK Gas Market

193

on the recommendations of earlier MMC and OFF investigations. The main measures were: 9 Targets for maximum market shares for British Gas in various market sectors; 9 A requirement on British Gas to price according to published schedules; 9 A gas release programme under which British Gas was obliged to release gas to other shippers. By 1994, the target for British Gas was to reduce its market share in the over 2,500 therms market (about 40% of UK gas sales) to 55% during 1995. In January 1994, its share was 65%, and by the end of that year it had fallen to 48%. This allowed a relaxation in the requirements on British Gas to sell according to price schedules and went a long way to meeting the OFT target set in 1992 to reduce its market share in this sector to 40%. The requirement for price schedules made it easy for competitors to 'cherry-pick' British Gas' most profitable customers. In September 1994, Ofgas suspended the requirement for schedules for the above 25,000 therms firm gas market, initially for six months; in June 1995 for one year; by July 1996, British Gas' market share in the 2,500 therms market, excluding power generation, was only 29% and in 1996, Ofgas permanently removed the requirement to price according to schedules for the above 25,000 therms market. Ofgas had always seen the fact that British Gas had contracted all the gas supplies from the UKCS as the major obstacle to competition. "If there is no product available to competitors it is not possible to compete. ''12 The OFF report required British Gas to release gas to competitors for a period, at least until new fields could be developed. Initially, British Gas 'swapped' gas with new competitors requiring gas to be repaid later. This was seen as too restrictive and was replaced by an auction system up to 1995 with the volume released dictated by the market share requirements imposed by Ofgas. Gas was sold on a cost plus basis - the cost of purchase to British Gas plus an administration charge. This limited the extent to which new competitors could undercut British Gas, but by 1995, new competitors with independent access to gas were entering leading to the stranded contracts problem discussed in Section 9.3.2.

12Office of Gas Supply (1993), op cit, p. 5.

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194

9.3.2. The stranded contracts problem The stranded contracts problem became visible in 1995. There were two main factors behind it. First, there was a general overestimation of the British gas market by oil and gas companies. There was limited scope for alternative uses and markets for such gas and even quite a small excess could have a dramatic effect on the newly emerging spot price for gas, reducing it to less than 10 p / t h e r m , about half the level British Gas' LTI contracts were signed for. Second, there was the late completion of some power stations with contracts for gas from British Gas and also the Regulator's enforced loss of market share in the industrial and commercial markets. This left British Gas contracted, on take-or-pay terms, for more gas than it could immediately use. In 1995, it paid s for gas it could not immediately use and was forced to make provisions of s m for the lower price that it expected to receive when this gas could be sold. In 1996, the provisions for stranded contracts had risen to s m and the problem was far from solved then.

9.3.3. The splitting of British Gas In the 1994 accounts, it was clear that there would be major costs in restructuring the company, for which more than s bn provisions had already been made, but there was little sign that the fundamentals of the company were going wrong (Table 9.2). There were further Table 9.2. British G a s - 1994-96. Operating Profit (s

Turnover (s

Total Trading Transco E&P Others Intra group Trading to E&P Trading to Transco

1994

1995

1996

1994

1995

1996

9698 8238 3103 1161 1149 (3953) (773)

8601 7604 3126 1268 821 (4218) (892)

9453 8114 3444 1491 881 (4477)

987 (75) 631 288 143

583 (289) 580 441 (149)

(182) (1305) 813 555 (245)

(2816)

(2742)

Notes. 1. Profits are calculated on a current cost accounting basis. 2. Intra group transfers mainly represent payments from Trading to Transco for use of the network and to E&P for purchase of gas. Source: Annual Report and Accounts.

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exceptional charges of s m, made up of s m for clean up of sites where town gas had been manufactured and s for revaluation of property assets (Britain was then in the midst of a property price collapse). The E&P and the Global Gas divisions were increasingly profitable, although by then British Gas had decided to sell Consumers' Gas Company, then the mainstay of Global Gas, at a minimal profit only three years after acquiring it. 13 Its 53% holding in Bow Valley Energy of Canada acquired in 1988 and part of the E&P division was sold only a year later in 1995 for s m. It is not clear how far these decisions were strategic and how far they were designed to reduce borrowing. The main part of the business, UK Gas, remained profitable. The Transco division was under strong economic pressure as a result of the much tougher regulatory formula (reflected in the job cuts), but profits were high for a low risk monopoly business. While UK Trading was making a loss, given that Transco and E&P were profitable, and nearly all Transco's business and a large proportion of E&P's business were with UK Trading, this might have been seen as just a problem of misallocation of costs. The sale of assets in Canada reduced overseas activities, although there was investment in gas in Argentina and, in 1995, construction of the pipeline to Northern Ireland was started. British Gas also moved into the electricity business in partnership with a privatised Scottish power company, Scottish Hydroelectric, to build a 755 MW gas-fired power station, Seabank. In 1994, Trading was split into four divisions, Public Gas Supply (supply to franchise consumers), Business Gas (supply in the competitive market), Servicing (appliance installation and servicing) and Retail (shops selling domestic equipment). This split was removed in 1995 when the Business and Public Gas divisions were recombined. Adding to British Gas' difficulties Chief Executive Officer, Cedric Brown, had become the focus of public disgust at the rewards senior executives of privatised utilities were awarding themselves. Of course, the pay of the CEO had a negligible impact on the price consumers paid for gas. However, the public saw these rewards as an indication that the privatised companies, which they saw as essentially monopolies, were being run for the benefit of senior executives and shareholders. The public believed that Brown was doing essentially the same job as Dennis Rooke before privatisation, probably not as

13Bythen, British Gas had already sold 15% of its shares in Consumers' Gas Company.

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well, but for a b o u t s m per year, seven times the salary p a i d to Rooke. The profit he could m a k e from the s h a r e options he held could be expected to m o r e than d o u b l e his salary. At a time w h e n s o m e e m p l o y e e s of British Gas w e r e forced to accept pay-cuts, this r e p r e s e n t e d a public relations disaster for British Gas. Even the Prime Minister, John Major, b r a n d e d t h e m 'distasteful' a n d B r o w n felt obliged to w a i v e the right to b u y some of the shares d u e to him. In D e c e m b e r 1996, the decision w a s taken to split the c o m p a n y into t w o parts a n d in F e b r u a r y 1997, the t w o c o m p a n i e s w e r e formally d e m e r g e d . The first company, k n o w n as BG plc w a s based a r o u n d the Transco division, w h i c h o p e r a t e d the pipeline network. I n c l u d e d in this w a s a part of the E&P business, a n d the Global, Generation, a n d Pipeline Integrity Businesses. The Transco business w a s highly profitable m a s k i n g the relatively p o o r p e r f o r m a n c e of the other parts of BG. In overseas markets, BG w a s a l l o w e d to continue to trade as British Gas. The second, Centrica, w a s based a r o u n d British Gas Trading (BGT) including the Service a n d Retail businesses (Table 9.3). BGT w a s a h e a v y loss-maker and to give the c o m p a n y s o m e chance of survival, Table 9.3. BritishGas - 1995-96. Turnover (s

Operating Profit (s

1995

1996

1995

1996

Continuing Operations (BG Group) Total Transco E&P International Downstream Other Intra group transfers

3864 3126 405 215

4383 3444 591 257

304 580 (116) (85)

554 813 (44) (7)

304 (186)

199 (108)

(75)

(225)

Discontinued Operations (Centrica) Total Gas Sales Services Retail Other

7827 6935 413 177 302

8550 7496 452 175 427

279 n/a n/a n/a n/a

(736) (408) (291) (70) (33)

Notes: 1. In 1994, there were exceptional charges of s m comprising s m for the clean-up of old town gas sites and s arising from the revaluation of property. Source: Annual Report and Accounts.

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197

E&P's highly profitable Morecambe Bay fields were included in the group. This accounts for the reduction in turnover of the E&P in the old breakdown of activities from s m in the old structure (with large profits) to only s m (with small losses) in the BG accounts. This split and the retention by both companies of the British Gas and BG names continues to cause confusion and four years later few people in Britain were aware that there were now two entirely separate companies trading under the same or similar names. However, it is an interesting comment on the continuing prestige of the British Gas name that both companies are still keen to associate themselves with it. 9.4. 1997 Onwards: A Competitive Gas Market? From 1997 onwards, two processes have dominated gas policy in the UK. The first has been the emergence of the daughter companies of British Gas, BG plc and Centrica, as separate companies, followed by a further split in October 2000 with the flotation of a UK gas regulated business, Lattice. The second factor has been the opening of the residential market for competition and the emergence of competitors to British Gas in the gas supply business. As in the rest of the period since privatisation of British Gas, considerations of reserves and strategic resource development have seldom achieved a high profile. Despite consumption doubling in the last 10 years, using the latest estimate of maximum reserves, UKCS gas supplies will last for a maximum of a further 15 years at the current rate of consumption. The completion of the Interconnector, a gas pipeline to Belgium, capable of carrying about a quarter of Britain's gas consumption and which ends Britain's status as a gas island, has excited little public policy debate. 9.4.1. BG Group and Lattice

While BG was initially a much stronger company than Centrica, it faced important strategic decisions. Income from its mainland UK business seemed likely to decline as regulatory pressure reduced income from monopoly activities and the regulator identified new areas of its business that could be opened to competition (Table 9.4). This pressure culminated in a decision in March 2000 to separate its regulated UK activities, primarily the network and metering, from its international competitive business. The new regulated company, Lattice, was demerged in November 2000, but its existence as an independent company was a short one. In April 2002, it announced

198

National Reforms in European Gas Table 9.4.

Financial results for BG p l c - 1996-99 (s

Turnover Transco BG Storage E&P International Downstream Other Intragroup sales Operating Profit Transco BG Storage E&P International Downstream Other Pre-tax Profit Exceptional Charges Employment

1996

1997

1998

1999

4383 3324 192 591 257

4300 3071 172 710 261

4474 3032 157 823 393

4787

199 (180) 787 919 46 (24) 72

212 (126) 1201 1007 32 118 27

205 (136) 1570 1198 33 161 64

(226) (295) 1138 22073

17 1235 0 19705

114 1227 0 18894

836

1591 1160 (8) 220

1202 0

Notes: 1. Profits are calculated on a modified historical cost basis. For 1997, BG paid s in Windfall tax. 2. Employment excludes discontinued operations, essentially Centrica and is the average number during the year. 3. From 1999 onwards, it is not possible to break d o w n activities into the same categories as previously except for E&P. Source: Annual Report and Accounts.

that it had agreed a merger with the UK electricity transmission company, National Grid Company. BG Group now describes itself as an 'integrated gas major', its main source of income being its exploration and production division (54% of turnover) and its transmission and distribution business (mainly non-UK pipelines) accounting for a third of turnover. In July 2001, it sold the strategically important Rough and Hornsea gas storage facilities to the US company Dynegy. This latest demerger and the sale of its main UK gas storage facilities mean that, for the UK downstream gas industry, BG Group has no more significance than any of the other competing oil and gas producers operating in the North Sea.

9.4.2. Transco In 1997, BG's main remaining monopoly was its operation of the pipeline system. In 1995, investigations by Ofgas into the new regulatory

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199

formula for gas transportation and metering began and Ofgas' final proposals for the transportation business were published in November 1996. These involved a one-off cut in real terms in the income from transportation in April 1997 of 20%, followed in the four subsequent years by annual reductions of 2.5%. This amounted over the five years to a reduction of income of 28%, equivalent to an X factor of 5, but with early benefits to consumers. BG rejected the Ofgas proposals opting for an MMC inquiry. In 1998, the MMC gave its verdict, largely upholding the Ofgas proposals. It increased the one-off cut to 21% retrospectively imposed for April 1 1997, but reduced the subsequent X to 2 for the following four years. The continued use of the RPI-X formula was in line with confirmation in a government review of regulatory policy that RPI-X was to be retained as the basis of utility regulation. 14 However, the MMC report confirmed what had been clear for some time, that the difference between incentive regulation and rate of return regulation was one of presentation not substance. The arguments centred less on the value of X and the one-off cut, and more on the value of assets in the BG asset base and the rate of return that was appropriate. The price control was calculated to allow a 7% real return on the value of the asset base as of March 31, 1997. This asset base was to be re-valued each year by the addition of net investment less depreciation. In 1999, the Regulator required Transco to fully open the metering business fully to competition. From April 1999, gas suppliers were free to provide, install and maintain gas meters to all consumers and avoid the Transco fixed charge of s per year. The scope for further large reductions in prices was exhausted by the 1997 settlement and for the period April 1, 2002-07, Ofgem required much less severe reductions. Prices must be reduced by 4% in April 2002 followed by reductions of 2% in each of the following four years. 15 This reduction was driven mainly by a target to reduce operating costs by 3.6% per year (17% in total). There was also a reduction on the allowed rate of return to 6.25% for its networks although for metering this remained at 7% to reflect the extra risk in this business introduced by competition. Lattice faces further fragmentation in the next few years because of the requirement by

14Department of Trade and Industry (1998) 'A fair deal for consumers: Modernising the framework for utility regulation- the response to consultation' Department of Trade and Industry, London. 15Ofgem (2001) 'Transco price control 2002-2007: Final proposals' Ofgem, London.

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National Reforms in European Gas

Ofgem to divide its network into 12 Local Distribution Zones (LDZ) and a National Transmission System (NTS) to produce a structure analogous to that for electricity. The NTS accounts for about 16% of its income, the 12 LDZs for 70% and metering for 14%. It is expected that these NTS, each of the LDZs and the metering business would eventually come under separate ownership.

9.4.3. BG storage One area of BG's business to be opened to competition was the storage market. Britain has three main types of storage facilities. The depleted Rough field is the largest, being capable of supplying 10% of peak demand for two months. The Hornsea salt caverns in Yorkshire have a much smaller capacity but a much more rapid response time making them suitable for short-term storage. The third is the five LNG stores, which are also responsive but contain only five days capacity at maximum demand. Up to 1997, income from this was regulated using the transportation formula, but in 1997, BG sold this capacity for fixed periods under terms dictated by it. Ofgas was uncomfortable with the market power this gave the BG and in 1999 began a process of auctioning capacity at the main sites to cover several years forward. In the October 2000 demerger, BG Storage remained with the BG Group, but in July 2001, it sold the division to the US company, Dynegy. As a result of financial difficulties, Dynegy put these facilities up for sale again and in September 2002, Scottish & Southern Electricity bought the Hornsea facility and in November 2002, Centrica bought the Rough complex.

9.4.4. Centrica When Centrica was created in 1997, a cursory glance at its balance sheet made it difficult to see how it could survive as the Energy Supply business made a loss of s in 1997 (Table 9.5). This loss had been turned into a profit of s in 1998. However, these figures include exceptional charges (mainly to cover the stranded contracts) and profits from the Morecambe field that disguise the underlying position. Exceptional charges allocated to Energy Supply were s m in 1997 and s m in 1998. The Morecambe Field, through the Hydrocarbon Resources Limited (HRL) subsidiary, is counted as part of the Energy Supply business and made an operating profit of s m in 1997 and s m in 1998. If the exceptional charges and the Morecambe profits are removed from the Energy Supply profit/loss figures, the underlying loss on this business was s in 1997 and

Gas as a Commodity. The UK Gas Market

201

Table 9.5. Financial results for Centrica - 1997-2000 (s

Turnover Energy supply (UK) Energy supply (USA) Services Retail Telecoms Other Operating profit Energy supply (UK) Energy supply (USA) Services Retail Telecom Other Pre-tax profit Exceptional charges Employment

1997

1998

1999

2000

7842 7192 467 183 (660) (339) (82) (47) (623) 835 15423

7481 6784 526 169 2 214 248 4 (31) (7) 167 211 16427

7217 6386 730 83 18 428 461 8 (25) (16) 268 136 19600

9933 8390 267 1211 1 64 522 544 8 60 (49) (24) 438 14 28305

Notes: 1. Profits are calculated on a modified historical cost basis. 2. Centrica paid s (included in exceptional items) in Windfall Tax in 1997, included in exceptional charges. Source: Annual Report and Accounts.

s in 1998. F i g u r e s for 1999 a n d 2000 c o n f i r m t h e t r e n d of a s t r o n g i m p r o v e m e n t in t h e t r a d i n g p o s i t i o n . T h e first p r i o r i t y for C e n t r i c a w a s t h e r e f o r e to r e n e g o t i a t e its p o r t f o l i o of gas c o n t r a c t s so t h a t it c o u l d c o m p e t e effectively w i t h e n t r a n t s into t h e gas retail s u p p l y b u s i n e s s , w h o w e r e n o t s a d d l e d w i t h historic h i g h cost contracts. In 1996, the C e n t r i c a d i v i s i o n of British G a s h a d a l r e a d y b e e n c h a r g e d p r o v i s i o n s for losses of s m o n t h e s e c o n t r a c t s to a d d to t h e s t h a t British G a s h a d m a d e c h a r g e d to its a c c o u n t s in 1995. In 1997 a n d 1998, f u r t h e r s u m s of s and s w e r e c h a r g e d to C e n t r i c a ' s a c c o u n t s a g a i n s t e x p e c t e d losses. T h e o v e r a l l c h a r g e for the s t r a n d e d c o n t r a c t s to C e n t r i c a a n d British G a s s h a r e h o l d e r s , a c c o r d i n g to the a c c o u n t s , h a d t h e r e f o r e b e e n in excess of s to date. S o m e relief w a s p r o v i d e d b y t h e g o v e r n m e n t , w h i c h r e m o v e d a tax o n old gas fields, w h i c h in 1996 a n d 1997 h a d cost C e n t r i c a a n a v e r a g e of a b o u t s T h e s e w e r e n o t t h e o n l y e x c e p t i o n a l c h a r g e s f a c e d b y Centrica. D e s p i t e t h e v a s t s u m s p a i d u p to 1996 b y British G a s for r e s t r u c t u r i n g , further charges were incurred totalling s m in t h e p e r i o d 1996-98. In 1997 a n d 1998, it also h a d to p a y s to t h e n e w L a b o u r

202

National Reforms in European Gas

government under its Windfall Tax. By 1998, it was clear that the stranded contracts problem was under control allowing Centrica to begin to think more strategically about the development of its business. The servicing business, which has been expanded to include the AA road-side recovery business (see below) and financial services as well as installing and maintaining gas equipment, is now profitable and is probably a useful means of increasing consumer loyalty. Those with British Gas service contracts can be confident that in the event of equipment problems, British Gas will respond quickly to ensure that their space and water heating needs are met. Customers may value this reassurance higher than saving money on gas bills. The retail business is a hangover from pre-privatisation days when British Gas ran chains of retail appliance stores where gas bills could be paid and contact made with British Gas. This facility to pay gas bills no longer exists. Centrica struggled to make these shops competitive, but in 1999, it finally gave up and closed them all down. It has begun to reinforce its gas resource base buying Powergen's North Sea gas resources in 1999 as well as other reserves in the North Sea. It is beginning to develop overseas businesses partly through trade using the gas Interconnector to Belgium and through partnerships with utilities, for example in the Netherlands. A taste of the longer-term strategy that Centrica might follow came with the launch of the Goldfish credit card in 1996. This suggested a future for Centrica in providing a basket of household products and services, some network delivered, such as gas and electricity and others not, such as financial services. Centrica has two overwhelming assets in fulfilling this aim. First, it has the British Gas name which still draws loyalty from residential consumers and second it has the largest customer base of any utility company. It still has ready access to nearly 15 million consumers, a formidable base from which to sell a range of household services. Centrica reinforced its customer base by buying the main roadside vehicle recovery organisation, the Automobile Association (AA), an organisation with more than 10 million members, in 1999 for s In early 2000, it decided to move into telecoms. By September 2000, it was offering fixed, mobile and Internet services under the British Gas brand name with partners providing the telecoms infrastructure. In the longer term, moves into water supply and other financial services have also been proposed. However, its most important move in developing a basket of household consumer products and services has been in the electricity

Gas as a Commodity. The UK Gas Market

203

sector. It has been the most aggressive competitor in the residential electricity market since its opening in September 1998, and by the end of June 2002, it had 5.6 million consumers buying a package of gas and electricity. This made it one of the largest electricity retail companies in Britain. However, the market share in electricity supply was only won at significant cost and its accounts showed that Centrica had lost s in the first two years after market opening in order to win its first 2.6 million consumers. To support the electricity business, it has begun to buy electricity generation capacity, including ownership or part ownership of two large gas-fired power stations.

9.4.5. The introduction of competition The 1995 Gas Act provided for three different licensed actors in the gas supply chain. These were: public gas transporters, in this case Transco; gas shippers, essentially gas wholesalers; and gas suppliers, the companies that retail gas to final consumers. This brought the structure into line with that imposed on the electricity industry in 1990 and was intended to facilitate competition for small consumers. The costs of introducing competition, inevitably borne by consumers, were high, and by 1998, Transco alone had spent s on the computer system to handle the data needs created by the introduction of competition. 16 This figure does not include the costs incurred by other companies, such as Centrica. In comparison, for electricity, about s m will be passed on to consumers to cover the cost of developing the computer software and running it for five years. 17 The introduction of competition for small consumers required a large public education programme to inform consumers about how it was possible to buy gas from a different company without changing the meter and without new pipeline work. Competition was introduced in April 1996 in an area of Southwest Britain with 500,000 consumers. Competition was extended to 2 million consumers in February and March 1997, then in further

16House of Commons Trade and Industry Select Committee (1998) 'Progress in the Liberalisation of the Gas Market' Memorandum submitted by the Office of Gas Supply', Second Report, HC 338, HMSO, London. 17House of Commons Trade and Industry Select Committee (1998) 'Developments in the Liberalisation of the Domestic Electricity Market' Memorandum submitted by the Office of Electricity Regulation, Tenth Report, HC 871, HMSO, London.

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National Reforms in European Gas

tranches at about six monthly intervals until the programme was complete in May 1998. The majority of consumers did not receive choice until fairly late in the process with 80% of the market only opening up in the last seven months of the programme. The initial opening excited considerable media interest, a large field of new competitors, and an expectation that the large discounts on offer would lead to a collapse of British Gas' market share. British Gas had yet to clear up the stranded contracts problem and its competitors were able to buy gas at up to 50% less than British Gas. Discounts of up to 20% were on offer meaning that a typical consumer could expect to save around s per year. Eleven competitors to British Gas were initially licensed to supply gas to residential consumers. Privatised electricity companies (regional electricity companies or RECs) dominated the field, often in partnership with oil companies. Particularly in their own territories, the RECs felt they had a brand name that consumers trusted and consumers would assume there would be scale and practical benefits from buying their energy from just one company. Competing to supply gas was also a useful way of defending their market share for electricity when residential electricity competition was introduced. Within a year, all 12 England and Wales RECs and both of the vertically integrated Scottish electricity companies were offering gas to residential consumers. Gas competition had leapt ahead of electricity competition, which was not expected to begin until April 1998 with a strong expectation of slippage even then. This allowed the electricity companies to take a share of the gas market from British Gas with no scope for British Gas to move into electricity. British Gas was not allowed to reduce its prices on a regional basis to counter its competitors until Ofgas was satisfied that competition was well-established. Although this decision understandably annoyed British Gas, it made some sense in competition terms. Despite its weakened state, British Gas could probably have directed the savings from renegotiating its stranded cost contracts to the competitive markets and deterred many potential competitors. A shakeout in the market is already underway. The oil companies, Amoco, Texaco, Phillips and Total have all been bought out by their REC partners, while Shell, BP and Exxon have shown no interest in entering this market. For reasons unrelated to the gas market, all 14 of the electricity retail supply businesses in Britain had been taken over by the five emerging integrated electricity companies by mid-2002. It is not clear why consumers seem so reluctant to move away from British Gas and what this means for the future of competition. There is

Gas as a Commodity. The UK Gas Market

205

probably no single explanation but a n u m b e r of factors have probably contributed: 9 The strong brand image of British Gas and a reluctance to switch a w a y from a tried and tested supplier for such a vital commodity; 9 Bad publicity from the door-step selling tactics adopted in the trial areas; 9 Distrust of the headline advertising claims of competitors and a fear that short-term savings will be recovered in higher costs longer term; 18 9 A belief that British Gas w o u l d have to match the prices offered by competitors; 9 Lack of interest from entrants in less attractive parts of the residential market, such as pre-payment meter customers and customers in disadvantaged areas; and 9 Lack of time or interest amongst consumers in finding out which supplier is cheapest and doing the necessary paperwork. Whatever the reasons, it n o w appears unlikely that most small consumers will shop around aggressively and regularly for the cheapest gas supplier. Consumers will remain loyal to the incumbent supplier, especially one with as strong a b r a n d - n a m e as British Gas. This presents a difficult challenge to regulators. If residential consumers are not mobile, suppliers will tend to treat them as captive or semi-captive and will tend to load costs on to them rather than on to more mobile sectors of the market. The poorest consumers have so far received meagre benefits from competition, a problem that is occupying the g o v e r n m e n t and the Regulator, with no solution in sight. 9.4.6. The Interconnector

The Interconnector is a 235-km pipeline r u n n i n g from Bacton, one of the East Coast gas terminals, to Zeebrugge in Belgium. It has a diameter of 40 inches (just over one metre) and a capacity of 20 billion cubic metres per a n n u m (additional compression could raise the capacity further), equivalent to about a quarter of current UK gas consumption. The first serious proposal to build an Interconnector

18The Regulator is also guilty of making misleading claims for the impact of competition. In the 1998 Annual Report, he notes that a customer could save 20% in 1996 by switching from BGT's standard credit terms to a competitor on Direct Debit terms without noting that much of this saving could have been made simply by switching from standard credit to Direct Debit with British Gas.

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National Reforms in European Gas

from Britain to Belgium was proposed by the UK Energy Minister in 1992. The natural assumption for many would have been that it was intended to be a net importer of natural gas into Britain as gas reserves began to run down and consumption continued to grow. However, a 'gas bubble' from the North Sea was already being anticipated and these proposals envisaged it as an export-only line. A company, Interconnector (UK) Ltd, was set up in 1994 with nine shareholders led by BG (Table 9.6) and, in 1996, construction work was started. The capacity of compressors was only such as to allow it to run at about 40% of its export capacity if the flow of gas is reversed, i.e., importing from Belgium. 19 Once the 'bubble' had been drawn down, it was expected that, as UK gas reserves were depleted, the flow wo~ld reverse, and, in about 10 years, the pipeline would be a major importer of gas to the UK. The Interconnector was completed and commissioned in October 1998 at a cost of about s m. By then, the shareholding structure had changed a little, with BG reducing its stake from 40% to 25% in late 1997 and early 1998. Once construction was underway, the owners began to sublet their capacity and by the time the Interconnector was commissioned, at least 8 b c m / y e a r of its capacity had been contracted, all of which was to export gas from Britain. Competition for the Interconnector is emerging using pipelines to depleted gas such as the Frigg gas field. This field has connections to both Norway and the UK, and in July 2001, Statoil agreed to supply BP with Norwegian gas starting deliveries in October 2002. In the Southern Basin, there are a number of largely depleted gas fields in the UK sector close to Dutch fields. The under-utilised pipeline capacity in this area could also be readily adapted to provide an interconnection to the Netherlands. Gas connections to Norway and the Netherlands, especially if matched by electricity connections, give rise to some intriguing possibilities with these two countries emerging as energy 'hubs'. For example, Norway could export gas to Britain for conversion to electricity and re-export it as electricity to Norway (generating electricity from gas in Norway may be difficult to reconcile with greenhouse gas emission targets). This would allow Norway to retain water in its dams, using them mainly at peak demand times to export power to Europe taking advantage of the high prices available. Similarly, the vast Dutch gas storage capacity could be used to store gas for release at peak demand times for use by

19Reversing the flow would take up to three days to reach full capacity.

207

Gas as a Commodity. The UK Gas Market

Table 9.6. Shareholders in UK Interconnector Ltd and Shippers. Shareholding (%) Company BG BP Conoco Elf Gazprom Distrigas Ruhrgas Amerada Hess National Power Snam International

Capacity (bcm/year)

1994

1998

1994

40 10 10 10 10 5 5 5 5 0

25 10 10 10 10 10 10 5 5 5

8.0 2.0 2.0 2.0 2.0 1.0 1.0 0.25

1.0 1.0 0

a

Notes:

aCapacity not known. Source: Petroleum Economist, October 1998, vol. 65, no. 10, p. 12. final consumers and for power generation, again taking advantage of high peak gas and electricity prices.

9.5. Future Issues 9.5.1. Resources

For the 15 years of UKCS gas exploitation until privatisation, policy was driven by resource m a n a g e m e n t considerations. Resource depletion was controlled and British Gas' m o n o p s o n y p o w e r allowed it to b u y gas cheaply, ensuring that m u c h of the 'rent' from North Sea gas was captured by British consumers. However, by the mid-1980s, perceptions were beginning to change. The second oil crisis had proved short-lived, world trade and gas reserves were growing and UK reserves were not running out as quickly as predicted. Driven by the privatisation p r o g r a m m e of the Thatcher government, private ownership and markets rather than national planning were increasingly seen as a more efficient w a y of resource management. Since then, UK consumption has increased by two-thirds, production has more than doubled, yet prices have halved and reserves are still healthy. The European market for natural gas has also g r o w n markedly, fuelled to a great extent by imports from Russia and Algeria. Despite fears about their political instability, these two countries have proved reliable suppliers. The Gulf War in 1991 had little impact on world fuel markets.

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Given this background, it is not surprising that little public attention is now paid to resource depletion. However, the North Sea is now a mature oil and gas province and future discoveries will increasingly be small and in hostile waters. Existing production is now in small dry gas fields that have only a short life, or as associated gas, where production levels are difficult to predict and are driven by the need to maximise oil production. A steep decline in UK gas production could occur that would force Britain to import large quantities of gas from mainland Europe. The completion of the Interconnector now means that Britain can no longer be insulated from European market conditions. The potential for disruptions to this market from instability in Algeria and Russia will exist until supplies are diversified either by new pipelines to the Middle East or LNG supplies from the world market. From an economic point of view, depletion of UK energy resources could have significant consequences. Oil reserves are uncertain, and at present rates of production and with current reserves estimates, they could last between 7-20 years. While it is commonly believed that coal reserves in Britain are huge, the amount of coal that can be recovered economically is limited and deep-mined coal production is now very small. Oil and gas production provide about a quarter of a million jobs and contribute about 2% of GDP as well as contributing strongly to the UK's trade balance. Provided prices in world energy markets are low, the decline in UK oil and gas production is not steep, and Britain's export competitiveness remains strong, the impact of depletion of the UK's oil, gas and coal may cause few problems. Any risks and economic consequences incurred could be seen as being more than counterbalanced by the benefits that market forces can bring.

9.5.2. Competition and regulation The liberalisation of the British gas market suffered from a lack of clarity in the objectives for privatisation. Many in the Conservative government seem to have believed that simply changing from public to private ownership would be sufficient to bring major improvements to the efficiency of the gas sector. As a result, the old structure was allowed to continue with no firm plans to break up its monopoly position. The regulatory bodies, OFT, MMC, but especially Ofgas were left, by default, with the job of creating a competitive structure. Unlike the other two institutions, Ofgas was a new body and, understandably, took some time to establish itself, although the decision to draw its entire staff from the civil service probably only served to

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delay the point at which it was fully effective. In its last year of operation, Ofgas before merging with Offer in 1999, spent nearly s more than ten times the 1987-88 budget. Its staff level had increased to 150, seven times that employed in 1987-88 and five times the number James McKinnon thought would be sufficient. 2~ The apparently new form of regulation, incentive regulation, via the RPI-X formula has proved to be no more than rate-of-return regulation in a new guise. There are incentives for improvements in static efficiency. However, it is now clear that the heart of the regulatory process is an assessment of the investment needs, the appropriate rate of return the monopoly company should be allowed to make, accompanied by monitoring of the actual investments made. After privatisation in 1986, the attention of politicians engaged in energy policy issues was concentrated on the privatisation of the electricity industry, completed in 1990. It was not until 1992 that government ministers became actively involved in setting policy for the gas industry. This was with the decision that competition was to be extended to residential consumers and that the competitive and monopoly businesses of British Gas should be separated. The then minister, Michael Heseltine, known for his wish to create strong British companies to compete in world markets, went against the recommendation of the MMC that the two parts of British Gas should be completely split and allowed the separation to be internal. However, the financial condition of British Gas became so poor that a full split was necessary to ensure the survival of the heart of the business. The process of introducing competition for large consumers had little to do with new companies seizing a competitive opportunity. It had more to do with policies imposed by regulatory bodies requiring British Gas to give up markets and supply gas to its competitors. For small consumers where a de facto policy of forcing people not to buy from British Gas would not have been acceptable, the stranded gas contracts left the prices offered by British Gas apparently hopelessly uncompetitive. Despite this, British Gas still has a strong hold on the residential market. The 12 regional electricity companies have all tried to enter this market, but only one or two has had much success. The largest oil companies, which might have chosen to integrate vertically from gas production into gas supply to residential consumers, have been absent supplying only

2~

(1999) 'Ofgas Annual Report, 1998', The Stationery Office, London.

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large consumers. Relatively few competitors may survive the 'shakeout' of the market in the residential sector that is now under way. No major new suppliers have come forward that are not electricity supply or oil companies. Estimating the benefits from liberalisation is difficult. In his 1998 annual report, the Regulator gave figures that showed the real price of gas to residential consumers had fallen by 25% in the period from December 1987 to December 1998. 21 But, this begs the question, of what prices would have been had British Gas not been privatised. If British Gas had reduced its non-gas costs at a rate of 2% a year, its costs would have fallen by a little over 20% in that time. In fact, during this period the costs allowed for monopoly services have come under increasing pressure. If the X factors that have been imposed on monopoly costs are accumulated, the price of the monopoly part of the bill has fallen by about 40% since privatisation. In this period, the average gas price also fell in real terms. In 1987, the average price of gas at beachhead delivery points was 0.90 p / k W h in 1998 prices. This compares to an average price of 0 . 5 6 p / k W h in 1998, a 38% fall, and a spot price of about 0.35 p / k W h , a 60% fall. The average price still reflects the high cost of some stranded contracts and, while the spot price is volatile, it may be a better indicator of the cost of gas for new contracts. How far this fall was due to liberalisation of the UK market and how far it was due to a drop in the international market price of gas (or other factors) is not clear. However, it does appear that regulation, especially from 1993 onwards, has been far more effective at bringing cost savings to consumers than competition. The rent from the steep reduction in gas prices seems to have gone to British Gas shareholders, especially in the 6-8 years after privatisation and to oil companies that held contracts for above market prices. This parallels experience with electricity where, despite heavy falls in fossil fuel prices, the price reductions that consumers have seen are largely the result of regulatory action. 22

9.5.3. Corporate changes For much of the period since privatisation, the dominance of British Gas has meant that the gas sector has seen little change at corporate

21Ofgas (1999) op cit. 228. Thomas (1999) 'Has privatisation reduced the cost of power in Britain?' UNISON, London.

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level. Oil companies have begun to integrate vertically into gas supply, but only for large consumers and they still retain their dominance of gas exploration and production. However, as gas increasingly dominates electricity generation and supply competition is extended to residential consumers, the electricity and gas industries are increasingly converging at both the wholesale and retail ends. For electricity, it appears likely that the market will become dominated by a handful of companies integrated into generation and supply to final consumers. These companies will be large consumers of gas and will probably see scope to use their gas purchasing power to establish gas retail businesses. Winning final consumers for gas may also be relatively easy through 'dual fuel' offers, which sell electricity and gas as a package. For the monopoly business, the basic nature of the business, operating and maintaining a complex network infrastructure is little different to operating an electricity or water network and there may be scope for companies to integrate horizontally into other sectors. Literature Department of Trade and Industry, (1998) A fair deal for consumers: Modernising the framework for utility regulation- the response to consultation, Department of Trade and Industry, London. House of Commons Trade and Industry Select Committee, (1998) Progress in the Liberalisation of the Gas Market' Memorandum submitted by the Office of Gas Supply, Second Report, HC 338, HMSO, London. House of Commons Trade and Industry Select Committee, (1998) Developments in the Liberalisation of the Domestic Electricity Market, Memorandum submitted by the Office of Electricity Regulation, Tenth Report, HC 871, HMSO, London. Monopolies and Mergers Commission, (1988) Gas: a report on the matter of the existence or possible existence of a monopoly situation in relation to the supply in Great Britain of gas through pipes to persons other than tariff customers, Cm 500, HMSO, London. Monopolies and Mergers Commission, (1993) Gas: Volume 1 of reports under the Fair Trading Act 1973 on the supply within Great Britain of gas through pipes to tariff and non-tariff customers, and the supply within Great Britain of the conveyance or storage of gas by public gas suppliers, Cm 2314, HMSO, London. Monopolies and Mergers Commission, (1993) British Gas plc.: Volume 1 of reports under the Gas Act 1986 on the conveyance and storage of gas and the fixing of tariffs for the supply of gas by British Gas plc., Cm 2315, HMSO, London. Office of Fair Trading, (1991) The Gas Review, HMSO, London Office of Gas Supply, (1993) Report of the Director General of Gas Supply for the period 1 January to 31 December 1992, HMSO, London. Ofgas, (1991) Ofgas Annual Report, 1990, HMSO, London. Ofgas, (1999) Ofgas Annual Report 1998, The Stationery Office, London. Ofgem, (2001) Transco price control 2002-2007: Final proposals, Ofgem, London. Parker, M. and Surrey, J. (1994) UK gas policy: Regulated monopoly or managed competition? Steep Special Report 2, SPRU, Brighton.

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Chapter 10 The Transformation of the German Gas Supply Industry LUTZ MEZ

10.1. Introduction

The German gas industry consists of approximately 730 independent companies which operate at different supply levels. Only 10 companies are producers a n d / o r importers, annually selling 80 bcm gas to 16 supraregional gas utilities, and to approximately 710 regional and local distribution companies as well as to large industrial customers. Natural gas is the second largest energy source in Germany, and its market share will continue to increase. This chapter describes the historical development of the German gas industry, discusses current issues of importance in German gas policy, and outlines the industrial organisation and profiles of the major gas utilities. 10.2. Overview of the German Gas Industry

Natural gas ranks today as the second largest energy source in Germany, following oil (38.5%) and ahead of hard coal (13.1%) and lignite (11.2%). In 2001 natural gas consumption totalled 3,124 petajoules, i.e. about 80billionm 3 (bcm) or a 21.5% share of the total primary energy supply (see Fig. 10.1). According to forecasts, the market share of natural gas will continue to increase. Gas is mainly used for the heating market. The share of natural gas in electricity generation decreased slightly from 9.4% in 1999 to 8.9% in 2001 (DIW 2002, pp. 113-117).

10.2.1. History and development of the German gas industry For over 150 years, the gas industry in Germany was built around town gas or coke oven gas. In Berlin for example, the British Imperial 213

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Fig. 10.1. Total primary energy eemand in Germany 2001 (14,501 PJ). Source:AG Energiebilanzen01/2002. Continental Gas Association (ICGA) began illumination with gas in 1826. According to a contract with the Royal Prussian Ministry of the Interior, the company was paid 31,000 thaler per year to light Berlin's streets. In 1847 the city of Berlin took over public gas lighting. Metering was implemented in 1851. Local gasworks were established. In the period before World War I (1912), the St~idtische Gaswerke AG - today GASAG - became Europe's largest gas supplier. Similar developments took place in all larger German cities and municipalities. In the late 1920s, huge coking plants in the Ruhr area produced a large amount of gas as a by-product of the coking process. Consequently, the mining companies produced and propagated a large-scale plan to feed their gas into a nationwide network of longdistance pipelines. The main pipelines were designed to connect the largest German cities with the Ruhr coking plants. One of these main pipelines was planned to run east from the Ruhr area, via Hanover to Berlin. But the plans of the Aktiengesellschaft f~ir Kohlenverwertung - today Ruhrgas A G - which had been founded in 1926 to forward the scheme, met with strong opposition from the cities and from competing private gas companies. Faced with opposition from all quarters, the nationwide gas network was not realised until after World War II. This has given rise to speculation about the reasons for the evidently slow development of a promising technological system. Comparing the gas engineers and the mining companies with their seemingly more dynamic and successful counterparts in the electricity supply companies, observers

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blamed a general lack of proactive spirit or professional coherence for this striking difference. The economic and technological, as well as the political circumstances within the gas industry were totally different from those the big electricity supply companies had to deal with. As a by-product of the coking process, gas, in contrast to electricity, had never been thought of in terms of a coherent technological system. It was not until the late 1920s that the idea of a long-distance gas network became attractive as part of the rationalisation movement. Unlike the rise of the big electricity supply companies and their interconnected networks, the plan of Ruhrgas AG almost coincided with the beginning of the economic crisis. More important than this, however, was the strong opposition from the cities. Some had operated their own gasworks since the 19th century and used the huge profits derived from them to balance their budgets, and thus were not prepared to give them up. Moreover, the provincial administrations feared that the Ruhr companies would only supply the most profitable consumers and exclude the rural areas from the economic and social benefit of cheap gas. In southern Lower Saxony, divergent economic and political interests paralysed any breakthrough for almost 15 years. It was the demands of the war economy and the interests of the army that finally paved the way for the emergence of an interconnected gas network in Lower Saxony (Niemann, 1997). Today the German gas industry can be divided into two groups: (1) the gas supply industry and (2) the rest of the gas industry. The gas supply industry (GSI) includes all companies that deliver gas to third-party customers such as industry, private households, trade, commerce and the service sector, and power stations. The GSI comprises of local and regional gas utilities, supraregional utilities, natural gas producers and coking plants. Gas utilities- mainly those at the supraregional l e v e l - play the predominant role in the gas sector. The rest of the gas industry can be located in hard coal mining, and in the iron and mineral oil industries. These industries produce gas as a by-product, which they mainly use for their own purposes. At the end of the 20th century, natural gas accounted for more than 90% of the total gas supply in Germany and a remarkable 97% of utilities' gas sales. 10.3. Development of the German Market for Natural Gas

The gas market in Germany has developed on three levels: natural gas production and import, pipeline business and distribution, and end user supply.

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N a t u r a l gas is a relative n e w c o m e r in Germany. Its use spread rapidly in West G e r m a n y beginning in the mid-1960s. In 1965 the natural gas supplied totalled 2 bcm, or about 1% of the total p r i m a r y energy supply. From the early 1970s to the 1990s, the n u m b e r of households using natural gas for space heating rose at an annual rate of over 300,000. Roughly half of the gas was used in the residential and commercial sectors. Today about 75% of n e w houses are supplied with natural gas, and two-thirds of replaced space heating systems are based on natural gas. In East G e r m a n y the first natural gas was p r o d u c e d in 1973 in the Salzwedel area, in western Saxony-Anhalt. After G e r m a n reunification, gas companies took swift action in the early 1990s to e x p a n d the gas industry in the n e w La'nder, to convert all installations from t o w n gas to natural gas and to modernise existing plants and pipelines. Conversion from t o w n gas was completed in 1995. G e r m a n y ranks fifth in Europe in domestic gas production, w i t h a v o l u m e ranging between 17 and 21 b c m in the period since 1973. In 2001 a total of 20.3 bcm of natural gas was p r o d u c e d in G e r m a n y (see Table 10.1). An additional 4.8bcm was p r o d u c e d abroad. G e r m a n natural gas production is located m a i n l y in Lower Saxony. Ten companies of very different sizes produce natural gas in Germany. The core business is done by affiliates of multinational oil companies, with a n u m b e r of G e r m a n drilling and mining companies also contributing, most notably RWE-DEA and Wintershall of the BASF group.

Table 10.1. Natural gas production in Germany. 1999

2000

2001

1,000 m3 percent 1,000m3 percent 1,000m3 percent BEB Erdgas und Erd61 GmbH Mobil-Erdgas-Erd61 G m b H RWE-DEA AG Wintershall AG Preussag Energie G m b H EEG- Erd61 Erdgas G m b H von Rautenkrantz E&P Deutz Erdgas GmbH EWE AG ITAG Total

Source: W.E.G. 2002, p. 36.

10,560,253 49.71 9,802,592 48.78 9,472,129 46.70 5,559,999 26.17 5,326,267 26.51 5,046,391 24.88 1,695,856 7.98 1,786,974 8.89 2,211,282 10.90 1,033,781 4.87 1,201,071 5.98 1,686,123 8.31 1,518,283 7.15 1,187,042 5.91 1,035,015 5.10 765,399 3.60 680,827 3.39 685,108 3.38 57,018 0.27 50,084 0.25 53,944 0.27 39,936 0.19 30,922 0.15 36,770 0.18 9,314 0.05 36,931 0.18 13,702 0.06 17,131 0.09 19,479 0.10 21,244,227 100.00 20,092,225 100.00 20,283,173 100.00

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The two largest producers are subsidiaries of the German branches of multinational oil corporations and control about 72% of the total natural gas production. BEB Erdgas und Erd61 GmbH (merger of Brigitta Erd61 und Erdgas GmbH and Elwerath Erdgas und Erd61 GmbH) is jointly owned by ESSO AG and Deutsche Shell AG, each of which controls 50%. Mobil Erdgas-Erd61 is an affiliate of Mobil Oil. Four production companies (RWE-DEA, Wintershall, Preussag and EEG) together have a market share of nearly 28%, with specific shares of between 4% and 10%. The owners of EEG - Erd61 Erdgas G m b H - are Gaz de France (75%) and E.ON (25%). Four additional companies produce less than 1% of domestic natural gas. Wintershall AG and Deminex GmbH formerly dominated natural gas production abroad. In December 1998 Deminex was divided between Veba - since 2000, E.ON - and Wintershall. Since 1998, Wintershall has been the largest producer of oil and gas abroad. The oil and gas exploration and production activities of Veba Oel AG and Deminex were integrated under the name of Veba Oil & Gas GmbH as the upstream affiliate of the Veba Oel AG group. In 1998 Veba Oil & Gas produced 1.3 bcm and in 1999 1.1 bcm of natural gas abroad. In 2001 BP signed an agreement with E.ON, by which BP, in a first step, acquired a 51% share of Veba Oel, the parent company of Veba Oil & Gas. In January 2002 Veba Oil & Gas signed a sales and purchase agreement with Petro-Canada, pending necessary approval to be obtained in the summer of 2002. The major part of Germany's gas supply is purchased from foreign producers. In 1999 a total of 81.5bcm were imported from Russia, Norway, the Netherlands, Denmark and the UK. The first imports were in the early 1960s. The Netherlands began delivering natural gas to Germany in 1970, followed by the Soviet Union in 1973 and Norway in 1977. Denmark delivered gas beginning in 1986, France in 1992, and the UK in 1993. Until German reunification, the German Democratic Republic imported natural gas from the Soviet Union. German total gas imports increased continuously until 1996, when 83.1 bcm were imported. Since then, total gas imports have been slowly declining (see Fig. 10.2). By the end of 2000, the number of houses using gas for space heating had increased to some 16.5 million, or 44.5% of all households (DIW 2001, p. 83). Gas sales in the residential and commercial market s e c t o r - including private homes, commercial and public buildings, swimming pools, e t c . - were around 38bcm, comprising 34% of the total final energy consumption of this energy market segment (cf. Fig. 10.3).

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Fig. 10.2. Development of natural gas imports in Germany. Source: BMWi & BAFA2002.

Fig. 10.3. Structure of gas consumption in Germany 2000. Source: BMWi.

In the industrial market, gas sales totalled approx. 20bcm, giving gas a share of 32% of total final energy consumption in the sector. This represents nearly a doubling in this sector since 1975. Natural gas consumption for electricity generation was approx. 11bcm, representing 7% of power station feedstock. Combined

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electricity and heat production in gas-fired co-generation plants is of importance in industry and particularly in conurbations. Other gas consumption totalled 12bcm in 2000. This includes gas for district heating as well as non-energy use, e.g., gas as a feedstock in the petrochemical industry.

10.4. Significance of Natural Gas in German Energy Policy Germany's energy policy, as a part of economic policy, is oriented to free market principles. The Federal Ministry of Economics and Technology (BMWi - since November 2000 is now BMWA) ensures the existence of the basic conditions necessary for an efficient energy supply, taking into account supply security, costs, environmental friendliness, and finite natural resources. The necessary protection of the climate, increasing European integration, and accelerating global competition pose international challenges to German energy policy. These general policy issues remained unchanged through the change in government administrations. Although the gas industry is one of the BMWi's primary areas of activity, the heat-energy market in Germany has up to now been characterised by the absence of regulation. Gas supply companies today have no special technical, commercial or legal status. Anybody can undertake to supply gas and build pipelines, plants and other equipment. But until the revision of the basic energy law in 1998, the cartelisation of supply areas was legal. The new energy law calls for liberalisation of the electricity and gas market according to the EU directives for the interior European energy market. The rational use of energy and the utilisation of renewable energies was assigned greater importance by the Social-Democratic/Green coalition government and will play a larger role in future energy policy. At the national level, attention is now being given to Germany's development of a future-oriented and nuclear-free energy supply structure. Energy policy is also to be formed and executed so as to ensure that technologically forward-looking markets are developed within the framework of energy supplies, thus creating jobs and export possibilities. Since the gas industry associations signed a voluntary agreement (the Verbdndevereinbarung-Gas) for third-party access and transmission on July 4, 2000, the GSI has advocated approaches calling for non-regulated competition based on negotiated guidelines, and the liberalisation of pipeline construction and the import and export of natural gas. However, the European Commission demands that the formal requirements of EU directive 98/30/EC be fulfilled.

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10.5. The Technical Infrastructure of German GSI

The companies of the German gas industry have built the necessary facilities and equipment for the purchase and resale of natural gas. At their own cost, they maintain and operate a fully-equipped pipeline system tailored to meet their specific purchase and supply obligations. German gas companies together own approx. 345,000 km of natural gas pipelines (see Fig. 10.4): 28% are high-pressure (1+ to 100b), roughly 34% medium-pressure (100 mb to I bar) and 38% low-pressure pipelines (up to 100 mb). The gas that enters homes has a pressure of 20 mb. In Germany, high-pressure gas pipelines have a diameter of up to 1,200mm. The diameter of medium-pressure distribution systems is

Fig. 10.4. The German gas pipeline system. Source: BGW.

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generally between 50 and 150 mm, and the diameter of pipelines for low-pressure distribution is 80-300 mm. Service mains for single- and multi-family houses have a diameter of between 30 and 65 mm. Sixty percent of the pipelines in the network (excluding service pipes) are made of steel (high-pressure), roughly 33% of plastic (mainly medium-pressure) and about 7% of cast iron (mainly lowpressure), of which about three-quarters are ductile cast iron and less than 25% grey cast iron. Gas contracted by producers and importers for delivery to other gas companies or industrial users is handed over at agreed transfer points. The supply companies operate extensive pipeline systems which include compressor stations and metering and regulating stations. Large amounts of gas are additionally held in underground storage facilities. The actual amount of gas in the storage facilities fluctuates considerably, depending on the time of year, the weather, and the state of economy. At the end of 2000, 42 underground storage facilities with a capacity of about 18.6bcm of working gas were available for peak shaving (NLfB 2001). The regional and municipal gas distribution companies construct, operate and monitor complex distribution systems which include pressure-regulating stations and metering facilities. In larger cities, the pipeline network operates at pressures below 16 bars between offtake stations and the final distribution mains. This often involves a loop with more than one feed-in point. Only in small municipalities is the pressure reduced directly in the offtake stations to the pressure of the final distribution mains.

10.6. Institutional Organisation of the German Gas Market, Major Actors and Activities

The German gas market has a number of institutions and organisations which oversee the technical, political and economic interests of the GSI. Technical self-monitoring of the gas sector has a long tradition, dating back to 1859 and the establishment of the Association of German Gas Experts and Authorised German Gasworks, known today as the German Association of Gas and Water Engineers (DVGW). In the natural gas market the DVGW is involved in transport and distribution, from metering at the production site to the mains in buildings. The Bundesverband der deutschen Gas- und Wasserwirtschaft e.V. (BGW) represents the gas utilities and has over 1,200 member companies. All levels of the natural gas market are represented, from

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production and import to final distribution. The BGW represents the political interests of the gas sector, and is organised in groups and associations at the Land level. The BGW is one of 17 German industrial associations which in 1995 signed the voluntary agreement on CO2 reduction. Founded in 1920 as a "technisch-wissenschaftlicher Fachverband', the Bundesvereinigung der Firmen im Gas- und Wasserfach e.V., or FIGAWA, today has 1,300 members which produce components for, or construct and service gas and water supply facilities. This association is closely connected with DVGW. Whereas the membership of DVGW comprises utility companies, FIGAWA organises the equipment supply industry and contractors of the GSI. At the beginning of 2000, about 28 companies were affiliated under the umbrella association Wirtschaftsverband Erd61- und Erdgasgewinnung e.V. (W.E.G.). With its approx. 6,500 employees, the W.E.G. actively represents the oil and gas production industry in Germany.

10.7. Major Focus of German Gas Policy As domestic production of natural gas accounts for just 20% of the annual gas supply, this area has not been a subject of Germany's national energy policy. The gas importing companies contract with producers, agreeing to buy large quantities of gas over a long period usually 20 years or more. They commit to take-or-pay obligations, requiring them to pay for the contracted gas even if demand falls or gas users switch to other forms of energy. Despite a number of relevant regulations on the GSI, no gas market regulation as such exists in Germany. Both environmental concern about climate change caused by CO2 emissions in the atmosphere and the aim of the Federal Government to phase out nuclear power in Germany indirectly support gasbased energy conversion solutions. Investors' decisions to mainly install gas heating systems in new and modernised houses are due to the environmental standard and favourable price of this energy source. The green tax reform adopted by Parliament in December 1999 included tax exemptions for gas-fired CHP plants. These provisions had to be removed, however, due to EU intervention. This must be viewed in light of the fact that, of all energy sources for power generation, only oil and gas are taxed in Germany, while hard coal, lignite and even nuclear fuel for this purpose remain exempt.

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10.8. The Reform Process and the German Stance on Liberalisation of the European Gas Market

Directive 98/30/EC of the European Parliament and of the Council of 22 June, 1998, concerning common rules for the internal natural gas market, gives EU member states two years' time for implementation. In accordance with the Act Reorganising Energy Business Law of 28 April, 1998, Germany also created full competition in the gas market in a single step. The only missing detail in the law was the formal integration of TPA for gas. The institutional culture of German energy supply industry insists in that regulation by government is not only undesirable but in some respects not legitimate. For the German ESI competition regulation by cartel authorities- i.e., ex-post control of competition a b u s e - is the only legitimate form of regulation. This model is unique in Europe, and the German government has held out against creating a specialised energy regulatory body. Similar to the negotiated TPA in the electricity market, German energy and gas associations tried to reach an association agreement for TPA to gas pipelines. The negotiations were not completed as proposed by the end of 1999. On 17 March, 2000, the gas industry association BGW and the large-scale users' associations BDI, VIK and VKU signed the 'Eckpunkte', a preliminary document for an association agreement, which, similar to that in the German electricity sector, defines TPA to the grid and the calculation of user's fees. The Federal Minister of Economy was present at the event. The final agreement had to be signed before 10 August, 2000, the deadline for the implementation of the EU Gas Directive. The Gas Industry Association Agreement (Verbdndevereinbarung Gas) was signed on 4 July, 2000 by the Federal Association of German Industry (BDI), the VIK, BGW and VKU. The associations agreed on 'objective, transparent and nondiscriminatory criteria' for access to the gas grid. The agreement covered only the industrial sector. It set rules for long-distance transport and reconciliation of the differences between feed-in and take-out, and defined different qualities of gas. The adopted transport tariffs differentiated between the three levels of gas supply. For supraregional supply exceeding distances of 100 km, the fee depended on the transport distance (entfernungsabha'ngiger Tarif). For regional and local levels, a stamp system was chosen (regional or municipal stamp).

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While not simple, this model is in keeping with the traditional structure of the German GSI. As in the ESI, the German GSI favoured a negotiated solution over government regulation. This can be interpreted as an effort to buy time and forestall the consequences of the very liberal German Energy Act, which can be used by big energy supply companies as an expansion platform. Two amendments to the association agreement of July 2000 were signed in March and September 2001 respectively. In May 2002 the second association agreement (VV Gas II) was signed after long and strenuous negotiations. Despite the initial apparent failure of the talks, the involved parties eventually managed to reach a consensus and thus head off the introduction of a regulator. The VV Gas II differentiates between just two network levels: longdistance supply and end distribution. The division between supraregional and regional long-distance gas supply heretofore in effect was removed and a uniform long-distance tariff system put in place. At the end-distribution level, the VV Gas II maintains the use of stamps comprising labour, performance and service system fees. The VV Gas II came into force on 1 October, 2002, to be effective for a period of one year. Its continued implementation will depend on whether the new regulations for network access are uniformly and transparently put in practice. Additionally, the transport tariffs must be brought into line with European standards. In 2002 the transport tariffs at the end-distribution level exceeded the European average by up to 40% (Hannes et al., 2002:614f). The voluntary agreement by the associations on basic rules for competition in the gas market makes for a continuation of the lack of state regulation in this part of the energy market. In comparison to the electricity market, in which the existing state regulation for investment, cartelisation and tariffs has been criticised as dysfunctional and was partly abolished by the new energy act, the gas market has an even longer tradition of self-regulation in Germany. Even if the opening of the gas market is to be similar to that of the electricity market, the speed and degree of the process is left to be negotiated by industrial associations. German gas prices, which range about 20% above the European average, will decrease as a result of the liberalisation, but not to the same degree as electricity prices have. In contrast to the electricity market, the German gas market is not characterised by over-capacities, and the share of natural gas in primary energy consumption is still growing.

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10.9. Current Issues of Importance for the German GSI

The issues of importance for the German GSI are, on the one hand, the future of municipal utilities given the financial situation of municipalities, and on the other, the wave of mergers in the energy industry leading to higher concentration and centralisation of the energy sector, and to increased inter-fuel competition between the electricity sector and the gas market. All larger electricity utilities have acquired shares of gas utilities at the supraregional, regional and local supply levels. If the electricity sector can extend its control over the GSI, its power station strategy will determine the market opportunities for the supply of district heating by CHP plants and other energy services. When the Federal Cartel Office blocked E.ON's acquisition of a majority stake in Ruhrgas in February 2002, Cartel Office president Dr. B6ge stated: "The merger would further strengthen dominant positions in the gas and electricity markets. (...) Ruhrgas' share in the largest grid gas company in Eastern Germany, VNG (37 percent), and in municipal utilities would, for example, fall into E.ON's hands as a result. In a region like Hanover, competition for end-consumers would come to a complete standstill" (Bundeskartellamt, press release 28/ 02/2002). The merger of Ruhrgas and E.ON would strengthen Ruhrgas' position as the dominant supplier to gas distributing companies. Ruhrgas would, to a great extent, be able to secure its sales to E.ON affiliates and associates and deny competitors market access. E.ON group companies, on the other hand, would be able to strengthen their positions in supplying gas to large end-consumers and local gas distributors, since after the merger they would no longer face potential competition from Ruhrgas. Having better opportunities to bundle gas and electricity supply would strengthen E.ON companies supplying both electricity and gas. This would create more market barriers to companies operating purely in the gas supply sector. According to former BGW president Hartmann, the German gas industry has reduced its workforce by about 30,000 in the last decade. Of approx. 110,000 jobs in the German gas industry at the beginning of 2000, a further 20,000 will be cut in the near future. These figures can be questioned, as official statistical data for the German energy sector differ from this statement. The gas industry as a whole employed 36,900 people in 1991. This number gradually declined to 32,800 in 1997. The reduction of 4,100 jobs, or 11% of the workforce, in the gas supply industry over seven years is not especially critical; lay-offs in the gas industry are less than the average for the energy industry as a whole.

226

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10.10. Institutional Organisation of the German Gas Market

Roughly 730 independent companies operate in the German gas industry. In 1998 the German gas industry had around 44,000 employees and invested ~3.07 billion. The German gas companies operate at different supply levels: 10 companies are producers a n d / o r importers. They sell gas from fields in Germany or from foreign suppliers to 16 supraregional gas utilities, and to approx. 710 regional and local distribution companies, as well as to major industrial customers. Regional and local distribution companies resell gas to residential and commercial customers, as well as to industrial users (see Fig. 10.5). Even if the German gas industry comprises a large number of companies, the gas sector is dominated by several big corporations, of which Ruhrgas AG and Wintershall AG are the most prominent. Since the basic energy law was revised in 1998, giant mergers have taken place in the German energy sector. RWE and VEW became the new RWE AG, while PreussenElektra and Bayernwerk formed E.ON Energie AG. These mergers have also influenced the gas industry. The role of the two giant electricity companies on the gas market has totally changed since the liberalisation. E.ON and RWE dominate the German gas industry today. RWE has inherited VEW's position as a national grid company with a sizeable turnover in natural gas. After its renaming of Westf~ilische Ferngas to RWE Gas AG in 2000, RWE

9 Domestic natural gas producers

Foreign suppliers" NL, N, RF, DK, GB v

16 Supra-regionalgas utilities (8 importers) 9

710 Regional and local gas utilities v

Domestic end users" residential & commercial customers, industry,power stations Fig. 10.5. Structure of the Natural Gas Industry in Germany. Source: Ruhrgas in Schiffer 1999, p. 131; current data.

Export

The Transformation of the German Gas Supply Industry

227

achieved a relative market share of 24% in the German natural gas market. E.ON reorganised its gas business by merging the regional utilities THUGA and Contigas, and is, after the acquisition of Ruhrgas, one of the Western world's biggest private energy groups. Other important actors are the German subsidiaries of multinational oil companies (Shell, BP, and ExxonMobil). In 2001 RWE formed a strategic alliance with Shell, and E.ON joined forces with BP. As in the German electricity sector, the survival of a large number of municipal utilities or Stadtwerke- the traditional local-level suppliers of electricity, district heat, gas and other s e r v i c e s - is threatened. Additionally, there is a trend towards the privatisation of municipal utilities.

10.11. Current State of Industrial Organisation in the German Gas Sector

The relative market share of the supraregional gas utilities in the German natural gas market has been stable. Ruhrgas AG has long been the dominant company, in recent years supplying about 600 billion kWh annually. In 2000 Ruhrgas sold nearly three times as much gas as the two next largest companies, Wintershall and RWE Gas, combined (see Fig. 10.6). In the last several years, the steep increase in the market share of the Wintershall group is noticeable. Wintershall is a fully owned subsidiary of BASF AG. After taking over the former German Democratic Republic's gas contracts with the Soviet Union and establishing two joint ventures with the Russian Gazprom, Wintershall

Fig. 10.6. Gas supply of supraregional gas utilities 2000. Source:Annual reports; database FFU.

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developed into a true competitor of Ruhrgas. The Wintershall group builds and operates gas transmission systems and storage facilities, and markets transportation and storage capacities. In the area of industrial power stations, BASF and RWE became partners in the operation of gas-fired CCGT plants on a contract basis. This joint strategy, which has been exported to other European countries, secures the Wintershall group's stake in the gas supply market. The ownership of the supraregional gas utilities is characterised by the strong positions of the multinational oil companies and their German subsidiaries, and the giants of the electricity supply industry. Esso, Shell, Mobil and BP are shareholders in six supraregional utilities. RWE, E.ON and EnBW own shares in nine supraregional utilities. Since German reunification, Verbundnetz Gas AG (VNG) has operated as a subsidiary of Ruhrgas and other supraregional gas utilities (Wintershall, BEB), as well as other energy corporations. In 2002 Ruhrgas additionally holds shares in six, and Wintershall in four supraregional utilities. Some supraregional utilities are partly publicly owned (RWE Gas, Bayerngas, Avacon, Gas-Union, Gasversorgung S~iddeutschland, and Saar Ferngas) by German Ldnder or municipalities. Gazprom (or its subsidiary, Zarubeshgaz) and Statoil are foreign shareholders in three supraregional utilities. The approx. 40 regional gas utilities are mostly under the control of the largest supraregional utilities, electricity utilities and other energy corporations, by means of capital links and/or long-term supply contracts. Seventy percent of gas supplied to final gas customers - industry, power stations, households and small c u s t o m e r s - is provided by regional and local gas utilities. A share of 28% of all gas customers is supplied by the supraregional gas utilities. In 1997 about half of the 711 local and regional gas utilities were under municipal ownership. More than a quarter had capital links with other companies, mainly electricity utilities, a proportion that has since increased significantly due to the liberalisation of the energy business and lack of financial sources for municipal budgets. Until the liberalisation of the gas market, the territory of Germany was divided among 19 supraregional gas utilities. Through mergers, the number has shrunk; in 2001 there were 16 supraregional gas utilities. In 2000, a total of 921.5 billion kWh of natural gas was consumed in Germany. The total gas supplied by the 16 supraregional utilities was more than double, due to pre-deliveries. Table 10.2 shows the German gas industry ranking.

The Transformation of the German Gas Supply Industry Table 10.2.

Ranking of German supraregional gas suppliers.

Rank C o m p a n y 1 2 3 4 5 6 7

8 9 10 11 12 13 14 15 16

229

Ruhrgas AG Wintershall group RWE Gas AG BEB G m b H Verbundnetz Gas AG Mobil Erdgas-Erd61 GmbH Gasvers. Siiddeutschland GmbH Erdgas Miinster GmbH Thyssengas G m b H Bayerngas G m b H Saar Ferngas AG Gas-Union G m b H EWE AG Avacon AG FG N o r d b a y e r n GmbH EVG m b H Total

Gas Gas Supply Supply in Turnover Pipeline Market bn. kWh in bn. ~ grid in km Workforce share (%) in bn. 1999 2000 2000 2000 2000 kWh 2000 63.2 24.0 23.9 17.9 17.3 15.7

582.0 221.5 220.0 165.0 159.2 145.0

585.7 199.5 200.0 181.3 150.7 70.2

9.18 4.23 1.41 1.83 2.61 12.3

10748 1830 4600 3439 7308 No

2581 1361 961 1369 910 2560

8.9

81.6

80.2

1.26

1880

245

8.6

79.1

82.3

1.22

2014

72

7.4 6.3 4.7 4.4 4.3 3.9 3.1

68.0 57.9 43.1 40.7 39.9 36.3 28.7

71.0 56.7 44.4 41.7 38.9 37.2 29.1

1.12 0.51 0.76 0.70 2.09 1.82 0.51

2300 1163 2692 505 n.i. 16986 2030

379 128 197 33 2310 2808 n.i.

2.4

21.8 1989.8

23.9 1892.8

0.39 41.94

1188 58683

26 15940

Source: Annual reports; own calculations FFU.

10.12. Major Gas Companies: their Activities, Responsibilities and Ownership Structures

10.12.1. Ruhrgas AG, Essen Ruhrgas was founded as the Aktiengesellschaft fiir Kohlenverwertung in 1926. The objective of the new company was to sell the coking gas that was a by-product of the coking process in coalmines and steelworks in the Ruhr region. The mining companies drew up a large-scale plan to feed their gas into a nationwide network of long-distance pipelines. The main pipelines were designed to connect the largest German cities with the Ruhr coking plants. One of these main pipelines was planned to run from the Ruhr region via Hanover to Berlin, but was realised only with the help of the war economy. After World War II, Ruhrgas developed into the strongest supraregional gas supply company in Germany.

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National Reforms in European Gas

With the start of natural gas deliveries from the Netherlands at the beginning of the 1960s, Ruhrgas concentrated on supplying natural gas. Ruhrgas AG is a private-sector company which makes an important contribution to meeting gas requirements both in Germany and, increasingly, in neighbouring countries. Directly or through its affiliates, the company controlled 63 bcm of the 80 bcm of natural gas that was distributed in Germany in 2000. Ruhrgas is by far the largest supraregional gas utility in Germany. Ruhrgas has long-term, flexible purchase agreements both with domestic gas producers and with foreign producers in the Netherlands, Russia, Norway, Denmark and the United Kingdom. Ruhrgas does not hold shares in German natural gas producers, but controls the greater part of natural gas imports. By long-standing agreements, Ruhrgas has links to nearly all gasproducing regions in Europe. It has co-operated, for example, with the Russian gas industry for 25 years. It sells gas to regional companies, local distribution companies, industry and power stations. Its supply system comprises of over 12,000km of pipeline, 12 underground storage facilities with a working gas volume of approx. 4.8 bcm, and 26 compressor stations with a total capacity of 785 MW. In 1998 Ruhrgas extended existing agreements on the purchase of Russian gas and signed contracts for new flexible deliveries. Ruhrgas was the first foreign gas company to acquire a direct share in OAO Gazprom, the largest gas producer in the world. Ruhrgas not only has an equity share in Gazprom but a seat on the supervisory board. Ruhrgas has approx. 1,600bcm of natural gas under contract, roughly equal to the entire gas reserves of the Netherlands. Its corporate policy calls for the agreement of long-term contracts, some of which run until 2030. New energy laws and energy industry regulations will change the business environment in which companies such as Ruhrgas AG operate, both at the national and international level. Ruhrgas intends to remain the leading gas company in Germany under these new market conditions. The Ruhrgas group offers a wide range of services and products for the transportation and use of natural gas. The service package Ruhrgas offers goes far beyond the mere supply of gas, and the quality of its gas purchasing structure is the basis for gas supply contracts with German and foreign customers and partners. At the end of 1994, Ruhrgas AG established two holding companies which began operations in 1995. Ruhrgas Energie BeteiligungsAktiengesellschaft (RGE) holds the majority of Ruhrgas AG's interests

The Transformation of the German Gas Supply Industry

231

in energy utilities, and Ruhrgas Industries GmbH is responsible for the corporation's industrial affiliates. The objective of this new corporate organisation was to bundle the required know-how for the management and administration of the affiliates and further expand them. The Ruhrgas Group has pooled its industrial activities under the umbrella of Ruhrgas Industries GmbH. In 2000 Ruhrgas Industries had a turnover of ~963million with a workforce of 6,212. Ruhrgas Industries unites a group of companies that are specialists and international leaders in their particular markets. The industrial affiliates grouped under Ruhrgas Industries operate in four business segments: gas measurement and control, industrial furnaces, engineering and indoor installations. At the end of 2000, RGE held interests in 23 German energy utilities. RGE's foreign utilities are concentrated in Scandinavia, the Baltic States and Central Europe. In 2000 RGE had a total of 17 foreign equity interests. Its latest acquisition was in March 2002, when it took over the gas supply utility of Slovakia. Ruhrgas holds interests in six German supraregional gas utilities (see Table 10.3). Ruhrgas additionally owns shares in the regional utilities MVV Energie AG (14.87%), Gasag Berliner Gaswerke AG (11.95%), Stadtwerke Bremen swb AG* (11.32%) and THOGA AG (10.02%), as well as in a number of local utilities. Ruhrgas AG accounts for around 87% of the turnover of the Ruhrgas group. In 2000 the group had a total gas sendout of 50 bcm or 582 billion kWh, a net turnover of ~10.518 million (1999:G7.83 million), 8,453 employees, and a profit of ~899.5 million. The shareholders of Ruhrgas AG are private-sector companies in mining, steel and capital goods industries, as well as gas producers operating in Germany. Voting rights at general meetings are held by Bergemann GmbH (59.76%), BEB Erdgas und Erd61 GmbH (25%), Schubert KG (15%) and other companies (0.24%). Bergemann GmbH Table 10.3. Supraregionalgas subsidiaries of Ruhrgas. Company

Ruhrgas share in percent

Ferngas Nordbayern GmbH Erdgasversorgungsgesellschaft Thtiringen-Sachsen mbH (EVG) Verbundnetz Gas AG (VNG)* Gas-Union GmbH Bayerngas GmbH* Saar Ferngas AG

53.1 50.0 36.84 25.93 22.02 20.0

*Subsidiaries to be sold according to ministerial approval decree for E.ON-Ruhrgas

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National Reforms in European Gas

represents a voting pool of Gelsenberg AG (Deutsche BP AG), RAG Beteiligungs GmbH (RAG AG), Mannesmann AG, ThyssenKrupp AG, RWE-DEA AG, E.ON AG and other companies. The mineral oil companies Mobil Oil, Shell, Esso, BP and Preussag own about 40% of Ruhrgas shares. The majority vote of Bergemann is represented by RAG, which holds 18% of Bergemann, but the single voting right. E.ON and RWE are the main shareholders of RAG. In July 2001 E.ON announced plans to obtain a substantial interest in Ruhrgas. The first step was an agreement between E.ON and BP plc to reorganise their oil and gas activities in Germany. E.ON is to acquire a stake of 51% in BP subsidiary, Gelsenberg AG, which holds 25.5% of Ruhrgas. In a second step, BP has the option to sell the remaining 49% of Gelsenberg to E.ON. BP in turn acquired a stake of 51% in Veba Oel AG. In 2002 E.ON exercised a put option to sell the remaining 49% of Veba Oel. In August 2001 E.ON applied for antitrust approval of the Gelsenberg acquisition. In November 2001 E.ON applied to the German Federal Cartel Office for the acquisition of a majority shareholding in Ruhrgas, after having also reached agreement with Vodafone (formerly Mannesmann), ThyssenKrupp, and RWE to acquire their respective shares in Bergemann, which holds 34.8% of Ruhrgas. However, the Federal Cartel Office blocked E.ON's acquisition of a majority stake in Gelsenberg in January 2002, and Bergemann the following month. In justifying its action, the Federal Cartel Office argued that the merger of Ruhrgas and E.ON would strengthen Ruhrgas' dominant position in the gas market, as it would enable Ruhrgas to secure its sales to E.ON affiliates and associates and deny competitors market access (Bundeskartellamt, press release 28/02/2002). E.ON then tried to obtain clearance for its Ruhrgas acquisition by way of ministerial approval. The Minister of Economics and Technology was in charge of the clearance procedure. The result of this bid will be of major importance for the future prospects of Ruhrgas, and of the German gas supply industry in general. In its decree of July 5, 2002 the Ministry of Economics and Technology gave its permission for the merger under several conditions. However, the execution of the ministerial approval was blocked by a ruling of the Upper State Court in D~isseldorf. The court faulted the decree on several procedural counts. A revised decree of September 18, 2002 is tightening up conditions for the merger. It requires E.ON and Ruhrgas to sell their holdings in VNG, up to 10% of which may be bought by East German municipalities a n d / o r the VNG Verwaltungs- und Beteiligungs GmbH. It stipulates that "the remaining shares shall be sold to a strategic

The Transformation of the German Gas Supply Industry

233

buyer." The revised decree demands that E.ON sell its 27.4% share of EWE, held by E.ON Energie AG, and its 80.5% share of Gelsenwasser AG. Ruhrgas and E.ON are further required to sell their shares in swb AG, Bremen (11.3 and 22%, respectively), and Bayerngas GmbH, Munich (22.02 and 22%, respectively). Beginning 1 October, 2003, E.ON and Ruhrgas must sell 200TWh of natural gas, in accordance with a release programme. The merger of E.ON and Ruhrgas was able to go ahead in January 2003 because all plaintiffs had withdrawn their complaints from the Upper State Court. The acquisition was completed in March 2003 when E.ON purchased additional 40% interest in Ruhrgas previously held by ExxonMobil, Shell and Preussag at a price of G4.1 billion.

10.12.2. RWE Gas AG, Essen RWE was established as the operative lead company for all gas activities of the RWE group. The company develops and bundles gas competence in the value chain of exploration, import, transport, storage, distribution and supply. In 2000 RWE Gas and its affiliates had a total gas sendout in Germany of 220 billion kWh. It is ranked second on the national gas market. RWE Gas has a gas pipeline grid of approx. 10,600 km at its disposal and operates 24,100 km in its gas distribution networks. At the end of 2000, RWE Gas had 10,015 employees, and served approx, one million households and small customers, public institutions and 125 industrial businesses directly through their own gas utilities, as well as indirectly through 78 subscribing companies. RWE Gas is the product of the merger of VEW Energie AG and RWE Energie AG gas activities into a modern utility and service company which serves large parts of Westphalia, as well as parts of Northern Hesse and Southern Lower Saxony with natural gas. Thyssengas GmbH, Duisburg, and rhenag AG, Cologne, are the major affiliates. In the new La'nder RWE Gas holds stakes in numerous regional and local utilities. The most important is Mitteldeutsche Gasversorgung GmbH (MITGAS), with a total gas sendout of more than 17 billion kWh in 2000. On the European market, RWE Gas is active in Hungary, holding stakes in three gas supply companies: DDGAZ, TIGAZ and FOGAZ, Budapest's gas utility. RWE Gas provides Hungary with 55 billion kWh of gas, roughly half of the gas consumed in the country. RWE Gas is also active in other Eastern European countries where the gas market has been liberalised, namely in Poland, and in the Slovak and the Czech Republic. RWE Gas holds a majority share in

234

National Reforms in European Gas

KB-Gaz T&E of Szeczin, and made a successful bid for Transgas AS of Prague. RWE paid ~4.1 billion for its 97% stake in Transgas. As part of the deal, between 46 and 58% of the regional Czech gas distributors were also handed over to RWE Gas. In Slovakia, RWE holds a share of the gas storage company Nafta, which has at its disposal strategically important storage capacities along the international gas transit route. In Western Europe, RWE Gas acquired N.V. Nutsbedrijf Haarlemmermeer (NBH) in the Netherlands. At the beginning of 2001, the company's engagement in the Netherlands was broadened through its purchase of the municipal shares of the gas utilities Intergas and Obragas. The supply area of these utilities is located in Northern Brabant in the southern Netherlands. RWE Gas controls 7% of the Dutch gas market.

10.12.3. Wintershall AG, Berlin Wintershall AG, based in Kassel, is one of the oldest German petroleum and natural gas companies. In 1894 industrialist Heinrich Grimberg and drilling entrepreneur Carl Julius Winter established Wintershall as a drilling company. The company's original speciality was potassium mining. In 1930, however, an oil eruption in one of the potassium shafts gave birth to a promising new segment of Wintershall's operations: petroleum production. The company intensified its efforts in prospecting for and developing oil deposits and soon became Germany's largest petroleum supplier. Natural gas production operations were started in the 1950s. Since 1969, Wintershall has been a subsidiary under full ownership of the transnational chemical company BASF AG. For the BASF group, Wintershall is an important supplier of feedstocks and forms an integral part of that company's long-term strategy for securing energy resources. In 2001 gross sales of Wintershall Consolidated amounted to ~5.3 billion (2000:~4.6 billion), representing an increase of ~0.7 billion. Wintershall's income from operations totalled ~1.32 billion (2000: ~1.334 billion). The company invested ~229 million in tangible and intangible assets, G38 million less than the previous year's figure. Wintershall's crude oil production increased by 5% in 2001, to 8.1 million metric tons. Natural gas production rose to 5 million bcm in 2001, exceeding the figures for the previous year by around 28%. Natural gas production in Germany increased by 39% to 1.6bcm. In March 1999 Wintershall and Gazprom signed an agreement on the joint production of oil and gas in Russia and other countries. This agreement marks a new era in the partnership of these two companies.

The Transformation of the German Gas Supply Industry

235

W I N G A S was established to purchase and sell natural gas in Germany. These operations involve building and operating natural gas pipelines and storage facilities, the capacities of which W I N G A S also markets. W I N G A S G m b H is a joint venture of Wintershall AG (65%) and the Russian O A O G a z p r o m (35%) and has about 200 employees (see Table 10.4). Since its entry into t h e G e r m a n gas m a r k e t in 1993, WINGAS has gianed a 13% share. The c o m p a n y has invested over G2.56 billion in pipelines and natural gas storage facilities. In 2001 WINGAS was able to increase its natural gas sales by 7% to a total of 120.7 billion kWh. The W I N G A S natural gas transmission system, with an associated u n d e r g r o u n d storage facility and several compressor stations, is designed for natural gas deliveries to local utilities, regional pipeline companies, national pipeline operators, industrial users and p o w e r stations, in keeping with their patterns of d e m a n d . Excess transmission capacities are m a d e available for third-party use.

Table 10.4. Subsidiaries of Wintershall AG. Fully consolidated subsidiaries of Wintershall AG Wintershall Erdgas Beteiligungs GmbH, Kassel WINGAS GmbH, Kassel Haidkopf GmbH, Celle Wintershall Romania Explorationsund Produktions GmbH, Kassel Untertage-Speicher-Gesellschaft mbH, Nordenhamm/Kassel Wintershall (U.K.) Ltd., London Wintershall Nederland-Gruppe, The Hague Wintershall Holding B.V., The Hague Explorations- und Produktions-Beteiligungsgesellschaft der Wintershall mbH Wintershall Energia S.A., Buenos Aires Joint ventures consolidated pro rata: Wintershall Erdgas Handelshaus GmbH (WIEH), Berlin Wintershall Erdgas Handelshaus Zug AG (WIEE), Zug Further investments: JV Wolgodeminoil, Volgograd Verbundnetz Gas AG (VNG), Leipzig Erdgas-Verkaufs-Gesellschaft mbH, Miinster Wintershall Bank GmbH, Kassel Wirtschaftliche Vereinigung deutscher Versorgungsunternehmen AG, Frankfurt/Main

Share in percent 100 65 100 100 100 100 100 100 100 100 50 50 50 15.79 28.8 100 50

236

National Reforms in European Gas

The new WINGAS transmission system carries Siberian natural gas and British North Sea gas to customers throughout Germany, thus making an important contribution to the country's long-term natural gas supply. In recent years, efficient cooperation between WINGAS and its associated marketing companies Wintershall Erdgas Handelshaus GmbH (WIEH) and Wintershall Erdgas Handelshaus Zug AG (WIEE) has helped to boost natural gas demand. For natural gas purchasers in Germany, WINGAS was the first alternative to the established natural gas companies. It has stimulated competition on the German gas market, thus benefiting both natural gas buyers and end users. The extension of the WINGAS underground gas storage facility in Rehden was completed in August 1999. Rehden is now Western Europe's largest underground gas storage facility, with a storage capacity of 4.2 billion m 3 of natural gas. WINGAS therefore accounts for roughly a quarter of the storage capacity available in Germany. The WINGAS transmission system comprises the pipelines MIDAL, RHG, WEDAL and JAGAL. MIDAL connects the terminals in Northern Germany for natural gas arriving from Western European sources with the German consumer centres. It runs 702km from the North Sea coast to Southern Germany. The RHG pipeline, 132km in length and connected with MIDAL, was built by WINGAS and Hamburger Gaswerke (HGW). Commissioned in the third quarter of 1994, RHG serves the HGW Hamburg gas utility, thus providing the entire Hamburg metropolitan area with natural gas. WEDAL MIDAL to the Belgian natural gas grid. The two sections of WEDAL cover a distance of approx. 320 km. JAGAL is the extension of the YAMAL-Europe pipeline in Germany with a total length of 336km. The YAMAL-Europe pipeline itself extends over more than 4,000 km from the Siberian Yamal peninsula to Frankfurt on the Oder. The JAGAL pipeline went into operation at the end of September 1999, requiring a total investment of ~0.56 billion. JAGAL forms a link between Russia's enormous gas reserves and the growing markets in Western Europe. This is of major importance for Germany's supply security, since, by the year 2010, the share of natural gas as a part of primary energy consumption will have increased to approx. 23%.

10.12.4. BEB Erdo'l-Erdgas GmbH, Hanover The history of BEB is the history of the two mining companies, Gewerkschaft Brigitta and Gewerkschaft Elwerath. BEB was founded

The Transformation of the German Gas Supply Industry

237

in 1969 through the merger of these two companies, each of which played a significant role in the history of oil and gas production in Germany. While Elwerath can look back on a long tradition as the largest oil producer in Germany, Brigitta achieved its dominant position in domestic gas production as a result of the discovery and development of gas reservoirs in the South Oldenburg area of Lower Saxony from the beginning of the 1960s onwards. At the outset, Brigitta's prospects were anything but promising. On 29 August, 1867, 'in the name of the King,' one Johann Clever, merchant by trade, was granted permission to explore and mine copper and lead ore in the district of Waldbr61, near Cologne. With this, however, the operational commitment of Brigitta was exhausted for the next few decades: the main activity of the company subsequently consisted of passing the title to heirs and purchasers. In 1921 the company was sold to multiple owners for the first time. In accordance with the regulations of the Mining Law, Gewerkschaft Brigitta came into being. In 1920 the industrialist Theo Seifer purchased the shell of the Elwerath company founded in 1865. His first major success was an oil discovery in Brand, a forest village northeast of Hanover. The war and postwar years were a boom-time for Elwerath and made the company one of the largest German oil producers. Brigitta has been owned by Esso and Shell in equal shares since 1932, as Elwerath has been since a third partner withdrew in 1969. After the discovery of the first major gas field in Europe, natural gas quickly became an important energy source in Germany. It soon became clear that the rapidly growing gas demand could no longer be met by domestic supplies alone. BEB reacted to this by signing a contract with the Netherlands in 1970. Contracts for Norwegian, Danish and Russian gas imports followed. Today, with diversified gas supplies at its disposal with which to meet the requirements of its customers, BEB has become one of the most important gas distribution companies in Germany. On 1 January, 1999, BEB Erdgas und Erd61 GmbH (BEB 'old') and Elwerath Erdgas und Erd61 (Elwerath) merged to form Brigitta Erdgas und Erd61 GmbH (Brigitta). At the end of October 1999, the company was registered under the new 'old' name of BEB. Shareholders in both the new and 'old' BEB are still Deutsche Shell AG and ESSO Deutschland GmbH. In 2000 BEB produced 9.8 bcm of natural gas in Germany, imported 7.7bcm and had total gas sales of 16.9 bcm. In 2001 BEB increased its gas sales by almost 10% over the previous year, from 165 billion kWh

238

National Reforms in European Gas

to 180 billion kWh. This increase was mainly due to additional sales in the Netherlands and Great Britain. A decisive factor for BEB is its strong domestic production base, which accounts for almost half of company sales. BEB is the leading German gas producer and one of the country's largest redistribution companies. Its workforce numbered 1,396 in 2000. BEB holds shares in 13 gas companies, among them Erd61-Raffinerie Deurag-Nerag GmbH (80%), Schubert KG M~inster (29.9%) ErdgasVerkaufs-GmbH (M~inster) (27.7%), Ruhrgas AG (25%), Ferngas Salzgitter GmbH (13.5%), Avacon AG (13%), Verbundnetz Gas AG (Leipzig) (10.5%), and Hein Gas Hamburger Gaswerke GmbH (10.1%).

10.12.5. Verbundnetz Gas AG (VNG), Leipzig VNG was created in 1990 as a follow-up company to the former VEB Verbundnetz Gas, which had held the monopoly in East Germany. Ruhrgas AG became the largest owner, with 36.84% of VNG shares. Seven further shareholders control the remainder of the stock. Wintershall Erdgas Beteiligungs-GmbH and VNG Verbundnetz Gas Verwaltungs- und Beteiligungsgesellschaft mbH, which is owned by eight Eastern German city utilities, each hold 15.79%. BEB Erdgas und Erd61 GmbH holds 10.53%, and Statoil, EEG Erdgas Transport GmbH, E.ON Energie AG and ZGG-Zarubezhgas-Erdgashandel-GmbH 5.26% each. According to the E.ON-Ruhrgas merger conditions, both companies have to sell their shares in VNG. In 2001 VNG had a turnover of ~3.1 billion (2000:C2.61 billion), and a total gas sendout of 150.8 billion kWh. In 2000 VNG had a total gas sendout of 159.2 billion kWh, of which 152.2 billion kWh were delivered to customers in fiscal 2000. The rest was delivered in the first quarter of 2001. VNG's pipeline network is approx. 8,000 km in length, the company has compressor stations with 77.3 MW and 2.35bcm underground storage capacity at its disposal. At the end of 2000, VNG employed a workforce of 910. In total, VNG transported 22.5 billion kWh of gas for third parties during 2000. VNG has 10 subsidiaries, e.g., ZEUS.energy GmbH and Verbundnetz Gas Beteiligungs-GmbH & Co. KG, both of Leipzig (full ownership of each). VNG holds shares of between 10 and 100% in eight energy utilities. It controls 20% of GasLINE Telekommunikationsgesellschaft deutscher Gasversorgungsunternehmen mbH & Co. KG. VNG holds an interest in North Bohemian Gasworks in the Czech Republic, and has also established two new

The Transformation of the German Gas Supply Industry

239

Polish companies in cooperation with the Polish gas industry. VNG has further had involvement in a district heat company in Slovakia. VNG's customers are the classic triad: regional and local gas supply utilities, power stations, and industry. Natural gas already accounts for 26% of primary energy supply in Eastern Germany and two of three households in the region are heated directly or indirectly with gas. VNG wants to consolidate its leading position in Eastern Germany in the field of gas services, and to expand its involvement in energy utilities in Germany and abroad. 10.13. Outlook for the German Gas Industry

The future of the German gas market is very promising. The share of natural gas is growing as a part of primary energy supply, as well as in power generation, substituting coal and oil, and electricity in the heat market. In the last 50 years, gas send-out has grown by 1200%. Supported by the energy and environmental policy of the Federal Government, the rise in annual growth rates will continue. In 2001 natural gas constituted 21.5% of Total Primary Energy Supply (TPES) and had a share of about 10% in electricity generation. According to baseline scenarios, natural gas will account for 27.7% of TPES and 20.4% of electricity generation by 2020. If a consistent climate policy is implemented, the share of natural gas as a part of TPES will double, and will make up 53.9% of electricity generation in 2020. The Act Reorganising Energy Business Law came into force in April 1998. This law, together with the EU gas market directive and the antitrust law, creates the legal framework for the German GSI. The new energy business law has brought a b o u t - as in the German electricity market, but in contrast to the EU d i r e c t i v e - not a step-by-step, but a full opening of the market for all groups of consumers. The German path to liberalisation constitutes a special approach in Europe. Negotiated third-party access (TPA) to hightension grids and pipelines has not been chosen by any other EU member state. As in the German electricity sector, the TPA problem in the gas sector was not dealt with by state regulation, but by voluntary agreement of industrial associations. It is doubtful whether this approach will endure in the context of European market liberalisation. With regard to the effects of liberalisation, it can be said that a one-to-one transposition of international experience to the German gas industry will not be possible, due to the different historical, economical and political factors at work. The European gas industry has had divergent structural patterns for decades. The strong local and municipal foothold of Stadtwerke in Germany, with profit-generating

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National Reforms in European Gas

energy supply and loss-making local transport and other deficitspending activities, is unique to Germany within the EU. However, the German GSI has to come to terms with a bundle of changing conditions and challenges: 9 Increased fossil energy substitution and gas-to-gas competition, which will put pressure on gas prices and force rationalisation. Even if price reductions do not compare to those for electricity supply, a reduction of around 10% is anticipated. 9 Basic new orientation in established customer-supplier relations, e.g., a change from a seller's to a buyer's market with additional changes in corporate strategies to respond to customers' wishes. In a gas market structured by competition, the degree of customer satisfaction will become a strategic factor for success. 9 A large number of German gas suppliers have focussed on the development and marketing of energy service activities, in part to increase connections with customers. There are two different thrusts to this effort: (a) improved organisation of metering, controlling and billing, and (b) the development of complex energy consumer services, including, among others, heat delivery and contracting. Energy trading and integration of the infrastructure with telecommunications services can be recognised as new business fields for gas supply companies. 9 Creation of strategic alliances in the area of gas production and gas transport and mergers. The obvious trend towards concentration in the gas i n d u s t r y - with special repercussions from the giant electricity mergers in G e r m a n y - can be seen as a reaction to the very liberal energy law and the corporate search for cost reduction and synergy effects. 9 Internationalisation of gas trade in the form of diversification of suppliers and optimisation of cooperation between gas exporters and importers. An obvious trend is the stronger positioning of foreign gas companies in Germany, e.g., Gaz de France, Statoil, and Gazprom. 9 New actors in the gas business. The opening of the domestic gas market means that all customers - domestic households from April 2002 o n - can choose between the established 700 gas supply companies and additional suppliers. Energy companies from other energy and supply sectors, e.g., mineral oil, electricity, district heating, and water are offering full energy services. Companies from the trade and service sectors (deparment stores, petrol stations, bank-houses etc.) will start with the sale of electricity and gas as a normal commodity. Brokers, portfolio-managers and other

The Transformation of the German Gas Supply Industry

9

9

9

9

9

241

business units will not enter the physical gas trade, but organise and bundle gas customers. Special attention should be paid to the ongoing acquisition activities of electricity companies in the gas sector. Since the RWE/VEW merger, RWE Gas ranks second among supraregional gas utilities. E.ON enhanced the group's position in gas retailing by completing the acquisition of Ruhrgas. Industrial CHP. Liberalisation has not improved the conditions for decentralised use of co-generation plants in general, due to the decline in electricity prices for industrial customers in Germany. The Federal Government strengthened the position of co-generation plants by law in 2002. Increased number of bilateral, physical and financial transactions and contracting possibilities. The typical system of long-term contracts will have to react to intense demands for flexibility on the part of many gas consumers. This will lead to shorter contracting, new forms of contracts, etc., including the establishment of a gas exchange. Prices as a result of competition. In the German gas industry, the gas price was tied to the price development of mineral oil, which resulted in competition between light oil and natural gas. This will not continue under the conditions of increased gas-to-gas competition. N e w marketing approaches. In the past, natural gas was sold by stressing environmental and other positive aspects of gas. In the future, other marketing aspects will take over such as the binding of customers, and better communication of prices and services.

These 11 points can be seen as the most relevant challenges for the GSI deriving from the opening of the gas market. The crucial factor for the functioning of competition on the gas market is the definition of technical, economical and legal details for TPA. The association agreements are a first step in this direction, but as in the German electricity sector, such agreements remain far behind the transparency of regulated TPA.

Literature

AG Energiebilanzen, (2002). Der Prim~irenergieverbrauch in Deutschland 2000/2001, www.ag-energiebilanzen.de. Autret, (2001). La fili6re gaz en pleine mutation, in: Regards sur l'6conomie AllemandeBulletin 6conomique du CIRAC, N~ 15-22, Florence.

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Baentsch, F., Kr/imer, H. and Mez, L. (1994) Die Umstrukturierung der Gaswirtschaft in den neuen Bundesl/indern und Berlin, FFU-Report 94-2, Berlin, Januar. Binde, W. (1999) Wettbewerb auf dem Gasmarkt: Status quo, Entwicklung, Chancen. VIK-Mitteilungen 2-1999, 26-30. Binde, W. (2001) Entwicklung der Liberalisierung des Erdgasmarktes in Deutschland. In: VIKMitteilungen 4-2001, 74-77. Bundesministerium ffir Wirtschaft (BMWi) (1998) Die Gaswirtschaft in der Bundesrepublik Deutschland 1997. Das Gas- und Wasserfach, 139(9): 505-555. Bundesministerium ffir Wirtschaft und Technologie (BMWi) (2000) Energie Daten 2000, Nationale und internationale Entwicklung, Bonn. Bundesministerium ffir Wirtschaft und Technologie (BMWi) und Bundesamt f-fir Wirtschaft und Ausfuhrkontrolle (BAFA) (2002). Erdgasdaten, http://www.bmwi.de. BGW (2002) BGW-Gas-Schnellstatistik, Erdgas in der Bundesrepublik Deutschland, http: / / 194.233.160.171/publik/4sta/2gas/erdgas.htm. Bfichner, H. (2001) Infrastrukturmarkt: Verifnderungen dutch Liberalisierung. IKBMitteilungen, 2/2001, 11-14. Burkhardt, A. (2001) Liberalisierung des Erdgasmarktes in den USA und DeutschlandUnterschiede. Energiewirtschaftliche Tagesfragen, 51(4): 212-216. Czernie, W. (1998) Die Europiiische Gaswirtschaft im strukturellen Wandeh Chancen und Risiken. Brennstoff-W/irme-Kraft (BWK), 50(7/8): 56-60. Deutsches Institut ffir Wirtschaftsforschung ( D I W ) (2001) Stagnierender Primifrenergieverbrauch im Jahre 2000. DIW Wochenbeficht 5/2001, 78-91. Deutsches Institut fiir Wirtschaftsforschung (DIW) (2002) Kfihle Witterung treibt den Prima'renergieverbrauch in die HiJhe. Der Prim4renergieverbrauch in Deutschland im Jahre 2001. DIW Wochenbericht 7/2002, 109-118. Hannes, B., Haag, W., Tenge, S. and Hillebrand, S. (2002) Auswirkungen der VV Gas II in der Praxis. Energiewirtschaftliche Tagesfragen, 52(9): 614-615. Hartmann, U. (1998) Aktuelle Fragen der Gaswirtschaft. Kommunalwirtschaft, 12: 634-637. Holst, K. and Altmann, W. (1995) Entwicklung der Ferngasversorgung Ostdeutschlands yon 1945-1995. g w f - Gas/Erdgas 136(6): 233-245. Karbenn, F. and Schenk, S. (1999) Energiehandel in der Gaswirtschaft. Energiewirtschaftliche Tagesfragen, 49(1/2): 24-27. Klag, N. (2002) Die Liberalisierung des Gasmarktes in Deutschland, Marburg, Tectum. Nieders~ichsisches Landesamt f-fir Bodenforschung (NLfB) 2001:Erd61 und Erdgas in der Bundesrepublik Deutschland 2000, Hanover. Niemann, H. (1997) 'Dornr~schenschlaf' der deutschen Gaswirtschaft? Das Gro)qsystem Ferngasversorgung im Spannungsfeld konkurrierender politischer und ~konomischer Interessen. Zeitschrift ffir Unternehmensgeschichte (ZUG), 1: 39-64. Polleit, H. (1998) Strategische Herausforderungen der Gaswirtschaft. Energiewirtschaftliche Tagesfragen, 48(3): 154-158. Ruhrgas AG (2000) The Natural Gas Industry in Outline, Essen. Schiffer, H. (1999) Energiemarkt Deutschland, 7. Aufl., Cologne: TOV-Verlag, Chapter 2.4 Erdgas', 128-149. Schuppe, T. and Nolden, A. (1999) Markt- und Unternehmensstrukturen im Europ~iischen Strom- und Gasmarkt (Stand 09/99), EWI Working Paper 99/1, Cologne. Specht, H. (2001) Gasbeschaffung im liberalisierten Energiemarkt. Vertragsgestaltung und Preisfindung ffir Sondervertragskunden. Cologne, Deutscher Wirtschaftsdienst. Timm, M. (1998) Gas-Renaissance in der deutschen Stromwirtschaft. Energiewirtschaftliche Tagesfragen, 48(7): 448-453.

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Ueberhorst, S. (1999) Energietr~iger Erdgas, Exploration, Transport, Versorgung, Landsberg/Lech. Wanke, A., Piening, A. and Mez, L. (1999) Chancen und Risiken innovativer Energiedienstleistungen in der Gaswirtschaft im internationalen Vergleich, Berlin, April 1999. Wirtschaftsverband Erd61- und Erdgasgewinnung (W.E.G.) (2002) Jahresbericht 2001, Zahlen & Fakten, Hanover. Witschen, B. (1998) Vom Verteiler zum Dienstleister - das GVU im ver~inderten Markt. Gas, 1/98: 8-11.

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Chapter 11 The French Gas Industry in Transition: Breach in the Public Service Model DOMINIQUE FINON

11.1. Introduction

France is generally viewed as the European country that most vigorously resists pressure to deregulate its national gas markets. The moderate reform that arose from the transcription of the European Gas Directive was voted in 2002 after a considerable delay. The main reason for this was the robustness of the French public service model, which has shaped the organisation of the gas industry in the same way as most of the network industries (Haywards, 1986; Frost, 1991; Stoffaes, 1995). This model is characterised by four elements: 9 a state-owned monopoly that concentrates ownerships of almost all the equipment and has a ministerial supervision influenced by the company; 9 a fully legitimate principle of equality for the supply of essential goods or services; 9 a strong interventionist economic culture aimed at national economic power and political independence, promoting national champions and seeking maximum industrial spin-offs; 9 a social industrial relations model, guaranteeing advantageous employment conditions and allowing strong identification of trade unions with public service and general interest. This public service model is to some extent flexible and allows public companies to adapt and modernise through autonomy of 245

246

National Reforms in European Gas

management, adoption of a commercial culture, and the creation of incentives for productivity gains. In some technology-based sectors, public companies have had opportunities to demonstrate both efficiency in long-term equipment programming and ability to improve production efficiency and commercial performance; this was the case in gas, electricity and telecommunications. To explain the institutional stability of the French gas industry, this chapter analyses its institutional trajectory shaped by the public service model and its strong institutional path-dependency (as defined by North, 1990), marked by resistance to change. The central hypothesis of the analysis is that as long as this model demonstrates economic and social efficiency in the development of gas supply in relation to the public services obligation and to control of the import dependence risk in the gas sector, no reform can be brought about by endogenous factors. Moreover, institutions strengthen themselves by gaining in economic efficiency and legitimacy. However, institutional stability is only possible in an insulated political and economic environment. The second hypothesis is that as the institutional environment has widened to include European Union regulations based on market-based principles aimed at integrating markets, there is a tendency to reduce institutional variety by coercion when it leads to inequity in the trade (Di Maggio and Powell, 1991). In other words, the European market integration process is slowly but steadily eroding the public service model in the gas sector. The reform process, begun in France with the delays of 1998 and concluded by the belated Gas Directive transcription voted in 2002, is a forced submission to the European integration process run on market-based principles. Even if preserved by a minimalist reform, the public service model is still at odds with the general trend of institutional and industrial changes in European gas markets. Heterogeneity of market rules and property regimes between European countries will lead to the passing of new European rules in years to come. Moreover, in Europe's increasingly competitive and integrated energy markets, traditional gas companies and especially public and semi-public companies must change rapidly to survive. New risky conditions in the future, bulk purchases by producers, and de-integration of the gas value chain with the threat of entries on one hand and the risk of takeover by oil companies or major electric utilities after privatisation on the other hand, will require strategic alterations if companies are to survive. Therefore, the French public gas company's adaptation by partial upstream integration into foreign gas production and by geographic diversification in its core business

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247

leads to destabilisation of the public service model concentrated on satisfying strictly national needs; this does not allow a competitionbased and international corporate logic. Moreover, the competition paradigm and the learning process with the new even moderate market rules is spreading (Stern, 1998). The hybridisation of different types of institutional arrangements and contradictory concepts is leading, through progressive loss of consistency and change of dominant representation, to an institutional realignment. The analysis of the French gas industry transition comprises four sections. A survey of its historical development is followed by its organisation and regulation under the public service model and its performance in terms of social and economic efficiency. The third section presents the minimalist reform for transcribing the European Directive in the French law, in order to identify its potential effects in terms of competition development and public service erosion. Finally, in the fourth section, the industrial policy option to preserve the existence of a French single-energy company and its consequences in terms of strategic adaptation are discussed.

11.2. Development of the French Natural Gas Industry The integrated industrial organisation, established in France by the 1946 nationalisation law, allowed the fragmented system, based on city gas networks, to be transformed in just 15 years into an interconnected system based on natural gas. The stimulus to develop the French natural gas industry came from the beginning of operations, in 1956, on the Lacq deposit discovered in Aquitaine in 1951, production from which reached a peak of 11 bcm in 1978. The centralisation allowed coordinated development of the high-pressure transport network interconnecting the regional networks with storage units and supplies of gas of differing qualities and origins (Beltran and Williot, 1992). Large underground storage areas were also completed (13 ground aquifers, 2 saline cavities) with a total useful capacity of 116 TWh, corresponding to 25% of the annual consumption, to compensate for interruptions in supply and manage seasonal variations in national demand. Given the uneven and relatively low density of population, this organisation also allowed the local distribution networks to develop steadily. The number of customers connected increased from 6.1 million in 1960 to 8.25 million in 1980 and 10 million in 2000. Since 1965 the French market has steadily increased its imports of LNG from Algeria (1965) and natural gas from the Netherlands (1967), Norway (1971) and the Soviet Union (1972). The increased need for

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gas imports led to diversification in s u p p l y sources and entry points. Imports make up 95% of the offer, with French production being limited to 2.5bcm in 2000 (See Table 11.1). However, between 1973 and 1990 increases in sales were restricted, because of the priority given to the promotion of uses of electricity in conjunction with the priority for d e v e l o p m e n t of nuclear p o w e r (Chevalier, 1993). Sales increased by a mere 11 b c m / y e a r d u r i n g this period, compared with about 30 bcm in Italy, G e r m a n y and the UK. Although the proportion of gas in p r i m a r y energy supplies is small in comparison with other European companies, totalling 14% in 2000, the final market is relatively mature. Gas will not conquer those areas of the domestic heating market that escaped it, because of the promotion of electrical heating until 1992. Finally, outlets for gas in electricity production are greatly restricted by the existence of recently constructed nuclear p o w e r stations. Official forecasts predict a total of only 18% of all consumption in 2020, with requirements totalling 5 7 b c m (Commissariat General du Plan, 1998); this does not portend a radical development in the gas system (See Table 11.2).

Table 11.1. Origins of French gas supplies between 1973 and 2001 (in TWh*).

1973 1980 1990 2000 2001

France

Algeria Netherlands Norway

81.3 (45.1%) 81.3 (29.2%) 32.5 (9.2%) 17.4 (3.7%) 18.1 (3.9%)

18.0 (10%) 22.9 (8.2%) 104.4 (29.7%) 112.9 (24.0%) 113.4 (24.9%)

80.7 (44.9%) 108.9 (39.1%) 42.3 (12%) 55.5 (12%) 55.4 (12.1%)

Russia

Others

Total 180

27.0 (9.7%) 63.1 (17.9%) 140.3 29.9%) 135.8 (32.1%)

38.4 (13.8%) 108.9 (31%) 133.6 (24.1%) 114.7 (25.2%)

278.5 351.2 28.8 (6.2%) 34.8 (7.6%)

471.1 454.1

"1 Bcm = 10.8TWh.

Table 11.2. Comparisonof gas market shares and dependency rates in 2000. United France Germany Italy Netherlands Kingdom Consumption (Bcm) Gas consumption per capita (toe/cap.) Share in energy consumption (%) Dependence

40.5 590 13.7% 97%

Source: IEA, Natural Gas Information, 2001.

87.7 879 21.5% 87.5%

70.4 48.7 1002 2185 33.9% 46% 81.5% (exporter)

101.5 1467 37.6% 2%

The French Gas Industry in Transition

249

11.3. Organising and Regulating the French Gas Industry: the Efficiency of the Public Service Model At a time when the gas industries of Europe are being liberalised, the French gas industry is the most heavily State-controlled and the most integrated both vertically and horizontally, at both transport and distribution levels. It does however have one of the lowest levels of integration between production and transport/distribution, and this was the case when there was significant natural gas production capable of supplying 65% of national gas requirements. The organisation was submitted to stringent governmental supervision and regulation, and was heavily restricted by energy policy goals. However, it showed good economic and social efficiency with moderate prices, well-managed dependence risks and territorial extension of the distribution networks.

11.3.1. Legal framework and industrial organisation until 2002 The legal regime is essentially based on the 1946 gas and electricity industry nationalisation law, which led to the creation of Gaz de France (GDF) and Electricit6 de France (EDF). Few alterations were made between that time and the law transcribing Directive 98/30, voted in 2002. The 1946 law did not lead to such heavy organisational centralisation in the gas industry as in the electricity industry, as nationalisation of gas carried less credibility. Most notably it excluded the production of associated natural gas that had occurred before, this exclusion extending to the exploitation of all new natural gas deposits in 1949 (through the Armengaud law). This led to a relatively complex industrial structure, which reflected the balance of strength between GDF and the French oil companies between 1945 and 1965 (Beltran and Williot, 1992); and the balance led to the setting up under the aegis of GDF of an industrial organisation partly integrated in bulk purchase, transportation, distribution and supply but with very little integration between production and downstream. I m p o r t a t i o n - The law of 1946 granted a monopoly to Gaz de France, a monopoly that will be abolished by the 2002 Gas Law in order to free up supplies to eligible consumers. Production and vertical i n t e g r a t i o n - In natural gas production, Gaz de France has been totally absent from France, but since 1998 it has begun to have a presence abroad through share participations. Elf-Aquitaine (formerly SNPA), has provided almost all of French production through the exploitation of the Lacq deposit.

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Table 11.3. The structure of the French Gas Industry before the reform of 2002. Activity

Status

Company

Domestic production Imports Transportation and storage

No legal monopoly Legal monopoly No legal national monopoly State concession for each pipe

Distribution

Legal monopoly of distribution concessions to GDF Exception of municipalities (5%)

TotalFinaElf GDF GDF CFM (GDF 55%, TotalFinaElf 45%) GSO (TotalFinaElf 70%, GDF 30%) GDF 16 r6gies or mixed capital companies

The t w o French oil c o m p a n i e s that m e r g e d at the end of 1999 w e r e also active in gas p r o d u c t i o n w o r l d w i d e (14.4 b c m for Elf-Aquitaine a n d 1 6 b c m for Total in 1996) a n d in E u r o p e (10 b c m a n d 5.4 b c m respectively), but they h a d no direct outlets for their foreign p r o d u c t i o n in France until the 2002 reform. Because of GDFs m o n o p o l y on imports, Elf-Aquitaine has h a d no chance to control the offer of gas i m p o r t e d to its regional distribution s u b s i d i a r y Gaz d u S u d - O u e s t (GSO) to c o m p e n s a t e for the decline in the Lacq deposit (Table 11.3). T r a n s p o r t a t i o n - Three c o m p a n i e s are present, in three distinct areas: Gaz de France, w h i c h covers t w o - t h i r d s of French territory; Gaz d u Sud-Ouest, a 70% joint-stock c o m p a n y controlled by TotalFinaElf (formerly Elf-Aquitaine); a n d C o m p a g n i e Fran~aise d u M 6 t h a n e (CFM) w h i c h is present in central France a n d 55% controlled b y GDF. 1 Until the n e w Gas Act, however, the functions of these last t w o c o m p a n i e s will be limited. First, their m a r k e t is limited to industrial sites c o n s u m i n g over 0.5 million cm and the few nonnationalised local distributors in their area. They thus sell respectively 3% a n d 6% of gas c o n s u m e d in France to a b o u t 500 industrial clients, that is, 25% of industrial sales. For the rest, they p r o v i d e GDF w i t h t r a n s p o r t a t i o n services to GDF's distribution units a n d to the small industrial c o n s u m e r s served directly by the 1In transportation, the law specified that the State owned the transport pipelines and would grant them by a concession to the company of its choice, which would be responsible for developing and exploiting them in the context of the terms of reference defined in 1952. For the concessionary company, however, it laid down a clause stating that at least 50% of the capital must be publicly owned 'in order to apply the controls necessary to ensure safety of supplies'. (This minimum was reduced to 30% by an amendment voted in 1985).

251

The French Gas Industry in Transition Table 11.4. Transportation assets and final sales of the French companies in 1999. Regions GDF

2/3 of national territory

Compagnie Fran~aise du Methane (CFM) Gaz du Sud-Ouest

Centre

South-West

Transmission Pipelines

Storage units

Final sales

6.77% (21658 km)

13 units (97.5 TWh)

88% (9.44 million customers) 6% (302 customers)

2 units (21.8 TWh)

3% (176 customers)

20% (6352 km)

12.2 % (3930 km)

(GSO) Distributors

Bordeaux, Strasbourg, Grenoble, etc

3% (420,000 customers)

Source: Secretary of State for Industry. White Paper on Gas Reform, 1999.

transportation network. Second, CFM was essentially an 'empty shell'. The Centre Region's network concession has been granted by the State to GDF, which is responsible for developing it and leases it out to CFM, meaning that CFM is thus only a seller of transportation services. Therefore, because of its hold over CFM, Gaz de France controls 87.7% of the transport pipelines, 80% of storage capacity and 75% of industrial sales from high-pressure networks (Table 11.4). Distribution - While the previous regime was one of concession granted by the local communities that owned the networks, the 1946 law granted a monopoly of local distribution concessions to GDF. The only exception was a few municipal companies with the status of 'r6gies' or mixed economy companies with a public shareholding majority. The 16 non-nationalised distributors, some of whom are located in sizeable cities (Bordeaux, Strasbourg, Grenoble) hold only 4% of the low-pressure pipelines and produce 3% of sales. 2 This structuring of gas distribution in France has one major distinctive feature: these activities belong to a gas and electricity distribution division common to EDF and GDF, with commercial units common to both public companies. This association has had significant effects on competition between gas and electricity, by inhibiting competition in commercial and domestic use, and this has allowed the commercial development of the gas industry to be controlled.

2In addition, GDF has shares in the stock of some of them (24.5% in Strasbourg, 16% in Bordeaux, 4% in Grenoble).

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National Reforms in European Gas

11.3.2. Regulation and Governance of the French gas industry The State plays a major role in strategic choices and in the regulation of the gas industry. During the last 50 years, this role has changed as the State has become modernised, but it has never been questioned. Since 1991 it has been based on a contractual relationship between the government and GDF.

Submission of the gas industry to government policies: the general economic interest Since the 1920s energy policy has been taken care of by the State and treated as a priority for limiting energy dependency in order to protect energy supplies from short-term market effects and sovereignty risks. After the Second World War, the State intervened through public companies in the different energy industries and by defining energy policies. The main objectives were to develop secure supplies for the country at reasonable costs in the long term, and to limit energy imports in the balance of trade (Finon, 1996). Gas imports could only contribute partially to these two goals through the development of diversified imports. It is against the background of these principles that development of natural gas has been restricted since 1973 because of the priority given to the nuclear programme and the promotion of use of electricity for 20 years (Criqui et al., 1984). Moreover, for foreign policy reasons, long-term gas import contracts must be given ministerial approval for signature in order to control the import risk from non-European countries. The present policy adopts the same moderate line: interest in the attractiveness of gas as a clean fuel and as a means of diversifying supplies, but caution about the extension of its share in the energy supply for two reasons: the geostrategic effects of dependency on imports from unstable countries and the long-term limitation of global resources (Commissariat General du Plan, 1998; White Paper on Gas, 1999). In this general energy policy framework, the general interest in gas supply through imports is formulated in order to secure gas supplies at low cost through diversification and, more recently, through overseas investment in gas resources and transportation. The gas industry was also used for other political goals. For industrial policies, successive governments used import contracts to promote French exports of industrial goods to Algeria, Norway and Russia (Estrada et al., 1988). Public procurements for GDF equipment were also considered as a way of promoting French LNG technology and other gas equipment. Downstream, the defence of industries

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253

using gas as a m a i n resource justified special contracts for some chemical sites (fertilisers) in the 70s and 80s with negotiated prices based on internal preferential prices in the Netherlands. Foreign policies have on occasion interfered with gas imports, as in 1981-82 w h e n the n e w left-wing g o v e r n m e n t desired to p r o m o t e n e w N o r t h South relations in the international arena. It compelled GDF to accept a generous price, 13.5% above the average European import price ($5.12 per mBtu) for the new contract being negotiated with Algeria.

The incorporation of the public service standard into gas supplies The content of the public service standard has been a d a p t e d to the specific features of the gas sector. In its general sense, this standard, which is strongly rooted in the administrative law, requires customers to be p r o v i d e d with essential goods and services as inexpensively as possible, w i t h o u t discrimination and with constant adaptation to changes in technology and d e m a n d for supplies. Generally speaking, non-discrimination implies equality of treatment and territorial equalisation of tariffs; but gas, unlike electricity, is not defined as an essential supply. The obligation of supply, therefore, does not require gas distribution networks to be developed extensively to cover the national territory, and the national c o m p a n y m i g h t refer to its normal rate of return on investment of 12% w h e n deciding to set u p n e w local distribution networks. The obligation is limited to an obligation of connection in the area covered by the distribution n e t w o r k and to an obligation to serve connected consumers. However, there is an element of tension b e t w e e n GDF's legal q u a s i - m o n o p o l y of s u p p l y legitimised by the public service standard, its profitability criteria w h e n required to cope with the economic constraints of extension of the distribution networks, and the wish of municipalities to have a gas network that allows their citizens to benefit from the advantages of gas supplies. 3

3At present, about 6,800 of the 36,500 local communities are equipped with gas distribution networks, representing 72.6% of the population. However, 26 rural departments with scattered populations have a connectable population rate of less than 10%. Until 1999 it was up to GDF to decide which areas it will supply. Normally it has connected about 200 small towns each year, subject to a profitability criterion of 12%. However, the rate would have been greater without GDF exclusivity, simply by reference to the public discount rate of 8%. Neighbouring local communities of areas equipped by a gas network claimed that they wished to develop gas distribution in new areas, but were prevented from doing it by GDF's exclusivity. After much controversy during the nineties a legal amendment was voted in 1998, allowing local communities excluded from GDF's third year extension programme to contract with independent developers (Masson, 1991; Assembl6e Nationale, 1998).

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National Reforms in European Gas

Concerning geographical equalisation of tariffs, as with electricity, regional differences in transport and distribution costs, caused by French territorial diversity in demographic and industrial density, have justified a certain difference in gas prices between regions. Moreover, gas is under pressure of competition from other energies, necessitating marketing practices and industrial price discriminations that oppose the egalitarian principle, but this has been accepted as a reflection of the necessities of competition.

The contractual regulation of the public monopoly The gas industry and the public company are under the supervision of the Ministry of the Economy and Finance and the Ministry of Industry. This regulation originally covered tariffs, cross-subsidies, product quality, safety standards and investments. The ministries agree on the rules for defining gas tariffs and issue a price increase authorisation twice a year. Since 1985 GDF has been free to determine industrial prices, provided they simply inform the ministries about the new price lists. On the other hand, residential and tertiary prices have remained controlled. Finally, the ministries control the allocation of the monopoly rent to activities outside the core business and to international investments: the former is controlled by a special supervision committee established in 19954 and the latter by an authorisation procedure, and a limitation is put on the self-financing of GDF's international investments and defined in the three-year 'contrat d' entreprise'. GDFs relation to the State has been organised on the basis of a contractual and incentive-based regulation since 1991, with three-year objective and performance contracts. The aim of these contracts was to limit the instrumentation of the public company by giving it greater managerial autonomy and real incentives to improve its performance. The dependency of GDF's overall expenses on outside factors (import purchases weighted to a m a x i m u m of 63% in 1985) has outlasted the opportunity for organising such a contractual relation because of the 4This committee controls EDFs and GDFs diversification activities. The rules, dictated in 1994 by a special commission known as the Commission Guillet, greatly limit activities outside the core business: TV cabling, urban waste, management and operation of heating appliances. GDF has to 'unbundle' its accountability for each of these activities by subsidiarising them. The supreme administrative court (Conseil d'Etat) refers to the so-called 'speciality principle' for public service monopolies, forbidding or greatly limiting their diversification. In fact, their monopoly advantages and public service function are considered to be incompatible with diversification outside their core activities.

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considerable uncertainty in relation to imports. Within the framework of the general functions of public service, the contracts specify the economic performance level to be reached and the strategic industrial objectives of GDF; the company has almost free rein regarding the means to adopt to reach the targets. The contracts have four main structural elements: economic and financial targets (under a price-cap incentive the contracts oblige GDF to pass-through half of its productivity progress on the corresponding portion of the tariffs), commercial targets (development in domestic heating and in co-generation), public service targets (development of new local distribution networks), and business development (internationalisation, upstream integration into production, etc.). 5

11.3.3. Efficiency of the public gas company The French public organisation has proved efficient in terms of the targets set by the Government, showing itself capable of developing gas supply and adapting in order to improve its productivity when managerial independence was granted to the public gas company after 1990. Price regulation has always limited profits gained, and this has favoured French consumers, as prices are established below the average European price level. Gaz de France has usually proved efficient in the development of infrastructures (transportation, storage and distribution) and in the negotiation of import contracts with seller countries, and as a full member of the club of major European purchasers. It played an active part in the consortia that negotiated with Algeria, Iran, Nigeria and Norway (especially for the Ekofisk contract of 1975 and the Troll-Sleipner contract of 1986-87) (Estrada et al., 1988). When the failure of the Algerian LNG chain in 1974 proved that a supply mostly based on imports was vulnerable, GDF responded by rapidly increasing the integration of its system, installing underground storage reservoirs, and developing interruptible contracts. It looked to diversify its supplies by going to four suppliers. This policy has necessitated a high level of annual investment of around C0.9 billion (in real terms), which is significant compared to a cash flow of around C3.8 billion. The aims of energy and macroeconomic policies have, however, had an adverse effect on the profitability of the French gas company. Since 5For instance, the 1997 contract specifies the restrictions that frame this strategy, particularly the amount of cash flow that can be used for the international development (FF5 billion between 1997 and 1999). Development all along the supply chain with partial vertical integration in production in up to 15% of its outlets, is assigned to GDF for corporate and economic reasons (see below).

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the first 'oil shock' before 1990, GDF has been held back in its commercial development policy by the priority given to the nuclear power option and by differences in the tax treatment of the different power industries. 6 Annual gas consumption increased only by 4.0 bcm between 1980 and 1990. GDF could not therefore benefit from the automatic increase in productivity that followed sustained increases in the geographic density of gas consumption, while the lower density of population in France was already restricting the average profitability of investments in gas transport and distribution. The policy of bringing inflation under control also led the government to drastically restrict increases in gas prices between 1980 and 1985, following the second 'oil shock' and the new rise in the dollar in 1980, and this caused GDF to suffer very substantial losses because of the increase in the price of imported gas indexed on oil prices. Faced with these major financial burdens, GDF's level of debt rose from C1.21 billion in 1980 to C5.45 billion in 1984, producing a very unfavourable d e b t / e q u i t y capital ratio (2.4 in 1984). 7 In comparison Ruhrgas and SNAM have always enjoyed a larger share of gas profits than GDF; this shows in the absence of debts and increased equity capital levels. This double restriction, which was a major handicap to return on capital, did not however prevent GDF from making the developments necessary for imports and for installing infrastructures with the aim of following growing needs; it was however based on finance through debt. Financial consolidation began when GDF emerged from the 'squeeze' between the very high prices of imported gas indexed directly on official oil prices and the rigid anti-inflationary control of its prices. In 1985 and 1986 GDF renegotiated its import contract indexation clauses: with the USSR and the Netherlands, an indexation on oil products (heavy oil and domestic fuel oil), based on the netback principle, was adopted, with the costs of transporting Soviet gas across Germany deducted; 8 the additional p r e m i u m in the 1982 contract with Algeria was abolished, with the introduction of an

6The level of the local tax on gas is 5.6% for industrial consumers while the heavy fuel oil does not support such a charge. 7Without inclusion in the accounts of the value of the transport and distribution assets, which legally belonged to the public authorities, the equity capital was negative during this period. 8In international contracts from before this date, the formula for defining contractual prices depended on the official oil price. After renegotiations, the formula of definition and indexation was a function of the pondered price of oil products, less the adjustments for taxes and transmission-distribution costs (along the method of 'net back' calculation).

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Table 11.5. Changes in GDF's financial characteristics (in current money and Cbillion).

Turnover Profit (after tax) Investments Debt

1980

1985

1990

1995

1999

2000

2001

3.28 0.01 0.51 1.60

8.48 0.07 0.63 4.67

6.33 -0.01 0.67 3.03

7.82 0.28 0.93 2.20

9.1 0.4 1.35 2.04

11.21 0.43 1.54 3.33

14.4 0.91 1.7 3.4

Source: GDF Accounting reports. Table 11.6. Improvements in GDF's productivity.

Number of employees per TWh Net expenses per TWh* in C million

1985

1990

1994

1996

1998

2000

94 7.35

83 9.36

71.7 10.66

59.5 9.15

57.3**

54.8**

7.25

7.1

*Expenses without gas cost and tax, and in real terms (1998 reference). **Employees in France. Source: GDF Accounting Reports. indexation f o r m u l a based on real prices a n d not on official crude prices. 9 The change in p o w e r balance b e t w e e n p u r c h a s e r s and sellers s u b s e q u e n t l y allowed GDF to negotiate all n e w contracts on the basis of the netback principle, transferring the price risk to the producer. In the same way, the n e w flexibility clauses negotiated d u r i n g this period allowed significant overcapacity in i m p o r t contracts to be a v o i d e d d u r i n g the 1990s (Table 11.5). The ministerial regulator also allowed GDF to r e t u r n to financial equilibrium, defining price changes that r e m a i n e d regulated but allowed GDF to p r o d u c e a positive result for the rest of the decade. GDF b e g a n to r e d u c e its debt levels w h e n prices of oil p r o d u c t s a n d i m p o r t e d gas fell. This contractualisation process led to real d y n a m i s m in GDF's m a n a g e m e n t in the first three contracts b e t w e e n 1992 a n d 2000, as w i t n e s s e d b y the increase of its commercial strategy in space-heating, h i g h - p e r f o r m a n c e industrial use and co-generation a n d the definition of an internationalisation strategy (see below). The efforts a i m e d at p r o d u c t i v i t y allowed costs (apart from gas costs) to fall from 1994 o n w a r d s , w h e n capital costs decreased sufficiently as debt levels decreased. The business's financial profile has i m p r o v e d steadily (Table 11.6).

9These corresponded to 40% of sales (1,300 industrial clients) and to 25% of the turnover. GDF immediately increased its industrial tariff by 6%.

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National Reforms in European Gas Table 11.7. Comparisonof gas price decrease in industry and households in selected countries between 1991 and 1999" (in current terms).

France Germany Italy The Netherlands UK

Industrial prices

Residential prices

-10.6% -19.7% 0% -11.4% -35.3%

-16.8% -10% -16% 0% -18%

Notes: The reference dates 1991 and 1999 have been selected in relation to the similarity of oil prices on these dates: 19.30 $/bn in 1991 and 17.26 $/bn in 1999; the prices are with non refundable taxes and VAT. Source: Calculated from IEA, Energy prices and taxes, Paris, OECD, 2002. Gas consumers have been able to benefit from continuing price reductions, in real terms, since 1985; these reductions are amongst the most substantial in Europe (Table 11.7). A comparison of gas prices for different types of use (based on IEA's data) shows that industrial prices in France have been a m o n g s t the most favourable in Europe, the only exception being the United Kingdom, since the increase in competition from 1994 onwards. On the other hand, domestic rates are relatively high, particularly for small subscribers, and reflect a distribution cost that remains high because of the lower average relative density.

11.3.4. The limits of the public organisation The theory traditionally attributes lack of incentive for productive efficiency to the m o n o p o l y regulation. Public ownership was itself a cause of inefficiency, especially because of superimposition of public policy objectives and the rationale adopted by the bureaucracies (maximisation of budgets, technological performance, etc.). These faults are evident, to a lesser extent, in the French gas industry. There is no doubt that the public nature of the industry requires it to protect jobs and wages, leading to high labour costs and restricting progress in productivity. 10 The heavy public policy restriction imposed on GDF (limited potential outlets, controls against inflation etc.) weighed quite heavily on its commercial d y n a m i s m and the possibility of reducing its unit costs through increased sales until 1990. H o w e v e r GDF, compelled to remain in its core business and limited in the increase of its outlets because of the priority given to 1~ average labour cost is reckoned to be 40% higher than the average for the manufacturing industries.

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electronuclear power, could not allow itself to follow the bureaucratic logic of the other French public enterprises, which had the opportunity to embark on a major national project, such as EDF or France-T616com. In spite of all that, it has not fully escaped the risk of technocratic change in its two most legitimate activities: negotiation of international contracts and major equipment. 9 The major contracts signed in the 1980s, which referred too optimistically to a hypothesis of 4% increased growth in the French market, tended to create overcapacity of about 1-2bcm per year between 1989 and 1995, in relation to the minimum take-off clauses; 11 9 Developments in storage capacity, which requires complex and high-level engineering and the application of specific skills, have been excessive as they were based on an overestimation of the vulnerability of external supplies. To sum up, centralisation of the French gas industry on GDF has shown good economic and social efficiency despite the restrictions imposed on its development by the SNPA, then by Elf-Aquitaine's pressure to extract gas rent on the bulk supplies made to it, and finally by the nuclear policy priority. Given the paramount importance of energy independence criteria in the French energy policy, the increased dependency of gas supply on imports strengthens GDF's institutional position and demonstrates its ability to diversify imports and manage dependency risks. In spite of some tension over the extension of gas distribution networks to cover financial and public service criteria, gas supply has been economically and socially efficient with good price-level performance. Moreover, since 1985, the public monopoly has shown a good capacity for improving its productivity, reducing debt levels and developing a dynamic industrial strategy after a long period of restrictive governmental regulation. Gas reform in France has therefore been brought about by prescriptive European Union legislation. French public authorities and economic agents were satisfied with the organisation of the gas industry, with its opportunity for controlling choices of imports and ensuring at the same time that the public gas enterprise is managerially autonomous and develops an industrial strategy. Gaz de France was considered to be an efficient public company with moderate prices and no deficit. Other institutional path-dependency elements such as the attachment of identity to public service, the nationalist 11Average growth in the market has been only 3% since 1990. The surplus was used to increase the quantity of useful gas in stock by 66.6TWh between 1987 and 1995.

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a p p r o a c h to e n e r g y d e p e n d e n c y , the i n t e r v e n t i o n i s t t r a d i t i o n of n a t i o n a l c h a m p i o n p r o m o t i o n a n d the t w i n n i n g of institutional a r r a n g e m e n t s in the gas a n d electricity industries, i n f l u e n c e d the r e l u c t a n c e to r e f o r m a n d the c o n s e r v a t i s m of the gas reforms.

11.4. The Choice of a M i n i m a l Liberalisation Reform The p r o c e s s of r e f o r m in the F r e n c h gas i n d u s t r y is well b e h i n d that of o t h e r E u r o p e a n countries (Germany, Spain, H o l l a n d , Italy, etc.) in w h i c h the n e w legislation w a s a d o p t e d in 1998 a n d 1999, to say n o t h i n g of the successive r e f o r m s m a d e in Britain since 1986. The gas r e f o r m act w a s only v o t e d at the e n d of 2002, well past the d e a d l i n e of A u g u s t 2000 i m p o s e d b y the E u r o p e a n Gas Directive ( E u r o p e a n C o m m i s s i o n , 1998) a n d f o l l o w i n g a f u r t h e r political p o s t p o n e m e n t in April 2001.12 D u r i n g the transition p e r i o d b e t w e e n A u g u s t 2000 a n d the p u b l i c a t i o n of the decrees i m p l e m e n t i n g the f u t u r e law, G D F a n d GSO i m p l e m e n t e d the rule of third p a r t y access (TPA) for eligible c o n s u m e r s in a d i s c r e t i o n a r y way, b u t u n d e r the aegis of the s u p e r v i s i n g ministry; 13 this has h a d s o m e impact, w i t h s o m e entries on the eligible s e g m e n t . The r e f o r m v o t e d in 2002 is m i n i m a l , w i t h a functional u n b u n d l i n g , m i n i m a l o p e n i n g of the final m a r k e t , a n d n o c h a n g e in the i n d u s t r i a l structure, especially the c o n c e n t r a t i o n of c o n t r a c t u a l gas i m p o r t s in G D F ' s h a n d s . T h e r e is no m e a s u r e in

12An initial official ministerial paper, the Mandil Report, published in late 1993, dealt jointly with the gas and electricity industries when specifying France's official position in the discussions on the two electricity and gas directives, a position based on the 'single buyer' principle (Minist6re de l'Industrie, 1993; see Secr6tariat d'Etat l'Industrie, 1999). The second stage of the process did not begin until the autumn of 1998, after the Gas Directive had been passed. The definition of the main directions to be taken by the reform was preceded by a consultation phase aimed at bringing about a level of legitimacy capable of reconciling competition and public service. An official report was published in June 1999 by the Ministry of Industry, specifying the various elements in the debate. After a parliamentary report drawn up in the autumn of 1999 (Bricq, 1999) and a debate with the interest groups involved, the draft law was ready to be voted by Parliament in May 2000. However, in April 2001, after the results of local elections did not favour the left-wing coalition, the vote of the law was postponed until the end of 2002, after the presidential and parliamentary elections, for the sake of the governmental coalition and against the wishes of the ministerial authorities involved and GDF's management. In May 2001 the European Commission commenced a lawsuit in the European Court at The Hague for non-application of a European directive, concluded at the end of 2002. 13The eligibility conditions, the transparency of conditions of access to the transport system (tariffs, technical conditions, balancing services) and the Chinese Wall conditions respect the principle of Directive 98/30/CE.

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anticipation of the next Directive to be voted in 2003, that will require legal unbundling of the transmission network.

11.4.1. Reluctance to adapt to the European instructions

There has been no coalition of economic and political actors demanding a radical change by showing up real or supposed faults in the industrial organisation. The potential entrants, such as the French oil companies and the diversified water distribution companies (Vivendi, Suez-Lyonnaise, SAUR-Bouygues) showed little interest in the gas supply business in France during this period. The industrial gas consumers, especially the major ones, which benefit from favourable sale conditions by GDF, did not campaign actively. Instead, there was a vast coalition of actors generally opposed to the questioning of the public service model in the network industries: trade unions, State engineers in the Ministry of Industry and in the Boards of Directors of public companies, and both left-wing and major right-wing political parties. With regard to the liberalisation of the gas market, the coalition was divided into two currents: 9 The 'liberalising' current, influenced by rapid changes in other European countries. Less readily impressed by the ideal public service image of the gas business than by that of the public electricity business, it is interested in integrating 'market-oriented' rules in the reform and in GDF's corporatisation and partial privatisation, while maintaining vertical integration. Ministerial administration is found in this current, which was joined in late 1999 by GDF's management who were willing to follow the European movement and in 2001 by part of the left coalition government and some of the trade unions. The right-wing government elected in Spring 2002 followed this political line and actively promotes the new legislation. 9 The egalitarian and centralising current, which is hostile in principle to the concept of the 'market' and wields national interest, public service and in the last resort French identity in order to preserve the old organisation as far as possible; this trend attracted all the trade unions and left-wing parties, with the communist party making the defence of EDF and GDF a particular stake in the joint programme of the coalition government between 1997 and 2002. Because of this influence, the parliamentary discussion of the gas act was postponed after the presidential elections held in spring 2002.

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The energy networks are subject to greater political resistance than the networks open to international markets (airways, telecom) for two reasons. They are not by nature a field for globalised markets for their outputs, although their supplies comprise resources deemed to be strategic; they are the subject of a nationalist reaction, and they are seen to be efficiently managed by the public enterprises GDF and EDF, unlike other public companies such as the railway company SNCE The defence of general economic interest and public service is subsequently given first priority in order to justify the preservation of integration, altering it only on the edges by introducing a limited TPA rule with minimal eligibility for consumers. 9 General economic interest. Under the influence of representations from the dominant operator, the opposition by the French public authorities to the principle of liberalising access to the network had its roots in the planning principle for developing a gas system. This principle consisted of anticipating growth in demand by making long-term capital-intensive import commitments. The existence downstream of a supply monopoly able to guarantee outlets and income is essential for setting up the long-term contractual arrangements based on TOP clauses, which are the only ones that even allow large-scale pipeline import operations such as Troll ($16 billion), Yamal or the new LNG chains. The complete import dependency of the French market is the second reason for the reluctance to open the market, because of the geostrategic risk associated with imports from unstable countries outside Europe (Minist6re de l'Industrie, 1999). The same applies to access to the storage capacity, which is considered to be an element of strategic control on the import risk. 9 The public service. Even though the supply of gas is not fully defined as a public service, the public authorities are still in favour of the principle of a single distribution operator. The preservation of horizontal integration within GDF also shows this advantage. It allows it to have sufficient capacity to mobilise capital for extending distribution networks in the direction of the general interest, without having to resort to raising finance through a 'general interest charge' (White Paper, 1999). 11.4.2. The choice of the minimalist option in the Gas Directive menu The 'Energy markets and Public Service' Act (Poniatowski, 2002), voted at the end of 2002, specifically defines the general economic interest content and the public service obligations for justifying

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retention of the pillars of the former organisation and regulation. 14 Preserving vertical and horizontal integration implies defence of GDF's exclusivity in distribution licensing, and the absence of provisions aimed at subsidiarising transmission and storage to help non-discrimination in access to the network. However, it establishes the two regional pipeline companies (GSO, CFM) as operators equivalent to GDF in systems operation in high-pressure and medium-pressure transportation. 11.4.3. Market opening rules The law strictly follows the minimum level of eligibility of 25 mcm/year in 2000, 15mcm/year in 2003 and 5 m c m / y e a r in 2008, defined by the Gas Directive. Multi-site aggregation is not allowed. As far as eligibility in electricity production is concerned, the flexibility allowed by the directive (Article 18.2) limits it to co-generation up to the current normal threshold. The eligibility of the 16 municipal distributors is fully recognised. Because of the eligibility limits and the small potential for development of gas power production by IPP entries or co-generation on site (because of nuclear dominance), the competitive share of the French gas market will stay at the minimal level laid down by the 1998 Directive: 20% in 2000, 28% in 2003 and about 33% in 2008.15 11.4.4. Conditions for access to the gas system As the Gas Directive only required unbundling in accounts for the vertical gas companies between transmission, storage, distribution and other activities, the French government is not seeking legal unbundling of the networks within the three gas system operators nominated by the law (GDF, CFM and GSO). The law defines some rules of confidentiality within them for the protection of bilateral transactions between third parties, and GDF chose to clearly separate its transportation activities from its supply and marketing activities for non-discrimination guarantees. Moreover, transparency is sought with the choice of a quasi-regulated TPA, but with limitations in access to the storage capacities. A regulated T P A - The law defines a regulated TPA to the highpressure and medium-pressure system, the distribution networks 14Its heading is quite general: 'Law relating to energy markets and to the public service', because it also includes some amendments of the law on electricity regulation. 15Thenumber of industrial sites affected by eligibility would have increased from 150 in the first step (to 2003) to 300 between 2003 and 2008, and finally to 720.

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National Reforms in European Gas

and the LNG equipment. It requires the tariff lists to be published and defines some principles of price calculation: cost-reflectiveness, which involves integration of d e v e l o p m e n t expenses (Article 5). 16 TPA is negotiable only for very large transit contracts; specific conditions on TPA rules can be negotiated w h e n justified u n d e r the control of the regulator w h o could require them to be published. 17 The law also includes an obligation to publish a grid code, which specifies the technical conditions of access. Rules of priority are specified for suppliers to non-eligible consumers. (other priorities will be based on the normal capacity reservation procedures). No access to storage capacities. Taking into account GDF's reluctance to open access to its storage capacity in order to preserve competitive advantage, the g o v e r n m e n t has only included in the law a little allowance for virtual access to storage capacities with the offer of balancing services, within the limit of capacities available after their use for public service missions and the overall balancing of the system (Article 30). 18

11.4.5. Creation of an autonomous regulatory body The requirement to distance gas sector regulation from the supervising ministries was included in order to guarantee impartiality and non-discriminatory access u n d e r ongoing European political scrutiny. The gas industry will be regulated by increasing the powers of the electricity regulation authority created in 2000 (which in 2003 will become the 'Commission de R6gulation de l'Energie' instead of Electricite'). Its a u t o n o m y should guarantee that the French gas market will be open to competition, mainly through its capacity of controlling non-discriminatory access by proposing tariffs and conditions of access to the transport and storage system for the ministerial decision; 19 this

16The tariffs include a significant fixed portion. 17In anticipation of the law, a zonal tariff was defined in 2000 by GDF, different from its former principles of tariff calculation in which high-pressure system costs were not geographically differentiated in the pricing. 18Abandoning the operational view of storage capacities limited to seasonal management and supply security, the government admitted its importance for trading activities with the possibility of creating value (Gas White Paper, 1999). However, like GDF then, the government now considers that entrants would not have to rely too much on existing storage capacity and would have to install their own devices. Balancing services are offered by the three system operators. 19During the 2000-2002 period of law postponement, the CRE mandated a working group to define transmission tariff principles that recommend the adoption of nodal pricing (entry-exit approach (Bergougnoux, 2001)).

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is almost the same as a decisional power. In addition, it advises on the regulated tariffs for sales to non-eligible clients. It also arbitrates in disputes on the access conditions with a power of sanctioning, and thus gives credibility to rules of access for allowing entries. 11.4.6. General interest and public service

The general interest and public service rules have been adapted to reflect the introduction of competition. 9 Long-term programming and protection of take-or-pay (TOP) contracts - The law introduces several provisions to allow the government to maintain its capacity to monitor the long-term development of the supply and its diversification. This is achieved mostly by establishing a programmed survey of future imported supplies, which the Directive allows. The law (Article 3.II) outlines the method of each supplier's foreign purchases by requiring them to inform the ministry of import contracts of a certain volume and to submit its annual import programme each year. In order to guarantee a certain diversity in the overall French supply, the Ministry is in a position to require major suppliers to re-diversify their purchase programme if it becomes too concentrated. If the supplier does not present a proposal for diversification when the government requests it, its new import contracts will have to be submitted to the ministry for approval (Article 3.II). Secondly, following the logic of the defensive French position during negotiations of the Directive, the law (Article 11.I) includes a provision that allows limitation of access for supplying eligible consumers when long-term contracts encounter difficulties, in order to ensure supply security. This provision could eventually help protect the existing TOP contracts in the framework of the specific restrictions laid down by the Gas Directive (Articles 15 and 25). 9 Revised public service obligations - The law revises the public service obligations: as well as the historical operator's duty to extend the distribution networks, it reduces the traditional obligations (equality of treatment, obligation of supply) to include ineligible consumers only. The regulated tariff for non-eligible clients must be equalised on the supply area of each distributor. It maintains the social requirement to supply low-income customers imposed on the public company. GDF's excessive cost of developing new local gas networks under its normal profitability rate (8% instead of 12%) must be supported by the national company (Gas White Paper, 1999, p. 21).

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11.4.7. Potential effects of the reform As a result of the transitory application of the TPA provision by GDF, CFM and GSO in anticipation of the vote of the law, the competitive situation in 2001 and 2002 clearly shows some competition effects. Against a background of high gas prices in 2000 many of the 150 eligible consumers, especially the major ones (P6chiney, Rhodia, Solvay and Saint-Gobain), shopped around by approaching or being approached by foreign suppliers or traders. In 2002 around 20% of the eligible consumers' total demand was switched towards entrants. 2~ The main entrants are TotalFinaElf, Distrigas (which has an important contract with the main industrial customer Rhodia), and to a lesser extent Centrica. The opening of access for eligible consumers to GDF's, CFM's and GSO's networks is encouraging operators to alter their commercial practices towards these clients. 21 GDF now offers new types of contract such as fixed price offers for a fixed period of 6-12 months and price offers indexed on the price of products sold by their clients. It also makes price indexes on the spot market, with a cap limiting the volatility risk. GDF's industrial prices are therefore being reduced in order to preserve its market shares, so that although there are positive effects for eligible consumers, competition still seems limited by industrial organisation and disincentive to entry because of GDF's dominant position.

11.4.8. The weakness of competitive forces Even with non-discriminatory access to the gas network, a centralised industrial organisation limits de facto competitive forces in the various market sectors. Upstream, the absence of national production means that wholesale competition only occurs in the field of supplies based on gas imports. However, the absence of a gas release programme such as that imposed on the incumbent in Italy (30% of SNAM's long-term contracts to be released to entrants in 2003) limits de facto the possibility of entries. In this context the real competitive pressure

2~ de l'Energie,No. 253, January 2001. 21In 1999 GDF altered the structure of its commercial activities. It created a special large customers department, eight 'industry' agencies in the regions, 33 'commercial clients' agencies and a trading operations centre that has become Gaselys, a joint venture with Soci6t6 G6n6rale.

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will come upstream from foreign suppliers (Distrigas, Centrica, ENI-SNAM and Ruhrgas), North Sea gas producers (including TotalFinaElf), and multi-energy companies (Edison, etc.). 9 The presence of the two regional transporters other than GDF appear to be partly conducive to competition in supply. It mainly allows foreign producers or suppliers to make some direct bulk purchases. Being controlled by GDF, CFM has little interest in competing against it. Competition is more likely from GSO, which is controlled by TotalFinaElf. GSO is tied for several years by an import agreement signed between GDF and Elf-Aquitaine in 1997, but since 2001 it has developed an aggressive marketing strategy aimed at large customers. 22 9 The concentration of distribution with the historical operator, with the exception of the few municipal distributions, reduces opportunities for competition in wholesale supplies, especially in second-tier supplies, where distributors would resell in the supply area of GDF or other distributors. Downstream, the structure of demand reduces opportunities for competition for three reasons. 9 The eligibility threshold is defined minimally, and the competition sector will not include medium-size industrial and commercial customers (under 15 mcm per year) until 2008. The next directive, however, will accelerate the opening process, including the SMEs and the commercial clients in 2005. The French government agreed on this measure in March and October 2002 (see below). 9 The limits laid down by the law for eligibility of co-generators reduce this sector to the major co-generators (over 15 MW for the 15mcm threshold between 2003 and 2008). However, the next directive will also open the game on this segment. 9 Independent electricity producers with gas turbines, who could be active buyers for new suppliers, are deterred from entering because of EDF's dominant position and the presence of its fleet of lowvariable-cost electrical equipment (nuclear reactors and hydroelectric plants).

22In 2001, GSO also began to disengage itself from dependence on GDF's supply. It

signed a one-year contract with TotalFinaElf's gas subsidiary for a supply totalling 13% of their gas supply to industrial consumers in their area, the first import contract indicating the end of GDF's import monopoly.

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Therefore, potential competition is mainly being felt in retail supply through multi-energy offers in the segment of industrial clients, in particular with large energy service companies: Dalkia (a subsidiary of Vivendi and EDF) and Elyio (a subsidiary of Suez-Tractebel).

11.4.9. The dominant position of the historical operator The conditions for access to the gas network, together with the advantages enjoyed by the historical operator, create a particularly strong dominant position that may deter entries and limit de facto the choice of large customers and brokers. First, in every network industry, even those with a guarantee of non-discriminatory practice, the incumbent will benefit from advantages that could discourage entries: the advantage of holding information on eligible clients (knowledge of demand in each market sector, hold over the commercial network and client files), the advantage of a confidential relationship with the client (reputation effect and risk aversion), the advantage of transactional simplicity with eligible clients compared to a competing seller who has to buy the transportation (and 'back-up') service, and the monopoly on the offer of balancing, back-up and metering. Second, the incumbent may increase barriers to entry by various strategic actions, especially by improving contractual offers to industrial clients as GDF has done. Third, the absence of organic separation of transport networks and supply is not conducive to establishing an atmosphere of confidence in the confidentiality of independent transactions or impartiality by the incumbent company when carrying out transportation for third parties. For example, large clients consider GDF's temporary transport tariff since August 2000 to be quite high, because it deters trade if the distance to the border exceeds 200 km. Moreover, the absence of TPA provision for access to storage capacities will limit the possibility of supply from agents with no storage capacity in France.

11.5. Signs of New Development The main potential for competition comes from European entrants and from the French oil company. In the mid-term, competition will evolve under two driving forces: the requirement to reduce the difference of market rules with other European Union state-members, and the business strategy of the entrants, especially TotalFinaElf.

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11.5.1. The European harmonisation rules process The French gas market is physically and cooperatively integrated with other European gas markets. It is currently linked to networks in other European countries by five connections, for importing gas and more recently for transporting to and s w a p p i n g with neighbouring countries. In the spirit of integration of the 1992 Transit Directive, GDF is developing significant transit activity for its Spanish, Italian and Swiss partners (Gas Natural, SNAM and Gaz Naturel). 23 In 1997 it signed a swap contract with an Italian partner (ENEL) on Nigerian LNG imports. The current issue is therefore the m o v e m e n t of this integration towards a market-based integration. European internal market integration is an institutional and political fact that affects national distinctions in every country. In a regional area governed by c o m m o n principles, there is a trend to reduce institutional variety by coercion w h e n this leads to imbalance in exchanges (Di Maggio and Powell, 1991). The European Commission is therefore likely to impose sanctions and require changes in regulations in instances of non-compliance with European rules, especially the competition law and the Gas Directive. More importantly, on behalf of the European Union, it looks for harmonisation of rules between countries in order to facilitate exchanges. The European Commission (EC), in which Directive 98/30 confided the task of harmonisation necessary 'in order for the internal market to function properly' (Articles 27 and 28), 24 will bring about certain changes in rules. The so-called Madrid harmonisation process, organised in 2000 by the EC between national regulators and transport operators, is having the effect of homogenising national rules (network and storage access, interconnection rules, etc.). The new planned directive on gas and electricity markets, issued in March 2001 for a possible vote in 2003, could bring forward the regulated TPA for the transit, the negotiated TPA for the storage and the total opening of the final market to 2007 and require the legal u n b u n d l i n g of the 23The first transit contract concerns Norwegian gas for Spain and relates to 2 bcm (signed in 1987). The second concerns a transit for Norwegian gas to SNAM and relates to 6 bcm (signed in 1998). The third concerns Norwegian gas for Switzerland with 0.5 bcm (signed in 1999). The swap contract signed in 1998 with ENEL exchanges 3.5bcm/year of Nigerian LNG with 2 bcm/year of Russian gas and 1.5bcm/year of Algerian gas. 24A first report on the harmonisation measures needed for the market to function properly should be issued in 2001. In the same way, after 10 years, a new directive should be issued 'in order to improve the internal natural gas market further'. In fact, however, this new directive has already been in the process of definition since 2000 and should be voted at the end of 2003.

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transport system and distribution networks (European Commission, 2001). In the Madrid s u m m i t in March 2002 and the European Council of Ministers in October 2002, the French G o v e r n m e n t opposed the full opening of the final market and the legal u n b u n d l i n g of distribution because these provisions conflict too m u c h with the public service model, even as a m e n d e d by the introduction of the TPA provision in wholesale. However, in the same time it agreed to the opening of the commercial segment and could be obliged to agree on a two-stage process of complete opening up, u n d e r certain conditions for preserving a quality of public service. If this happened, the French gas market w o u l d have to be fully opened in the near future instead of staying partially open at a r o u n d 30% before and after 2008. Gaz de France m a y have to dissociate its s u p p l y and gas network activities into different subsidiaries, leading to real transparency of network access.

11.5.2. TotalFinaElf's business strategy This French oil c o m p a n y has significant gas production activity in Europe ( 1 8 b c m / y e a r in 1999) and w o r l d w i d e (34Bcm/year), and is already present d o w n s t r e a m in the s u p p l y in the UK. 25 TotalFinaElf's vision of the commercial and trading opportunities is mainly European, but it has clearly expressed a wish to be present d o w n s t r e a m in the value chain. With its share in the UK-Continent Interconnector and with the possibility of access to the N o r w e g i a n pipelines on the continent in the near future (2003), it is able to reach the French gas system for its own gas. It aims to develop an active strategy in wholesale trading and in gas s u p p l y on the basis of its regional transportation assets, such as those held by GSO in SouthWestern France. It is currently GDF's main competitor on the eligible market. It is therefore planning to build a LNG terminal near Bordeaux, to connect the GSO system with Gas Natural-Enagas's system in Catalunya, and to create a hub market place in this region. 26 25In the light of Elf Aquitaine's history on the British gas market, TotalFinaElf is actively involved in that market. Its subsidiaries, AGAS and Elf Gas & Power, are involved in all sectors of the market (9% of the industrial and commercial market, 75,000 residential clients in 1999 and trading activity in gas and electricity). It is also present in electricity production, having a 40% shareholding in Humber Power Company with Centrica. 26This hub, located in Lacq, would be linked to its two GSO storage units and placed at the connection between GSO's system, GDF's gas system linked to Northern Europe, CEPSA's and Gas Natural's system in Spain and the connections to the two existing LNG terminals in Fos (France) and Barcelona (Spain) and the two planned terminals, one in Bilbao (Spain) and the other the TotalFinaElf terminal in Bordeaux.

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If the infrastructure and the hub project are realised in the next five years, this project will introduce more effective competition on the wholesale market in France and in Spain at a time when some of GDF's present long-term import contracts will expire and allow more scope for entries. However, GDF has a defensive strategy aimed at increasing its LNG import capacity by doubling the size of the Fos terminal, with the specific aim of dissuading Total/Elf from developing its ambitious strategy.

11.6. Industrial Policy: the Future Position of the National Gas Company At the confluence of various interest groups, the successive governments since 1995 have held their own views on the future of GDF as a gas company, an industrial firm and a public utility. Three options have been examined by the successive right-wing governments (Balladur, Jupp6) and the left-wing government (Jospin): 9 To place GDF under the thumb of one or the other French oil company (now a single company) that produces gas, as a major element of their downstream integration strategy. 9 To merge EDF and GDF in order to create a powerful multi-energy group (this would in fact mean that the first company takes over the second). 9 To favour GDF's autonomous industrial strategy by changing its status and allowing it to adapt in anticipation of the future competitive environment, by encouraging it to become internationalised in its core business. In the field of political forces, the public company has avoided being taken over by either of the French energy companies and has succeeded in developing a convincing industrial strategy. Part of the reason for this success is the company's refusal to accept the first two futures. It successfully adapts itself in order to resist future competition on its home market, to manage new risks in gas business and to expand in its core business with three main solutions: improved supply, upstream integration and internationalisation. From now on, its privatisation is a political issue and should be included in the gas reform act in 2002. However, it will be organising a shareholding between the two other French energy companies, a foreign oil and gas partner, and the State. This solution is seen as the best compromise for GDF's strategic autonomy in the future.

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11.6.1. Options in industrial policy On the eve of the opening-up of the gas market, GDF has two distinctive features in relation to other European gas companies. Firstly it is neither a subsidiary of an oil company, as is SNAM in Italy or Gas Natural in Spain, nor is it a company whose capital stock is partly controlled by oil companies, like Gasunie, Ruhrgas or Distrigas are more or less. This difference, which made it independent from the French oil companies' interests, also made it vulnerable in the political game for its institutional future as it would have legitimised purchase by one of the companies either as a means of controlling the price risk for the national bulk gas supply or for consolidating a national oil company by offering it a downstream basis in the gas markets. Secondly, GDF is legally tied to EDF in distribution and supply to medium and small consumers, which allows political resistance to total separation from public service model defenders and thus may suggest that a merger is an efficient industrial solution. In the political game, moreover, GDF as a public company is less legitimate institutionally than EDF. GDF imports gas; it does not benefit from the legitimacy associated with preserving energy independence and with national pride through technological power. It does not allow the base of public procurement to be offered in order to bear a major industrial project and ensure the development of an equipment industry. The option of acquisition by oil companies - The first particular feature explains why the idea of a privatised French gas industry controlled by one or both French oil and gas companies (Total, ElfAquitaine) could have been seriously considered during 1995-96 under the right-wing Balladur government. However, the government hesitated for three reasons: the difficulty in giving preference to one of the two French oil companies, fear that the concentration of the French energy sector would increase, and more importantly, the political barrier to privatising the gas company at a time when the oil companies were wholly privatised. GDF has been backed by the coalition that defended the public service model, and has also resisted this option by demonstrating its managerial efficiency and ability to enlarge its strategy, relying on the performance of its management and showing its ability to internationalise. Instead of gaining the option of controlling GDF in future, the French oil companies were called upon to support GDF's upstream integration strategy in exchange for increased symbolic participation in downstream regional or local distribution. After agreements signed in 1996 and 1997 the companies sold it

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some shares in North Sea offshore production assets and in the UKContinent Interconnector (5%). 27 This strategy led to increased ministerial support, with GDF winning an implicit 'national champion' status that should be supported in both European and world competition. The option of an EDF/GDF m e r g e r - The new competitive environment has not led to legal changes for separating EDF and GDF completely because of the resilience of the public service model; their gas and electricity supply units have been administratively separate since 1998, but the customer reception centres remain common. Backed by the part of the coalition that defends this model, EDF sees itself as a major multi-energy business and aims to purchase GDF with that in mind, particularly for its international expansion. Some trade unions are advocating a capitalist-type alliance between EDF and GDF, as 'the businesses that are succeeding are multi-energy and multi-field'. 28 The President of EDF expressed these ambitions in autumn 1998.29 As for its resistance to oil companies' ambitions, GDF's board benefited from the context in which advantage is not given to the defenders of such a solution. First, the high degree of centralisation of France's energy industry would have been reinforced by the merger of the two public companies, arousing suspicion from foreign competitors and the European Commissions anti-trust division. The German situation with E.On's takeover of Ruhrgas is not seen as the potential rationale for a EDF-GDF merger, given that E.On has a major competitor in multi-energy on its home market, and has two minor active competitors in electricity market. Second, from the ministries' viewpoint, the merger would not help to give a clear competitive advantage in France on the domestic market where the two companies benefit from a clear incumbent's advantage over other competitors. The multi-energy competition would definitely have been weakened, given that GDF is one of

27In return for transferring to GDF some of their shares in their North Sea deposits and envisaging subsequent cooperation in production in other areas, the two agreements signed at end 1996 and end 1997 allowed the two companies to develop a stronger presence downstream, making CFM into a corporate body in order to grant it a level of managerial independence, increasing Totals share in CFM from 5% to 10%, authorising CFM and GSO to contract directly with Elf-Aquitaine Gaz, with transfer by GDF of 25% of Gaz de Strasbourgs capital to Total. 28See the position taken by one trade union, the CFDT in La Tribune, September 1997 (22) and again in 2002 by two trade unions in Les Echos, October 2002 (3). 29See Le Monde, October 1998, 10.

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EDF's main competitors in multi-energy supply. Abroad, the new group would have some advantages in new trading activities, supply and green-field power production projects. The size advantage offered by the merger in terms of international strategies would have been clearer had the gas and electricity companies been about to be privatised. The option of a mono-energy s c h e m e - Ultimately, the public authorities favour the option of preserving a public gas enterprise, subjected in France to a level of competition-related pressure in order to improve commercially and required to move upstream in gas production in order to manage risks on the value chain and set itself up in other countries. It should not however be allowed to diversify into other business fields, so that the principle of speciality can be respected. Between 1999 and 2002, unofficial considerations favoured a triple alliance of GDF with the new French oil company, a foreign public oil company (Statoil) and EDF, by selling stock shares to them at a total of 40% (15% for TotalFinaElf, 8-10% for Statoil and 15% for EDF) after the corporatisation and partial privatisation of GDF. For this reason, part of the left-wing government conceded in 2000 that there was a need to change GDF's status to allow this option, g~ (The version of the gas law draft prepared for Parliament in 2001, before the postponement to 2002, therefore included a provision for change in GDF's status). The law voted by the new right-wing coalition at the end of 2002 does not cope with this problem because the government decided to manage jointly the issue of privatisation of GDF and EDF in 2003 and 2004. However, after the opening of the commercial and residential market and the legal unbundling of the gas networks, competition could be harsh for GDF, especially from EDE In this situation GDF could be incited to seek a strong alliance with a major European energy company such as Suez-Tractebel, and this strategy may succeed because of the major consolidation of its industrial strategy between 1998 and 2002.

11.6.2. GDF's active industrial strategy With the opening of competition in Europe, the official reports (General Planning Board 1998, White Paper 1999) increased the pressure on GDF to adapt itself commercially to the threat of

3~ Le Monde, April 2001, 14. In the first stage, GDF's stock will be sold bilaterally and the government will retain more than half of it.

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competition and diversify its geographical locations. Official analyses show the competitive threat to GDF by comparing its size with those of gas and oil companies (Leban, 1998) or by focussing on the apparent danger of being reduced to a simple transport company, whereupon it will be legally obliged to separate supply and transport functions. 31 They stress the threat posed by the large oil companies' strategy of downstream integration into gas supply and the choice of downstream alliance by the major gas producers (Gazprom, Statoil). GDF is developing a new management culture for the value chain and internationalisation. In the matter of internationalisation, the objective is to reach 50% of the turnover compared with 15% in 2001. The development of GDF's active industrial strategy (Dauger, 1998) has been efficient but it is heavily constrained by the rules governing the public service model: 9 The so-called principle of speciality as a legal provision of the public service model limits its diversification into fields outside its core business. 9 GDF's financial capacity for diversifying or developing its assets abroad is limited by its reduced capacity for generating cash flow from sales of gas in France, because of the regulation of prices. 9 State control of investments made abroad limited them to a total fixed for three years by the 'contrat d'entreprise'. However, the new 'contrat d'entreprise' signed in 2001 by GDF and its supervisory ministers allows GDF more room for manoeuvre by making the restrictions on using its surplus more flexible in order to finance investment and the completion of major transactions abroad (company or asset purchases etc.) with a financial resource level set at ff1-1.5 billion. 9 GDF's status as a public establishment also limits its room for international manoeuvre by preventing alliances through exchange of shares, arousing suspicion from potential private partners and leading some foreign governments to refuse purchases by GDF. 32 It motivates the Board of Directors' wish to change the status of GDF and be partially privatised.

31This risk was pointed out by a trade unionist in the financial newspaper Les Echos, April 30, 2001. In this context the scenario will involve giving the transport to Total FinaElf and the distribution networks to EDE 32For instance, in May 1999 the Norwegian Government opposed the planned transfer of shares in the Visund deposit from Saga to GDF for this reason.

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11.6.3. Upstream integration The development of GDF's presence in gas exploration and production is considered to be necessary for two reasons. First, risk sharing and value extraction on the gas chain is changed when competition is introduced on the wholesale and retail markets. Given the indexation of gas prices on oil prices in bulk sale contracts, gas-togas competition creates a potential squeeze between purchase price and retail price to eligible consumers for gas companies, while integrated oil and gas companies are not affected by this risk. Secondly gas producers, being closer to their resources, have greater capacity for attracting and keeping major clients downstream. As for some other gas companies such as Ruhrgas, GDF's objective is to reach a production capacity of 15% of the gas marketed by it in 2005, i.e., 6 bcm, which corresponds to half of the eligible consumers' demand. 33 Beyond this date a level of 25% will be sought. For this reason GDF purchased shares in British North Sea deposits (Elgin, Franklin, Murdoch) from Elf and Total in 1998, and then from other oil companies (Lasmo and Ranger Oil) in 1999 (Boulton, Caister, McAdam) and from Statoil in Norwegian offshore and TransCanada Pipe-Line in Dutch offshore in 2000. In 2001 GDF, with the Malaysian company Petronas, signed a partnership agreement with the Algerian company Sonatrach for developing a gas field in the next five years.

11.6.4. Diversification in energy services Anticipation of future competition is encouraging GDF, together with every other incumbent, to alter its commercial practices towards these clients by enriching its supply through services. At the same time it is developing activities in energy services, especially in the field of on-site co-generation, which are important elements of new outlets to its gas supply. It has created a special subsidiary Cofatech for this purpose, but failed to acquire Dalkia, the energy service division of the Vivendi Group, in 2000. Outside France, it took over control of Agip Service, the principal energy service group in Italy, in 1997, and Heat Service, the third largest service company in the UK, in 1999.

11.6.5. Internationalisation GDF is internationalising through purchasing assets, mainly in the industry's core activities (transportation, storage, and distribution) 33Its production reached 2.5bcm in 2001, that is, about 6% of its supply in France.

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Table 11.8. GDFs internationalisation in core activities.

Activities

Country

Name

LNG imports

India

Consortium with Petronet (Dahej and Cochin terminals)

Supply

United Kingdom Volunteers Energy Italy GDF (future retail supply from Libyan contract of 2 bcm/year) Distribution Europe Austria ESTAG Germany GASAG (Berlin) EMB (Brandebourg) Hungary DEGAZ EGAZ Portugal Portgas Distribution, Canada GasMetropolitan America (Montreal) Mexico Tamanligas Consorsio Mexigas Argentina GASEBA(North-East) Uruguay G A S E N A(Montevideo) Storage Slovakia Pozagaz Transport/Supply Slovakia SPP Transmission UK Interconnector Mexico TCPUs Mexican pipes Thermal Services Italy Agip Servizi Policarbo, Castagnetti, Zanzi UK Heatsave

Share Date of holding acquisition (%) 10

2001

100

1999 2000

25 50

1998 1997

50 50 19

1995 1995 1996 1998

51 75 60 46 30 16 5 100

1998 1998 1999 1997 1995 2002 1999 2000

90 100 32

1997 2001 1999

a n d in e n e r g y services, w i t h o u t l o o k i n g to m o v e d o w n s t r e a m into electricity p r o d u c t i o n projects (ATG, 1998). The a i m is for 50% of t u r n o v e r to originate f r o m i n t e r n a t i o n a l activity, 20% h a v i n g b e e n r e a c h e d in 2000. 34 G D F has seized o p p o r t u n i t i e s created b y the p r i v a t i s a t i o n of gas e n t e r p r i s e s to acquire m a j o r shares in their capital a n d p l a y a significant i n d u s t r i a l role. In this context it is p r e s e n t in several E u r o p e a n countries (Austria, G e r m a n y , H u n g a r y , Portugal) a n d in C a n a d a , Latin A m e r i c a a n d Asia (see Table 11.8). It h a d 34Until 1990, international activity was limited to sales of gas engineering services in LNG, storage, transport network management and general distribution management, through its subsidiaries Sofregaz and Technigaz.

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2 million clients outside France in 2000. In Italy it is becoming a key figure in supply activity: because of SNAM's gas release programme imposed by the local regulator, GDF purchased a SNAM long-term contract of 4bcm/year with Libya in 2001, thus becoming the fourth major supplier. In the same way, GDF is preparing to trade in different European countries through a joint venture with Soci6t6 G6n6rale. To conclude, Gaz de France's future is clearly restricted by the residual force of the public service model when it comes to changing its corporate status and possibly being privatised. At the same time, however, it will do well to resist the French oil company ambitions. Meanwhile, the new competitive environment and the scrutiny of France's particular situation by European players limits the feasibility of a merger between EDF and GDF. The efficiency of its industrial strategy, with its upstream integration and its large internationalisation, gives some scope to its future as a semi-private mono-energy company. It would be a strong basis on which to negotiate alliance in the future with a company such as Suez, in particular at the time of probable partial privatisation in 2004. 11.7. Conclusion

This historical analysis demonstrates that French institutional conservatism in reforming the gas industry is based on the legitimacy of the public monopolist status and the vertical organisation maintained by its good social and economic performances, I n the past Gaz de France, the public gas company, efficiently developed its natural gas system from a national resource base and then from an increasing imported gas base, integrating itself into the developing European gas exchange system in order to import from diversified resources. It has also allowed control of the public gas company's monopoly rent, to the benefit of consumers. Although weaker than in the electricity industry, this model contains extension of French oil companies in the gas system and allows it to develop efficiently despite its market shares being restricted by the nuclear policy priority. After internal reform, performance has also been able to improve. At present, the French gas system is technically and economically mature and can handle a competitive regime. Introduction of competition that questions the basis of the public service model in the gas supply, i.e., long-term security of supply and equality in supply, is slowed down by strong elements of institutional pathdependency. Moreover, the stakes of introducing competition are limited by near-exhaustion of national gas resources, by quasi-vertical

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and horizontal integration, and therefore by limitation of potential candidates to entries that do not involve an industrial shake-up. It will therefore still be somewhat affected by the new European regulation based on competition principles. The transcription reform has been postponed to December 2002; it is minimalist, preserves vertical and horizontal integration with adoption of minimal eligibility threshold, and has no legal unbundling or contract divestiture. Reform could not need to change the public company status in this first stage. An unravelling process, however, is occurring. The public service model institutions could only survive if France is politically and economically insulated. The analysis shows that the European economic integration movement is eroding the basis of the model. Limiting the institutional differences between European Union Member States as the cultural adaptation to competition, and increasing public companies' managerial priority of internationalisation, is the seed of new change in the future. Unbundling the transmission and distribution network could in future affect the legitimacy of preserving at any cost a traditional gas company in a European context from which its sister companies could have disappeared. Even though it is risky to speculate on a scenario of institutional and industrial change, in the medium term the French gas industry will probably not be immediately de-integrated with GDF's assets divested and some of its long-term contracts being transferred to entrants and transport and supply separated, as the Italian reform has just done in a previously monopolistic structure. The change in France will most probably lead to GDF's de jure monopoly being transformed into a de facto duopoly for GDF and TotalFinaElf with a competitive fringe of some foreign entrants in industrial supply: oil or gas companies disposing of gas surpluses, foreign traders and multi-energy suppliers. Some public service elements will remain in the development of distribution network, the protection of domestic consumers and the control of political dependence risk.

Literature

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of the natural gas public service and to the development of gas businesses) Paris, Assembl6e Nationale. ATG (1998) 'Le d6fi du d6veloppement international', Gaz d'Aujourd'hui, No. 11-12, pp. 531-536. Beltran, A. and Williot, J.P. (1992) Le Noir et le Bleu: 40 ans d'Histoire de Gaz de France. Paris, Belfond. Bergougnoux (2001) Rapport du Groupe d'Expertise Sur la Tarification Des Rdseaux de Transport de Gaz. Commission de R6gulation del'Electricit6, Paris. Bricq, N. (1999) Mission de rdflexion sur la transposition de la directive europdenne sur le marchd int&ieur du gaz (Report to the Prime Minister), Paris, Assembl6e Nationale, October Chevalier, J.M. (1993) The structure and regulation of the French gas industry. In E.J. Mestm/icher, Ed., Natural Gas in the Internal Market, Graham & Trotman, pp. 73-90. Commissariat G6n6ral du Plan (1998) Trois scdnarios dnergdtiques pour la France: Energie 2010-2020 ('Scenarios' workshop report). Paris, Commissariat G6n6ral du Plan. Criqui, P., Finon, D. and Martin, J.M. (1984). 'La politique 6nerg6tique de la France depuis la premi6re crise p6troli6re: analyse et essai d'6valuation'. Economica Delle Fonti de Energie 22: 73-131. Dauger, P. (1998) Position de Gaz de France et les Possibilitds Dans un Marchd Ouvert, Colloque Euroforum, Paris. (17-18 November 1998). Di Maggio, D. and Powell, D. (1991) The New Institutionalism in Organisational Analysis. Chicago, Chicago University Press. Elf-Aquitaine (1998) Rapports d'activitds. Paris. Estrada, J., Bergesen, H.O., Moe, H. and Sydnes, A.K. (1988) Natural Gas in Europe: Markets, Organisation and Politics. London, Pinter Publishers. Estrada, J., Moe, A. and Dahl-Martinsen, K. (1995) The Development of European Gas Markets. Chichester, John Wiley. European Commission (1998) Directive concerning the common rules for the internal market of the natural gas, CE/98/30, Brussels. European Commission (2001) European Directive modifying the Directives 96/92/CE and 98/30/CE concerning the common rules for the internal market of electricity and gas (proposal from the Commission). Com (2001) 125 final. Finon, D. (1992) 'Maturit6 des industries gazi6res et viabilit6 du r6gime concurrentiel'. Economies et socidtds (S6rie Energie). EN No. 5, February, pp. 189-221. Finon, D. (1996) 'French energy policy: the effectiveness and limitations of Colbertism'. In E McGowan, Ed., European Energy Policies in a Changing Environment. Heidelberg, Physica-Verlag. Frost, R. (1991) Alternating Currents: Nationalized Power in France 1946-1970. Ithaca, NY, Cornell University Press. Gas White Paper (1999) see Secr6tariat d'Etat a l'Industrie (1999). Haywards, J. (1986) The State and the Market Economy. Industrial Patriotism and Economic Intervention in France. Brighton, Harvester Press. International Energy Agency (1998) Natural Gas Distribution: Focus on Western Europe. OCDE, Paris. Leban, R. (1998) 'La r6gulation du secteur 61ectrique et gazier fran~ais dans la concurrence'. In Commissariat G6n6ral au Plan. Energie 2010-2020, Les chemins d'une croissance sobre. Paris, La Documentation Fran~aise, pp. 427-463. Masson, J.L. (reporter) (1991) Proposition de Rdsolution D'une Commission D'enqu~te Sur les Perspectives D'evolution du Monopole de Gaz de France. Assembl6e Nationale, No. 2277. Minist6re de l'Industrie (1993) Rdforme de l'organisation de l'industrie dectrique et gazi&e franr (Mandil Report), DGEMP Paris.

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North, D.C. (1990) Institutions, Institutional Change and Economic Performance. Cambridge, Cambridge University Press. Poniatowski, L. rapporteur (2002). Projet de loi relatif aux marchd dnergdtiques (Rapport de la Commission des Affaires dconomiques). Paris, S6nat. No. 16, Octobre Secr6tariat d'Etat a l'Industrie (1999) Vers la future organisation de l'industrie gazi&e (Livre blanc). Paris, Secr6tariat d'Etat a l'Industrie. Stern, J. (1998) Competition and Liberalization in European Gas Markets: a Diversity of Models. RIIA, London. Stoffaes, C. Ed (1995) Services Publics: Questions D'avenir (Rapport au Commissariat Gdndral du Plan). Paris, Editions Odile Jacob.

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Chapter 12 Gas Markets in Southern Europe ROLF W. KUNNEKE AND ISABEL SOARES

12.1. Introduction

Chapters 12 and 13 provide an overview of market developments and trends in countries that are not covered by the in-depth studies in this book. It completes the overview of current developments in EU-relevant gas markets and allows a comprehensive assessment of current and future developments. Three different regions are covered: Southern Europe, East-Central Europe and North Africa, specifically Algeria. The description of Southern Europe focuses on Italy, Spain, and Portugal. Italy is the third largest natural gas market in Europe. Spain is interesting because of its rapidly developing gas industry. Portugal is a newly emerging gas market that only started to introduce natural gas in 1997. Since these gas markets have some similarities with respect to their geographical location, industry structures and the process of restructuring of national gas markets, they are addressed separately in Chapter 12. Chapter 13 completes the summary of developments and trends in the gas industry by addressing gas markets in East-Central Europe and Algeria. East-Central Europe is important as transit corridor for Russian gas. Besides, some countries have significant domestic markets that attract private investment from major Western European gas firms. Algeria is one of the most important gas producing countries for the European market. Algerian gas is good for about one-fifth of the EU gas imports. Both chapters provide brief overviews of the core features of the gas markets in these regions. They focus on the industry structures and the challenges for the regulatory reform. Chapter 14 includes an analysis of the relevance of these countries for the evolution of a liberalised European gas market. 283

284

National Reforms in European Gas

12.2. Italy 12.2.1. Some core features Italy is the third largest gas-consuming country in the European Union, after the UK and Germany. 1 Compared to other primary energy sources, the relative share of gas is expected to increase from 32% in 2001 to about 39% in 2010 (see Table 12.1). The relative share of oil, which is the most important primary energy source of this country, is likely to decrease in this period from 55% to 46%. This increasing significance of natural gas is predominantly the consequence of using gas for electricity production. Nowadays, about 25% of the electricity plants is fueled by gas. Residential and industrial consumers contributed strongly to the growth of the gas consumption in Italy between the 1970s and the 1990s, but now the growth appears to stabilise in these sectors. In 1997, the share of natural gas of the total energy d e m a n d was 47.8%. Industry covered 35.6% of their primary energy needs by natural gas. These numbers are well above the IEA European average (Fig. 12.1). 2 Italy has only very limited domestic gas reserves, which in 2000 only covered about one-fifth of the total supply. The national gas reserves are declining, and consequently, Italy has to rely increasingly on imports. 3 (See Fig. 12.2). In the year 2000 Algerian gas was good for about 34% of the Italian gas supply, Russia 30%, the Netherlands 9%, whereas the inland production accounted for 21%. 3 To a small degree there are even imports from Norway and Abu Dhabi. Possibly in 2003 Libya might serve as an additional source of gas supply. (See Fig. 12.3). Liquefied natural gas (LNG) is becoming increasingly important as a means to diversify the gas supply and opens new physical means for the transportation of gas. Algerian LNG is shipped to Panigaglia terminal under a 25-year contract that runs to 2015. Nigerian LNG is landed to a French terminal and swapped to Italy. Figure 12.3 illustrates the development of the Italian gas supply from 1971 to 1998. The Italian pipeline system is quite well developed, although future investments are needed to serve the increasing demand. 4 The high 1In 2000 the total gas consumption accounted in Italy was 70.34bcm, whereas 91.39bcm in Germany and 103.28bcm in the United Kingdom was consumed. Source: ENI World oil and gas review 2002, p. 140. 2International Energy Agency (1999), p. 65. 3Department of Energy (DOE), December 2001. 4The ratio of the transmission network to the area of the country is 0.09km/km2, in the case of Italy. The European average is 0.05k m / k m 2. Source: EJC Energy, p. 207.

Gas Markets in Southern Europe Table 12.1.

285

Shares of primary energy sources 1973-2010 in Italy 1.

Supply

1973

1990

1996

1997

2000

2005

2010

Shares (%) Coal Oil Gas Comb. Renewables & Wastes Nuclear Hydro Geothermal Solar/Wind/Other Electricity Trade

6.3 77.9 11.1 0.2 0.6 2.5 1.4 . 0.1

9.5 59.3 25.4 0.6 . 1.8 1.3 . . 1.9

7.0 57.8 28.6 0.9

6.7 46.4 38.8 3.8

2.0

2.0

6.7 55.1 31.2 1.2 . 2.2 1.5 0.1 2.0

6.8 51.0 35.5 2.6

2.2 1.5

6.9 57.3 29.1 1.0 . 2.2 1.5

2.2 1.5 0.5 -

2.1 1.5 0.8 -

.

.

.

.

1Source: IEA Italy 1999, 118. Please note that the data for 2000, 2005 and 2010 are IEA estimates.

Fig. 12.1. Natural gas supply, production and net imports, 1973-2010. (IEA 1999, p. 67.)

and medium pressure network has a total length of approximately 29,000km. The medium and low-pressure lines of the distribution network accounts for 169,000km. Due to the geographical characteristics of the Italian peninsula, there are only four major entry points to the international pipeline system, i.e., two at the north, one at the south, and one at the north west (Fig. 12.4).5 5DRI-WEFA, vol. 2, p. 68.

286

National Reforms in European Gas

Fig. 12.2. Natural gas production, supply and net imports, 1973-2010.

Fig. 12.3. Natural gas production and imports by country, 1971-1998 (IEA 1999, p. 70).

9 9 9 9

Tarvisio at the A u s t r i a n border; Passo Fries at the Swiss border; M a z z a r a del Vallo (Scilily); P a n a g a g l i a (Genova) L N G terminal.

Gas Markets in Southern Europe

287

Map of the Italian Oil and Natural Gas Facilities

Fig. 12.4. Map of the Italian oil and natural gas facilities (IEA 1999, p. 60).

12.2.2. Sector organisation The gas and oil sector is dominated by ENI, a former state enterprise that w a s transformed into a stockholding company in 1992. Over the years, the state's share was reduced to some 38% in 1998. Before the recent unbundling of pipeline, storage and supply activities in late

288

National Reforms in European Gas

2001, ENI comprised three major firms 6 with each holding a dominant market position: 9 ENI/ AGIP: oil and gas exploration, and storage of natural gas. 9 Agip Petroli: oil refinery and distribution; 9 SNAM: Gas import and transport. In 1997 SNAM was the fourth largest gas firm in Europe. SNAM not only owns almost the entire Italian transport network, but has also a financial interest in the international pipelines delivering gas to this country. In 1999 this company transported 97% of the gas sold in Italy. By this time, SNAM has a virtual monopoly for the gas supply to industry, power stations and distribution companies. Some 700 local companies handle the distribution of gas. Half of them is publicly owned by municipalities, the other half belongs to private investors. Italgas is the biggest (private) gas distributor, serving about one-fifth of all municipalities including the largest cities of the country. SNAM holds about 40% of the shares of Italgas. It appears that before the introduction of the EU directive the Italian gas sector was strongly vertically integrated and virtually monopolised by the ENI consortium with SNAM holding a core position. The European Gas Directive was transposed into Italian law in May 2000. The regulatory authority for the gas and electricity market (UAutorita per l'Energia e il Gas) is operational since April 1997.7 Its main objectives include the determination of the basic network related tariffs, the establishment of quality of service standards, and the stimulation of competition in the energy sector. As of January 1st 2002, the following obligations for unbundling are effective8: 9 Legal unbundling for transport, distribution and storage activities form other gas sector activities. (Firms specialised in transport and storage must unbundle management and accounting) 9 Distribution companies are obliged to unbundle by the abovementioned date, although firms with less than 100,000 customers may meet this target one year later. 9 Gas supplying firms may not be engaged in other gas sector related activities except for exploitation, import, export or wholesale.

6International Energy Agency (1999), p. 57. 7The following information is derived from the official website of the regulator. www.autorita.energia.it 8DRI-WEFA, vol. 2, p. 66.

Gas Markets in Southern Europe

289

In line with this liberalisation process, SNAM is legally separated into different firms. As of late 2001, the transportation grid is owned and operated by SNAM Rete Gas Italia. A new gas distribution company, Italgas Piu, was launched in November 2001. Stoccaggi Gas Italia is the new specialised gas storage company. Although they are legally independent, the ENI conglomerate is still the mother company of the unbundled transport, distribution and storage companies by ownership rights. Other significant market parties in the gas sector include ENEL, Italy's main electricity producer, and Edison, an affiliate of the Montedison chemical group. Edison is engaged in the supply and production of gas and electricity in this country. Although its Italian activities are quite limited as compared to SNAM and ENEL, it is the second energy firm and most serious challenger to the traditional companies. Edison produces gas in Italy and has recently acquired an import contract with Russia. The firm owns a 1000 km transport network in central and southern Italy. In 2001 Edison had a market share of some 5% of the total supply. But as a consequence of this new import contract, this share is expected to rise. The electricity firm ENEL also holds import contracts to supply for a part of their generation activities. 9 On the other hand, ENI recently also engages in electricity production, owning approximately 1000 MW capacity. Formally the Italian gas market will be completely open for all customers as of January 1st, 2003. The terms and tariffs for third party access (TPA) to the gas networks are published in July 2002.1~ It is a system of regulated TPA, with some basic rules exemplifying access conditions. Among others, priority access is granted to long-term take or pay contracts and multi-annual and annual supply contracts. In case of congestion, a proportional allocation mechanism is applied for the remaining contracts. The tariffs for storage, which are effective as of April 1st 2002, are based on real cost of service and only apply for existing facilities. 11 Likewise for storage, LNG and technical services, the principle of regulated TPA applies. The amount of TPA as a percentage of sales in the home market increased in the past years from 3% in 1995 to 16% in 2000.12 Largely, this is the consequence of the imports of Russian gas by Edison that account for 5% TPA-volume in the year 2000 and the gas market activities of ENEL. 9Department of Energy, p. 3. 1~ release of the Autorita per l'Energia e il Gas, July 26, 2002. www.autorita.it 11Press release of the Autorita per l'Energia e il Gas, March 29, 2002. www.autorita.it 12DRI WEFA, p. 71.

290

National Reforms in European Gas

12.2.3. Challenges in the ongoing reform process The ambitions for a reform are quite high. In its initial plans of the year 2000, the government aimed that by the year 2003 no single company would be able to supply more than 50% of the natural gas sold to the final customers. 13 Meanwhile, this target is somewhat modified. In the year 2004 ENI/SNAM-related activities are targeted at the following levels: 14 9 9 9 9 9

SNAM gas imports and wholesale 60%, Agip gas production 90%, Storage by Stoccaggio 90%, Transport by SNAM Rete Gas Co. 90%, and Distribution and retail less than 50%.

Undoubtedly, stimulation of competition is necessary to come even close to these objectives. The regulatory authority issued in August 2001 a guideline giving large gas customers the right to withdraw from their contracts and change supplier. 15 Indeed, the large consumers are exaggerating quite some pressure to liberalise the gas market. They seem to be one of the most important drivers for change. 16 Compared with other European countries Italian gas prices are quite high, which might explain the pressure from industry (See Fig. 12.5). However, the conditions to realize a competitive market are complex and difficult. The grid entry points to the international pipelines only have limited additional capacity available to allow for third party gas import. 17 Besides, there are only four of such entry points. Building new lines to gas suppliers is very costly, because of the long geographical distance that has to be bridged. Italy's geographical positioning at the 'fringe' of the continental European market is a disadvantage that is very difficult to compensate. Additional pipeline connections are needed to lower this barrier to entry. In this respect the further development of the LNG infrastructure might serve as a means for diversification of gas imports.

13Department of Energy (2001), p. 3. 14presentation of Mr. Sergio S. Garribba, commissioner of the Autorita per l'Energia e il Gas, 3rd CEER-NARUCroundtable, 6-7 December 2001, Rome. 15press release of the Autorita per l'Energia e il Gas, August 26, 2000, www.autorita.it 16ECJ Energy, p. 204. 17DRI WEFA p. 68, vol. 2.

Gas Markets in Southern Europe

291

Fig. 12.5. Gas prices in IEA countries 1998. (Energy Policies of IEA countries, 2000 review, OECD publication 2000.)

Another major challenge for market opening is the behaviour of the dominant ENI group. Although the activities are recently unbundled, it nevertheless has to be seen whether this is sufficient to lower the third party entrance level and allow for competition. Even now, almost all major activities of the gas value chain are vertically integrated in the ENI holding. The commercial relations between these firms might be a little bit less tight, but each of the ENI divisions stays a dominant player in its market segment. Whether Edison and ENEL, the only serious competitors at this moment are willing and able to

292

National Reforms in European Gas

challenge ENI's position is questionable. Besides, most of the longterm import contracts are held by SNAM, which by the nature of these contracts still has a preferred access to the network. Evidently, there is quite a gap between the ambitious plans of the government and reality. There are large vested interests in the Italian gas market that are threatened by the ongoing liberalisation process. 18 Labour Unions and left wing parties fear significant employment effects as a consequence of rationalisations. The existing gas companies (ENI, SNAM) cannot be expected to become the drivers for liberalisation, because they have much to lose; i.e., a monopolistic home market with stable profit rates. In the past SNAM protected its position, among others by acquiring ownership rights in international pipelines delivering gas to Italy, and engaging in strategic alliances with important market parties like Gazprom and ENEL. This is very helpful to consolidate each others dominance. From a policy perspective, granting long-term security of supply might even appear more complex under competitive market conditions. To what degree are firms able and willing to enter into long-term agreements, that enable risky investments into the building of new long-distance pipelines or the exploration of new gas fields? Italy strongly needs a further development of the pipeline infrastructure, both on the level of international connections and the growth of the national grid in order to satisfy the increasing demand for primary energy source.

12.3. Spain 12.3.1. Some core features The Spanish market for natural gas only quite recently developed towards a significant size. Traditionally oil and coal are the most important primary energy sources in this country, holding a share of 73.3% and 17.2% respectively in 1973, which is however drastically declining towards an expected level of 49.8% and 8.4% respectively in 2010. On the contrary, the share of natural gas increases from 1.8% in 1973 towards 11.2% in 1999 and is predicted to reach 17% in 2010. (See Table 12.2). But still this is well below the EU average, which was in 1999 about 22% and is anticipated to be 26% in 2010.19 Obviously, the difference between the European average and Spain reduces, which indicates that the Spanish gas market is catching up with other European countries in the next decades. 18ECJ Energy, p. 204. 193rd CEER-NARUCRoundtable.

Gas Markets in Southern Europe Table 12.2.

293

Shares of primary energy sources 1973-2010 in Spain 1.

Supply Shares (%) Coal Oil Gas Comb. Renewables & Wastes Nuclear Hydro Geothermal Solar/Wind/Other Electricity Trade

1973

1990

1998

1999

2005

2010

17.2 73.3 1.8 -

21.5 51.3 5.5 3.7

15.3 54.5 10.3 3.2

16.3 53.8 11.2 3.4

10.3 52.0 16.0 5.1

8.4 49.8 17.0 8.1

3.3 4.7 . -0.3

15.6 2.4

13.6 2.6 . 0.1 0.3

12.9 1.7

12.8 2.5

12.2 2.4

0.9 0.3

1.8 0.3

.

. -

.

. 0.2 0.4

1Source: IEA Spain 2001, p. 121. Please note that the data for 2005 and 2010 are IEA estimates.

The rapid development of the natural gas market is mainly the consequence of a strong increase in the industrial use of this energy source. In the electricity sector the share of natural gas grew from 1% in 1990 to 9.2% in 1999. 20 In this period the Spanish government financially supported investments in gas-fired electricity combined heat and power (CHP) plants. Especially small electricity generators were stimulated, who received a premium up to 67% of the market price of the produced electricity. 21 For the other industrial sectors the use of gas doubled between 1990 and 1999. A further growth is expected, from presently 25.4-28% in 2010. Residential customers use natural gas for an increasing degree for heating purposes. In this sector final consumption tripled between 1990 and 1999, and is expected to have a share of 13.8% in 2010. (See Fig. 12.6). 22 Spain has extremely limited indigenous gas reserves that at present are almost depleted. 23 Consequently, long-term security of supply of the gas imports is an import theme on the political agenda. The originating countries of gas imports are in 2000:24 9 Algeria 59.8% 9 Norway 13.3% 9 Nigeria 10.8% 2~ International Energy Agency (2001), p. 71. 21Source: International Energy Agency (2001), p. 62. 22Source: International Energy Agency (2001), p. 72. 23The country's largest gas field was depleted by 1995. Presently only very small field remain in production. Source: Department of Energy (2002). 243rd CEER-NARUC Roundtable, p. 4.

294

National Reforms in European Gas

Fig. 12.6. Natural gas consumption by sector in Spain, 1973-2010.

9 9 9 9

Trinidad and Tobago 5.0% Libya 4.6% Others 5.5% Domestic 1.0%.

About half of these imports is based on LNG, the other half is delivered through only two international pipeline connections. One connection is in the north (Lacq-Calahorra) delivering Norwegian gas, the other in the south (Magheb-Europe pipeline) giving access to Algerian gas. Presently three LNG terminals are available (Huelva, Cartagena, Barcelona), and two others are planned (Bilbao in 2003, and possibly Murgados in 2005). 25 Figure 12.7 provides an overview on the natural gas infrastructure. Presently Spain is not well integrated into the European gas network. Due to its geographical position in the southwest of Europe, the distance to gas reserves is significant and there are only limited opportunities to connect to the European gas network. Consequently, Spain has to rely on LNG, which is quite expensive as compared with pipeline gas in other parts of Europe.

25Source: International Energy Agency (2001), p. 73.

Gas Markets in Southern Europe

295

Fig. 12.7. Natural gas infrastructure in Spain.

12.3.2. Sector organisation The Gas Natural Group (GN) dominates the Spanish gas sector. Prior to the liberalisation GN controlled the entire Spanish gas market as vertically integrated firm. Recently GN was responsible for more than 90% of the Spanish gas supplies. 26 Four firms divide the remaining market share: Cepsa Gas Comercializadora SA (Spains second largest oil and LPG company), Endesa Energia SA (a major Spanish electricity producer, developing into the final customer gas market), BP Amoco Gas Espania SA, and Shell Espa~a SA (oil and gas internationals). Another electricity firm, Unin Fenosa, has acquired an import contract of Egyptian gas, that will flow to Spain as of 2004. These data illustrate that the dominance of GN at least partially eroded. GN is a private sector firm with the Spanish oil company Repsol-YPF as the majority shareholder. In its origin GN is a gas distribution company, holding about 90% of the distribution networks. 27 Besides, this company had a legal monopoly for building new networks. 28 The Spanish gas transport company, Enagas, was acquired by the GN group in 1994. 26year 2000 data. Source: International Energy Agency (2001), p. 80. 27Out of the 28 regional distribution companies, the 14 biggest are owned by the GN group. 28This exclusive right for building new networks ends in 2005.

296

National Reforms in European Gas

The Hydrocarbons Act 1998 (law 34/1998) officially introduced the liberalisation process in Spain. Meanwhile several amendments are made in order to speed up this process. Third party access to the network is based on regulated terms and tariffs. As elsewhere, unbundling of regulated and commercial activities is required. Legal separation is obligatory for firms engaged in both regulated and commercial activities. For firms only engaged in regulated activities, separation of accounts is sufficient. This unbundling has of course profound consequences for GN. Enagas became the major Spanish transmission company and is nominated as the transmission system operator (TSO). 29 This TSO has to safeguard the technical management and operation not only of the transmission network, but is also responsible for the distribution networks and storage facilities. By law, no firm is allowed to have more than 35% of the shares of this TSO. As a consequence, GN has to sell a significant packet of his shares. Even with respect to the distribution, network activities and trade must be legally separated. In January 2001, 19 traders were registered, with the trading company of GN as the biggest (Gas Natural Comercializadora). Measures to stimulate competition in the Spanish gas market include: g~ 9 Limitation of the market share of any supplier to 70% in 2003; 9 25% of Algerian gas delivered to the Maghreb-Europe pipeline is designated for registered trading companies, to be allocated according to transparent and non-discriminatory rules. This gas release programme covers about 16% of the annual gas consumption. 9 Shareholding participation in other companies in the same sector are limited to 3%. 9 In order to increase the surety of supply, gas supplies from one single country are indicative limited to 60%. Table 12.331 summarised the liberalisation schedule as compared to the EU directive. As of January 1st 2003, all customers are eligible, which is considerably faster than obliged by the EU directive. However, the degree of third party access is quite limited. Resulting from the limited number of suppliers, at the end of 2001 only 13.5% of

29Societad de Gas de Euskadi is another regional gas transmission company that operate in the Basque Country in the North of Spain. 3~ International Energy Agency (2001), p. 81. 31Source: International Energy Agency (2001), p. 82.

Gas Markets in Southern Europe Table 12.3.

297

Schedule for the liberalisation of the Spanish gas market. 1

Date

Eligibility

1 January 1999 1 June 2000

Annual consumption > 10 million m 3 Annual consumption > 3 million m 3 and all generation and co-generation plants

1 January 2002 1 January 2003

Annual consumption > 1 million m 3 All consumers

Market opening 61% 72% (Directive requires 30% in 2000) 79% 100% (Directive requires 38% in 2005 and 43% in 2010)

1Source: IEA Spain 2001, p. 82.

the eligible customers changed their traders. However, the Spanish regulator expects a significant increase of this number.

12.3.3. Challenges in the ongoing reform process The Spanish government seems to be committed to stimulate the liberalisation of the gas market. The latest legislation is clearly very supportive in this respect. Large industry and power producers are pushing for market opening in order to realise lower prices and more favourable terms and conditions for the delivery of gas. However, quite some obstacles have to be removed to make the reform a s u c c e s s . 32

Regulatory uncertainty The practicalities of TPA for new suppliers and the terms and conditions for customers to change to an alternative trader are only very slowly developed. This includes aspects like development of network codes, terms and conditions for TPA, tariffs, and metering issues. The lack or uncertainties about these aspects create higher risks for market parties willing to profit from the market liberalisation, and hence penetration of third parties is too slow. For example, the terms and conditions for the complete liberalisation of the Spanish gas market, starting January 1st, 2003, are not known by fall 2002.

Immature infrastructure Because of the geographical location of this country, there are only limited connections to the international gas market, i.e., two pipeline connections and three LNG terminals. The capacity of these 32DRI-WEFA, vol. 2, pp. 93-103.

298

National Reforms in European Gas

connection points is mainly allocated to the consequence of the historical development of the within Spain free pipeline capacity for newcomers This clearly creates serious physical limitations for

incumbent, as a gas market. Even is very restricted. new market entry.

Dominant position of the incumbent Even after unbundling and other above-mentioned legal means to stimulate competition, Gas Natural remains in a very strong market position. From the past it inherited the long-term import contracts and the corresponding pipeline capacity together with the commercial relationships with the final customers. GN, of course, is dedicated to keep its customers, and is very likely to develop an aggressive strategy to prevent newcomers to get a too large market share. For example, the trading branch of GN offers very interesting discounts for large customer. These obstacles are very difficult to put aside by new entrants. Political concerns Next to the central government Spain has 17 autonomous regions with their own regional governments. Different regional interests influence the liberalisation of the Spanish gas market. For example, Gas Natural is seated in the region of Catalu~a, which is represented by a strong political party. In the past this party seemed to be dedicated to protect the market position of GN, in order to keep the economic position of this firm as strong as possible. On the contrary, the Basque regional government is in favour of liberalisation, because it wants its regional gas company, Gas de Euskadi, to become Spain's second gas operator. Besides, the creation of an interconnection of the Basque pipeline system to France has positive impacts for the region. 33 Although the gas act leaves the main responsibilities for the gas policy with the central government, decision-making processes are surely influenced by the above-mentioned regional considerations. Obviously, there is a long way to go for the Spanish gas market to become fully mature, both with respect to institutions and markets, as well as the physical development of the infrastructure.

12.4. Portugal 12.4.1. Some core features Portugal is an example of an emerging gas market. This country only very recently started with the introduction of natural gas. The first 33EJC Energy, p. 221, 222.

Gas Markets in Southern Europe

299

natural gas flowed into Portugal in February 1997. The Carregado electricity power station belonged to the first large-scale users of this newly evolving gas infrastructure. Prior to this period, Portugal developed a town gas system in the capital city of Lisbon. This system was good for about 230,000 customers and 2% of the residential energy consumption. 34 The EU directive considers Portugal as an emerging gas market and allows a transition period of 10 years for the restructuring of the national gas market. Accordingly, Portugal has to start the liberalisation at the latest in 2008. An important stage towards the introduction of natural gas was the 1994 Energy Program. The Portuguese government recognised the need to reduce the countries dependency on oil and hence diversify energy sources and suppliers. Natural gas was also attractive because it helped to reduce the environmental impact on the production and use of energy. Besides, natural gas was perceived as a possibility to reduce the countries energy bill. Figure 12.8 summarises the objectives and the energy policy of the Portuguese government in this period. The European Union, the Portuguese State and public enterprises contributed significantly to the development of the gas infrastructure. From 1994 to 1999 the EU provided some C300mln, the Portuguese state and public enterprises C400mln, and the private sector C220 mln. 35 In 2000 natural gas already covered about 10% of the national energy consumption. This share is expected to grow to 19% in 2015. At the same time the dependency on oil reduced from 71% in 1996 to a predicted 55% in 2015. (See Table 12.4) The most prominent users of natural gas are power plants and industry. Residential use is increasing, but still on a significant lower level than industry and power production. This structure persists even in the long-term perspectives. Table 12.5 summarises gas sales to these sectors for the period 1997-2001. Algeria is Portugal's most important gas supplying country. In 1994 a 25-year contract was signed, for an annual volume of about 2.5 bcm. LNG is contracted from Nigeria, starting with an annual volume of 0.35bcm in 1999, to be upgraded to I bcm in 2003. LNG terminal is already under construction in the city of Sines. Before this terminal is available, g6 LNG is landed in the Spanish La Huelva and transported to Portugal. 34Source: International Energy Agency (2000), p. 65. 35Source: International Energy Agency (2000), p. 18. 36This terminal is planned to be available in October 2003.

300

National Reforms in European Gas

Fig. 12.8. Portugal's energy objectives and policy. Source: Energy Policy in IEA countries: Portugal 2000 Review, p. 67.

Table 12.4. Energy Consumption in Portugal (1996-2015). ~

Coal Oil Natural Gas Other**

1996

1998

2000

2005*

2010"

2015"

18% 71% 0% 11%

15% 70% 4% 11%

18% 62% 10% 10%

15% 60% 16 % 9%

14% 57% 19% 10%

17% 55% 19% 9%

*Estimations. **Hydro, biomass, wind power. tSource: G D P - G~is de Portugal (1999) 'Relat6rio e Contas', Lisboa.

Table 12.5. Transg~s accumulated sales from December 97 to December 2001 (bcm) 1 Year

Household consumption

Industrial consumption

Electricity generation

1997 1998 1999 2000 2001

0.022 0.144 0.363 0.697 1.133

0.047 0.289 0.781 1.516 2.466

0.027 0.429 1.856 3.030 4.127

1Source: GALP ENERGIA (2001): Relat6rio e Contas.

Gas Markets in Southern Europe

301

The gas infrastructure of this country is still under development. In 1999 the transmission grid measured 1,417km, which is expected to grow to 1,705km in 2010. In the same period the size of the distribution networks is projected to increase from 4,635 to 7,860 k m . 37 Figure 12.938 maps the major gas facilities of Portugal and the supply areas of different distribution companies. At present, this country has only two international pipeline connections, both originating in Spain. The LNG terminal in Sines is a third connection point to the international market. It offers important opportunities for the diversification of the gas supply. Distribution networks are starting to develop. In the remote northwestern and southern part of Portugal an alternative for gas transportation through pipelines applied. In this area 13 regasification units are constructed in order to allow transportation of LNG by trucks. Special storage facilities guarantee a continuous availability of gas. 39

12.4.2. Sector organisation The GALP Energia Group dominates the Portuguese gas and oil sectors. This holding company is completely vertically integrated, controlling all major activities in these sectors, from import to transport and storage, to distribution and supply, for small and big customers. Under the holding, the activities in the gas and oil sectors are divided between Petrogal for the oil sector and GDP (G~is de Portugal) for the gas sector. Besides, the GALP group is engaged in the electric power production by GALP Power. GDP has various subsidiaries that are related to different activities in the gas business, including: 9 Transg~is: import, transport and sales to large customers and distributors. This firm is also engaged in the international pipeline business. Among others it holds a share of 27% in the EuropeMaghreb pipe from Algeria to Spain. 9 Transg~s AtlSntico: Exploitation of the LNG terminal in Sines There are six distribution companies with each in a regional monopoly position (See Fig. 12.10). Although GDP is the most important 37Source: International Energy Agency (2000), p. 75.

38Source: International Energy Agency (2000), p. 69. 39Source: International Energy Agency (2000), p. 70.

302

National Reforms in European Gas

Fig. 12.9. The Portuguese gas network. shareholder, in some firms there are also foreign investors engaging in this part of the gas business: 4~ Lisboag~s: 100% owned by GDP. Portg~s: 46.6% owned by GDP; 25% by Nelson Quintas e Filhos; 12.7% by Gaz de France Group; 12.7% by Lyonnaise des Eaux Group; 27.7% by Oporto and Ave Valley metropolitan areas. 4~

International Energy Agency (2000), pp. 67-69.

303

Gas Markets in Southern Europe

I st ,e

I

F

34.8%

I 33.3%

I

I 14.3%

(cod

j

I

Iberdrola

J

4%

13.5%

GALP

I 10(~'

J Petrogal I

m, 100%

J

G~

I

Transgas

I

100%

I

Fig. 12.10. GALP shareholding in 2000. Source: Energy policy in IEA countires: Portugal 2000 Review, p. 32. 9 Lusitaniag~is: 84.1% owned by GDP; 10% by Italg~is and the remaining capital by small shareholders. 9 Setg~is" 45% owned by GDP; 33% by ENAGAS and 22% by Italg~s. 9 Tagusg~s: 40.5% owned by GDP; 20% by Construtora do Lena, S.A.; 10% by A.G. Vieira & Filho, Lda; 10% by FAIART G~isriba and the remaining by small shareholders. 9 BEIRAGAS: 65% owned by GDP; 20% by VISABEIRA Group and the remaining capital by small shareholders. Originally GDP was a fully state-owned firm. This changed in 1999, when the government established GALP, as a merger of Petrogal and GDP. 41 Initially the Portuguese state had a majority of 60% of the shares and Petrocontrol, a firm of private Portuguese investors, owning most of the remaining part. Important steps towards a further privatisation and internationalisation of GALP were made in 2000. The Italian energy firm ENI acquired a share of 33.3%, the Spanish electricity producer Iberdrola 4%, the Portuguese electricity producer EDP 14.3%, and the banking group CGD 13.5%, while the share of the State reduced to some 34.8%. (See Fig. 12.10). The operation of the gas networks is based on concession agreements. Transg~s and the six distribution companies are awarded 35-years concession contracts granting them exclusive

41Source: International Energy Agency (2000), p. 70.

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National Reforms in European Gas

concession areas and rights for exclusive operations. regulations are: 42 9 9 9 9 9 9 9

Important

basic principles for pricing rules for relations with clients determination of investment targets rules for network operation and storage specification of investment targets for network expansion rules for the operation of networks and storage requirements for the capital structure of the firms.

Transg~s holds exclusive 25-year contracts with the distribution companies. The tariffs are based on costs-plus pricing, granting Transg~s a rate of return of 11%. A regulator for the natural gas market is officially established in January 1999 in an agreement between the Ministry of Economic Affairs and the industry association. 43 Next to the promotion of competition other objectives are the promotion of the development of the natural gas infrastructure, and a fair distribution of the valueadded of the gas industry between the operators and consumers. Tariff mechanisms and quality of service standards need to be developed. In time, TPA needs to be regulated. The regulatory office implements the general rules and guidelines that are given by the State. Because the State is also engaged in the sector as owner of gas firms, the regulator needs autonomy in order to ensure a level playing field and transparency in decision making. The members of the regulatory office represent different stakeholders in the energy sector, ranging from residential consumers to ministries and distribution companies.

12.4.3. Challenges in the ongoing reform process Portugal only very recently developed a natural gas infrastructure. The gas sector is barely five years old and is still in a phase of physical and commercial development. Investments in network and storage facilities are subsidised, and the use of gas is stimulated by tax reductions. Portugal is an example of an emerging market in the rulings of the EU directive. The restructuring process needs to start no later than 2008. The positioning of Portugal in the European gas market is at least for two reasons problematic. 42Source: International Energy Agency (2000), p. 71. 43Source: International Energy Agency (2000), p. 77/78.

Gas Markets in Southern Europe

305

First, Portugal has an unfavourable geographical location vis-a-vis the European gas market. This country has no domestic gas reserves and only very limited physical access to international gas supplies. There are only two international pipeline connections, both with Spain. An LNG terminal is under construction and scheduled to be operational in 2003. The closest gas producing country is Algeria, which is the most important gas supplier at the moment. The prospects of physical pipeline connections to other suppliers are very limited, because the long geographical distance implies high investment and transport costs. This very limited access to gas supplies seriously hampers the prospects for competition in a futureliberalised Portuguese market. Second, the young Portuguese gas industry has a difficult position compared to the established firms, especially on the Iberian market. Spain has a more developed gas industry and the sector is more advanced in the process of restructuring. For example, there are certainly opportunities for GALP to take profit of the Spanish experience. On the other hand the Portuguese government obviously seems to be opposed against too much Spanish influence in this strategic sector. Recently the Portuguese government intervened against an association between GALP and the Spanish Respsol. Italy's ENI seems however to be acceptable as mayor shareholder of GALP. There is a clear conflict between the economics and politics of the development of the Portuguese gas market. Apparently, international economic cooperation helps to develop a modern gas industry that is able to efficiently contribute to meet the increasing energy demand under increasingly strict environmental standards. On the other hand, even in a liberalised market the national government might wish to have some influence on the provision of this important primary energy source, for instance to ensure long-term security of supply or accessibility of gas for everybody. So far, the development of the Portuguese gas sector seems to favour the emergence of a strong national energy firm. GALP is not only vertically integrated, but also horizontally with oil and increasingly electricity. GDP and the regional distribution companies are granted monopoly positions. Long-term contractual relationships of 25 years between Transg~is and the distribution companies will become serious barriers to entry in a potentially liberalised market. The State of Portugal is not only engaged in the gas sector as a legislative authority, but also holds significant ownership rights. This dual position becomes even more complicated, as the function of the regulator still has to be fully developed. These conditions are not

306

National Reforms in European Gas

fundamentally different from other countries with a longer history in the gas sector. From the perspective of the development of a liberalised market, Portugal missed the chance to create right from the beginning structural conditions for competition. 12.5. Conclusions

This chapter describes the gas markets of three South European gas markets, i.e., Italy, Spain and Portugal. The gas markets in these countries are in very different stages of development. Italy has a fully developed gas infrastructure and belongs to the biggest gas markets in the EU. Portugal's gas industry is still emerging and was established only a few years ago. The EU directives grant Portugal a transition period until 2008 before opening its gas markets. The Spanish market is somewhere in between these extreme cases. Italy is the third largest national gas market in the EU, after the UK and Germany. This country has a quite well-developed national gas infrastructure and with ENI/Agip and SNAM world leading gas and oil companies. However, for the further development of the gas industry, this country somewhat suffers from its peripheral location on the European continent. Gas suppliers are situated at quite a long distance from the Italian market, and hence huge investments are required to establish these links. The relative low degree of interconnectivity to different suppliers is certainly a disadvantage for the further restructuring of the Italian gas market. Market entrance is severely restricted by physical bottlenecks for import and transport of newly contracted gas to the final customers. Spain has still a relatively small gas market. However, the share of gas in the national energy balance is expected to grow from 11% in 1999 to 17% in 2010, which is nevertheless below the European average of 26%. The growth of the Spanish gas market is for a great degree the result of an increasing industrial use of this energy source. Also gas-fueled electricity generation, often as combined heat and power production, contributes to this development. As far as the peripheral location on the European continent is concerned, Spain suffers the same disadvantages as Italy with respect to the long distance to gas suppliers. Portugal is an emerging gas market that is barely five years old. The gas infrastructure is under development similar to the industrial structures. The national oil and gas holding company GALP controls nearly the entire gas sector. The company is vertically integrated and holds long-term contracts with distribution companies. GALP is also the sole importer of natural gas. These are quite unfavourable

Gas Markets in Southern Europe

307

conditions for the o p e n i n g of the gas m a r k e t that has to start at the latest in 2008. Portugal's geographical position is even m o r e peripheral than Spain a n d Italy. There are only t w o pipeline connections. A n LNG terminal is u n d e r construction. However, the P o r t u g u e s e gas sector is g r o w i n g rapidly. In 2000 already 10% of the national energy c o n s u m p t i o n w a s covered by gas. In 2015 this n u m b e r is projected to g r o w to 19%. The p e r i p h e r a l geographical location of these countries certainly limits the physical access to different sources of gas a n d restricts the d e v e l o p m e n t of competitive markets in this part of Europe.

Literature Autorita per l'Energia e il Gas (2002) March 29. www.autorita.it 3rd CEER-NARUC Roundtable, Rome 6-7 December 2001, www.ceer-eu.org Department of Energy (DOE) (2001) Country Analysis Briefs, Italy, December. www.eia.doe.gov / cabs/ italy,html. Department of Energy (DOE) (2002) Country Analysis Briefs. Spain, January. www.eia.d oe.gov/ cabs / italy.html DRI-WEFA (2001) Report for the European Commission Directorate General for Trade and Energy to determine changes after opening of the gas market in August 2000, Brussels. ECJ Energy (1998) Natural Gas Trading in Europe. London. ENI World oil and gas review 2002, http://www.eni.it/english/notizie/analisi/ pd f_world / oilgas_review_2002_en, pdf International Energy Agency (1999) Energy Policy of IEA Countries: Italy 1999 review, OECD. International Energy Agency (2000) Energy Policy in IEA countries: Portugal 2000 Review, OECD. International Energy Agency (2001) Energy Policy of IEA Countries: Spain 2001 review, OECD. EJC Energy(1998) Natural Gas Trading in Europe. London.

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Chapter 13 Developments and Trends in East-Central Europe and Algeria MAARTEN J. ARENTSEN AND ROLF W. KUNNEKE

13.1. Introduction

As a continuation of Chapter 12, this episode finalises the overview of market developments by looking at relevant countries that are not covered by the in-depth studies in this book. It is thus possible to provide a more comprehensive understanding of relevant trends and developments that influence the restructuring of the EU gas markets. East-Central Europe is an interesting region as it provides transport corridors for Russian gas to the West European market. Algeria belongs to the important gas supplying countries of the EU.

13.2. East-Central Europe

East-Central Europe can be divided into two different regions according to significance of the development of a liberalized European gas market. These are Southeast- and Northeast-Central Europe. Southeast-Central Europe, including countries like Romania, Bulgaria, and Moldavia, has no major pipeline connections to the Western European gas market. However, the region represents an important transit corridor for Russian gas to Turkey and Greece. The domestic markets in these countries are developing, but because of considerable economic and political risks, there is a lack of international investment. Potentially this region could be important in the mid- and long-term future for the transit of gas from the Middle East and the Caspian Sea area to the European market. Northeast-Central European countries include Poland, the Czech Republic, the Slovak Republic and Hungary. These countries, that will 309

310

National Reforms in European Gas

join the EU in 2004, are economically well-developed and hence provide much better conditions for the development of the gas sector as compared with Southeast-Central Europe. Additionally, all important Russian gas pipelines to Western Europe pass through this region. Although these countries themselves are very much dependent on Russian gas, they are increasingly successful in diversifying their gas supply from other countries, like Norway, Denmark and The Netherlands.

13.3. Northeast-Central Europe The share of gas consumption for the national energy balances significantly differs between the four countries. Poland has the relative lowest gas share with some 10%, compared with 20% for the Czech Republic, 41% Hungary, 1 and 32% for the Slovak Republic. 2 Coal is the most important primary energy source for Poland and the Czech Republic with shares of about 66% and 50% respectively in the national energy balances. For Poland the share of natural gas is expected to remain quite flat, as coal is often more economical than gas. 3 As a means to guarantee long-term security of supply, reliance on domestic coal reserves appears to be more favourable than depending on gas imports from mainly one country (i.e., Russia). Only Hungary and Poland have significant national gas reserves that cover an important part of the national gas consumption (Table 13.1). Table 13.2 summarises the originating countries of gas imports and ...... the percentage of the total gas supply. Clearly, Russian gas has a dominant position in this region. The Slovak Republic has the highest per capita gas consumption of the four countries. About 80% of the Slovak households are connected to the gas network. Gas consumption has been quite stable over the past years. Residential customers had the highest growth rate (24%) between 1997 and 2001. During these years, total consumption only grew at a rate of 5.5% (Table 13.3). As for Poland, the Czech Republic strongly relys on its domestic coal reserves. There is political reluctance to become too dependent on imported gas, primarily from Russia. In the 90s the government started a gasification programme, mainly for environmental reasons. Between 1990 and 1998 the local distribution pipeline infrastructure

11998 data. International Energy Agency (1998). 2Slovakian State Gas Company (2002). 3Energy Information Administration (2002 b), p. 5.

Developments and Trends in East-Central Europe and Algeria

311

Table 13.1. Natural gas supply (in bcm) 1 for Northeast-Central Europe

Czech Republic Hungary Poland Slovak Republic 2

Indigenous production

Imports

Exports

Total consumption

0.0228 3.872 5.118 0.1

9.341 8.731 7.951 7.1

0.001 0.002 0.041 0.0

9.442 12.233 13.167 7.2

11998 data. EIA Natural Gas Information 1998. Numerical differences account for stock changes. 22001 data. Slovakian State Gas Company. Slovensky Plynarensky Priemysel. Annual Report 2002. p. 12.

Table 13.2. Originating countries of gas supplies 1 Originating countries and shares in gas supplies

Country Czech Republic

87.3% Russia 8.9% Norway 2.7% Germany 1.1% domestic 57.9% Russia 8.6% Germany 2.7% France 30.7% domestic 58.3% Russia 2.6% Germany 39.1% domestic 98.6% Russia 1.4% domestic

Hungary

Poland

Slovak Republic IIEA Natural gas information 1998.

Table 13.3. Natural gas consumption in Slovak Republic 1

Large commercial users Small commercial users Residential Other users Total

1997

1998

1999

2000

2001

4.7 0.4 1.6 0.1 6.8

4.6 0.4 1.8 . 6.8

4.6 0.4 2.0

4.8 0.4 1.8

5.0 0.4 2.1

7.0

7.5

.

. 7.0

.

1Slovakian State Gas Company, Slovensky Plynarensky Priemysel, Annual Report 2002, p.13. Difference in consumption and supply might occur as a consequence of stock changes.

312

National Reforms in European Gas

grew from 15,000 km in 1990 to 37,000 km in 1998. 4 As a result, about 40% of households now use natural gas for heating. In Hungary, natural gas consumption steadily grew throughout the past decade. As a consequence of the development of local distribution networks, about 40% of household energy demand is covered by natural gas. 5 Northeast-Central European countries are strategically important for the provision of Russian gas to the West-European market. These countries provide vital transit corridors for the interconnection of the Russian-European pipeline systems. Major pipeline connections run through Poland, the Slovak Republic and the Czech Republic. About 70% of Russian gas that is dedicated for the Western European market is transported through Slovakia. This pipeline corridor is divided into two directions: to the south to Austria and Italy, and to the north to the Czech Republic and Germany. Poland hosts the Yamal pipeline that transports Russian gas to the German market. This is the only route that bypasses the Ukraine. Gas transports through the Ukraine became problematic because of Russian accusations of considerable gas thefts. A Yamal II pipeline through Poland could provide a solution to this problem. The negotiations about the routing of this pipeline project are ongoing but not finalised. Germany prefers a southern route to its industrial areas in the south, whereas Poland favours a connection with its industries in the north (Fig. 13.1). The four Northeast-Central European countries are all nominated to enter the European Union in 2004. As part of this preparation the energy sector has to be reformed. The list of requirements (the so-called 'acquis') includes, among others, preparations for the introduction of the internal energy market (the EU gas and electricity directives), and the improvement of energy networks in order to improve the physical possibilities for energy exchange. 6 The current status of the four countries discussed in this section is summarised in Table 13.4. With the exception of Slovakia, the countries opened this chapter of EU membership requirements in 1999, which means that they actually started with the formal preparations for getting their national energy markets in line with the EU provisions.

4EU Enlargement Watch, p. 15. 5EU Enlargement Watch, p. 21. 1998 data. In 1990, only 21% of household's energy demand was satisfied by natural gas. 6Commission of the European Communities.

r

Fig. 13.1. The European Natural Gas Transmission Grid, 1999. (IEA, Regulatory Reform: European Gas, 2000, p. 36.)

National Reforms in European Gas

314

Table 13.4. Status of energy acquis with respect to gas market liberalization (October 2002). Country

Status

Czech Republic

Chapter opened: second half of 1999 Status: provisionally closed in second half of 2001 Transitional periods: implementation of gas directive until end of 2004 Chapter opened: second half of 1999 Status: provisionally closed in second half of 2000 Transitional periods: none Chapter opened: second half of 1999 Status: provisionally closed in second half of 2001 Transitional periods: none Chapter opened: first half of 2001 Status: provisionally closed in second half of 2001 Transitional periods: none

Hungary Poland Slovakia

The Czech Republic was granted a transition period until the end of 2004 to meet the requirements of the EU Gas Directive. The EU report is very positive about the progress m a d e with respect to restructuring and privatisation in the gas market. The major players in the gas sector are privatised, and administrative capacities have been improved, especially with respect to the functioning of the independent regulator. For Hungary, the progress for restructuring of the energy market is slower than the Commission expected. Although a new law was introduced in the electricity sector in December 2001, no progress was m a d e in the gas sector. The adoption of a Gas Act is still delayed in parliament. The regulatory function needs to be improved. The EU report signals that in Poland the efforts for the restructuring of the gas sectors needs urgently to be enhanced. There is a lack of transparency and the restructuring of the Polish gas and oil company has been delayed several times. A p r o g r a m m e for restructuring and privatisation was adopted in August 2002. The Slovak gas market will be open only to a small degree. As of July 2002, customers with an annual consumption above 25 bcm, are granted free access to the gas market. January 2003 the threshold is 15bcm, and in 2008 5bcm. This only results in 10-15% of domestic consumption having free access to the market, which is below the EU requirements. The Slovak gas company SPP was partly privatised in March 2002. Clearly, the gas sectors in the four countries have still quite a long w a y to go to become sufficiently restructured to meet the EU requirements.

Developments and Trends in East-Central Europe and Algeria 315 13.4. Southeast-Central Europe Southeast-Central European countries include Romania, Bulgaria and Moldavia. Of these, only Romania has a significant indigenous production of nearly 11 Mtoe in 2000, 80% of its total gas consumption. However, Romania's domestic gas production is steadily declining. In 1992 its gas production was on a much higher level than today, i.e., 17.6Mtoe. Figure 13.2 clearly illustrates the declining total energy production of Romania. None of the three countries export gas. Their national gas markets still need to be developed. In this respect there is little to be expected from the gas markets in this part of Europe for the near future. Romania and Bulgaria are candidate members of the European Union, possibly joining the Union by 2008. Gradually they will have to prepare for the restructuring of their energy markets (Table 13.5). These Southeast-Central European countries are located in a potentially strategic position as a transport corridor for existing or prospective future gas stream to the continent. Presently, Russian gas flows through these countries to Turkey and Greece. Potential supply of gas from the Caspian Sea and Middle East countries would have to use this corridor to the European markets. Figure 13.3 illustrates the pipeline infrastructure in this region. The Middle East and Caspian Sea regions offer huge gas reserves that can help to meet the increasing energy needs in Europe

Fig. 13.2. Romania's total production of energy. (Energy balances of non-OECD countries, IEA statistics 2002, p. II.161.)

316

National Reforms in European Gas

Table 13.5. Natural gas supply in 2000 (in Mtoe)1 for Southeast-Central Europe

Bulgaria Moldavia Romania

Indigenous production

Imports

0.012 10.965

2.741 2.111 2.711

Exports -

Total consumption2 2.931 2.113 13.676

1Energy balances of non-OECD countries, IEA statistics 2002. consequence of stock changes, total consumption might not equal (internal production + imports - exports).

2As a

(Table 13.6). Middle-East countries (Iran, Qatar, Saudi Arabia and United Arab Emirates) are on ranks 2-5 on the world's most important gas reserves. Over time, the proven reserves in these countries has even significantly increased. Caspian Sea countries (Turkmenistan, Kazakhstan, Uzbekistan) hold positions 14, 16 and 17 of the list. However, this overview also illustrates the significance of Russian gas for the energy provision of Europe. Russia holds by far the world's largest natural gas reserves. Based on the present market conditions, the export of Middle-East and Caspian Sea ~as reserves to the European market is only a longterm perspective." Transcontinental pipeline connections between the Middle-East (in casu Iran) and Europe are not economic u n d e r the current technical and economic conditions. Besides, the political conditions are presently unfavourable. According to IEA calculations the delivery price of Iranian gas at the 'European gate' would be 1.5 times higher than gas from Russia, North Sea or Algeria. There is also a possibility that LNG shipment will become significantly more economical as compared with pipeline transport. The switching point between these technologies is some 4,000 km. With LNG possibly becoming more economical, also others suppliers are able to enter the European market on a larger scale, including Iran, Qatar, O m a n or Yemen. Caspian gas is not competitive under the present conditions. Only if North Sea reserves gradually deplete or if Russia incurs economic or technical difficulties in exploiting its gas reserves would this region become more important for the European gas market.

13.5. Algeria Algeria is the main gas exporting country on the southern boundaries of Europe. Other gas exporters on the African continent that are 7The following argumentation is based on: International Energy Agency (2000) p. 35 ff.

~,,~o

Pr~ r

~.,ao

Fig. 13.3. Black Sea infrastructure. (International Energy Agency, Black Sea Energy Service 2000.)

318

National Reforms in European Gas

Table 13.6. World natural gas reserves (first twenty countries) in bcm I

Russia Iran Qatar Saudi Arabia United Arab Emirates United States Algeria Venezuela Norway Australia Indonesia Nigeria Iraq Turkmenistan Malaysia Kazakhstan Uzbekistan Netherlands Canada China First 20 Countries Rest of the World World

1998

1999

2000

2001

2002

48,240 23,000 8,500 5,695 6,063 4,735 3,700 4,121 3,654 3,280 4,010 3,483 3,188 2,900 2,464 1,840 1,750 1,787 1,809 1,199 135,418 17,748 153,166

48,080 24,200 10,900 5,777 5,996 4,645 4,077 4,148 3,785 3,310 3,650 3,511 3,188 2,770 2,410 1,840 1,732 1,771 1,748 1,250 138,788 17,237 156,025

46,900 25,000 11,157 5,790 5,992 4,740 4,100 4,148 3,808 3,500 3,770 3,568 3,285 2,850 2,413 1,840 1,750 1,714 1,719 1,375 139,419 18,915 158,334

46,600 25,800 14,443 6,012 5,991 4,845 4,250 4,163 4,017 3,530 3,790 3,610 3,285 2,900 2,420 1,840 1,750 1,680 1,705 1,515 144,146 19,669 163,815

46,052 25,800 18,650 6,173 5,991 5,135 4,250 4,185 4,017 3,883 3,866 3,610 3,285 2,900 2,222 1,840 1,750 1,680 1,669 1,515 148,472 20,092 168,564

1ENI energy figures, http://www.eni.it

relevant for the European market include Libya and Nigeria. Algeria not only depends on pipeline connections to export its gas, but was the world's first LNG producer. This technology offers new export opportunities, not only to Southern European countries including France, Spain and Italy, but also for remote destinations like the USA. 13.5.1. Some core features 8

Oil discoveries in Algeria were first made in 1956 with the Hassi Messaoud oil field. Commercial production of natural gas started in 1961. The Hassi R'Mel field holds the main gas reserves of this country with proven reserves of about 2,400bcm out of a total of 4,250bcm. In 2000 the annual production volume was 139bcm, compared with 129 bcm in 1999.9 Two-thirds of the production is sold

8This paragraph heavily leans on Energy Information Administration (2002a). 9Sonatrach Annual Report 2000.

Developments and Trends in East-Central Europe and Algeria

319

to the European Union with Italy and Spain as the most significant receiving countries next to France, Belgium, Slovenia, and Portugal. In 2000, Algerian gas accounted for one-fifth of EU gas imports. Non-EU export destinations include Turkey and the USA. The physical gas infrastructure encompasses high-pressure pipelines with a length of 18,400km, 1~ 69 pumping and compressor stations, and 105 storage tanks with a capacity of 4million cubic meters. 11 Medium and low-pressure networks add-up to some 18,000km. 12 There are two LNG transport terminals, in Arzew and Skikda. The two most important pipeline connections to the European continent are: 9 The Trans-Mediterranean pipeline Hassie R'Mel field via Tunisia connection accounts for 76% of the 9 The Maghreb-Europe Gas pipeline via Morocco to Spain (ca. 1,900 km). gas exports.

(renamed Enrico Mattei) from to Italy (ca. 1,100km). This pipelined gas export; 13 (renamed Pedro Duran Farell) This pipeline transports 24% of

There are ambitious plans to raise export volume. The capacity of existing pipelines are to be raised by building additional compressor stations. In August 2000, an agreement between the Algerian gas and oil company Sonatrach and the Spanish Cepsa was signed to develop a sub-sea pipeline between these two countries. This MEDGAS project provides a direct physical connection between Algeria and continental Europe. The feasibility of other projects is under consideration, i.e., direct connections to Italy and Southern France. Figure 13.4 shows the rapid development of Algerian gas production in the past 18 years. As mentioned above, Algeria is the world pioneer in LNG production, starting in 1964 with the Arzew plant. Cheaper Asian LNG recently challenges this competitive advantage. Because of its early start, Algerian LNG production turned out to be more costly compared with modern Asian installations. This resulted in a lower demand for Algerian LNG, and hence an uneconomic overcapacity, which also adds to higher costs. This impelled the Algerian gas company Sonatrach to completely renovate its LNG facilities. An ambitious refurbishment programme was completed in 1999 (Fig. 13.5).

l~ km is owned by Sonatrach, 4,400 km by Sonelgaz. Data of the year 2000. USonatrach Annual Report 2000. 12www.Sonelgaz.com.dz. 13Sonatrach Annual Report 2000.

320

National Reforms in European Gas

Fig. 13.4. Totalproduction of energyin Algeria. (Energybalances of non-OECDcountries, IEA statistics 2002, p. II. 44.) LNG contributes very significantly to the gas exports of Algeria, as shown in Table 13.7. For 2000 about 45% of gas exports was LNG. For the domestic energy consumption, Algeria also depends very much on oil and gas. In 1999 the following primary energy sources satisfied the Algerian energy consumption: 14 Petroleum: 31.2%; Natural gas 67.3%; Coal: 1.3%; Hydro: 0.2%. Among others, domestic energy resources are used in the petrochemical industry and for electricity production. About 95% of the electricity plants is fired by natural gas. The state utility Sonelgaz supplies gas to about 180 industrial customers and some 200 urban centers. The domestic sales of this company in 2000 was 11.6bcm, of which 64% for electricity production, 22% residential users, and 14% industrial consumption. 15 The domestic use of natural gas is stimulated by governmental programmes, i.e., the national gas programme 1995-1999.

13.5.2. Sector organisation and challenges in the ongoing reform process The Algerian oil and gas industry is completely dominated by the state-owned oil and gas company Sonatrach and the state utility Sonelgaz. Sonatrach is engaged in the exploration and transport of 14Energy Information Administration (2002a), p. 14. 15www.Sonelgaz.com.d z

t'N

('966[ 'sd~IAI f~ou~/~s!tuouo3~t tunoIm~Od) "tuo~sAs ou!iod!d u~!~o~iV ~o!~IAI "~'r "~!~I

~3

National Reforms in European Gas

322

Table 13.7. Algerian gas exports 1998-20001 (mtoe).

Gas LNG

1998

1999

2000

26.4 24.5

32.1 26.0

32.9 26.6

1Sonatrach Annual Report 2000. gas, both with respect to pipelines and LNG. It also acts as the international trader for Algerian gas. Measured in the quantity of oil and gas reserves, Sonatrach belongs to the five biggest petroleum companies in the world. 16 Sonelgaz operates in the electricity and gas sectors. Regarding the electricity business, it is a completely vertically integrated firm, covering production, transport, distribution and sale. For the gas sector Sonelgaz predominantly concentrates on the physical distribution and national trade and supply of natural gas. As a consequence of Sonatrach's dominance, the opportunities for private sector initiatives and international participation are limited. 17 However, in the mid-1980s it became evident that foreign investments were necessary in order to initiate technical innovations in the gas and oil sector. Sonatrach did not have sufficient access to modern exploration technologies and consequently the production rate for gas and oil declined, as did national reserves. In the existing gas fields the lowering pressure had to be compensated for in order to keep production rates at a high level. Additionally, opening new gas fields was only possible under difficult technical conditions and hence required up-to-date technologies. Considering the low oil and gas prices during this period, Algeria suffered significant economic problems. It was necessary to open the country for foreign investors and know-how, after a period of political and economic isolation that started in 1962 when independence was gained form France. In 1970 all gas and oil concessions were privatised and the petroleum industry nationalised with Sonatrach as the actor in this vital industry. The Italian AGIP belonged to the first foreign firms that again became engaged in the gas exploration. Other international firms followed after the introduction of a law in 1991. The introduction of enhanced oil recovery technologies significantly contributed to the modernisation of this industry. Foreign investors include Mobil, Arco, Total, Occidential, BP/Amoco, Samsung and Wintershall. Joint ventures in the oil and gas exploration are initiated for example with the 16Gelder, p. 25. 17The following paragraphs strongly refer to Gelder p. 24-28.

Developments and Trends in East-Central Europe and Algeria 323 American Anadarko and Lasmo, the Danish Maersk oil, the British BP, Italian Agip, and the Spanish Cepsa. However, Sonatrach still is the leading firm coordinating foreign activities according to its long-term planning of the utilisation of the national gas resources. For example, in 1996 Sonatrach initiated a five-year investment programme of some 19.2 billion US dollar to stimulate the development of new oil fields and extension of the pipeline infrastructure. In an assessment of the Algerian economy in December 2001, the International Monetary Fond (IMF) urged the Algerian government to proceed with economic reforms, including privatisation, lowering the protection of the domestic industry and reducing the dependence on hydrocarbons. Algeria is preparing a privatisation programme and a new hydrocarbons law. Although Sonatrach will remain in public ownership, possibilities for foreign investments may be enhanced. Sonatrach might be forced to compete for new projects, and even non-core subsidiaries might be privatised. This is expected to contribute to further economic development for Algeria. However, there is strong opposition to these plans, among others from labour unions. At this stage it seems quite unlikely that the Algerian gas industry will be significantly reformed or liberalised in the near future. The gas and oil industry is the major economic pillar of Algeria and is of strategic importance for national income, employment and economic development. 95% of the export of this country is related to oil and gas and about 60% of the governmental budget depends on this sector. 18 Under these conditions the national government can be assumed to be quite protective of this industry.

13.6. Conclusions

The regions addressed in this chapter are of quite different significance for the evolution of a European gas market. Algeria seems to be eager to strengthen its position as an important gas-supplying country for Europe. The pipeline capacity is upgraded and new connections to the European continent are under investigation. As a world pioneer, the Algerian gas industry heavily invested in LNG technology, allowing gas to be transported by ship. In 2000 about 45% of Algerian gas exports was by LNG. Although for distances below 4,000 km LNG tends to be more expensive than pipeline gas, this technology offers openings to new geographical markets and 18Gelder, p. 24.

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National Reforms in European Gas

distribution channels. For some gas importing countries LNG is a means for diversifying gas supplies, and hence lowering dependence on certain pipeline connections. Especially Southern European countries including Italy and Spain take advantage of this. Gas exporting countries like Nigeria and Qatar are increasingly able to enter the European market via LNG. Algeria broadened its geographical market by delivering LNG to France, Belgium, and even the USA. Being less dependent on specific pipeline connections, the LNG market is quite open for global competition, for example from new Asian LNG suppliers. Gas markets in East-central Europe can be divided into two groups of countries comprising Northeast- and Southeast-Central Europe. Northeast-Central European countries, including Poland, Hungary, Czech Republic and Slovak Republic are scheduled to enter the European Union by January 1st, 2004. The reform of the national gas industries is in progress according to the requirements of the EU Directives. These countries attract foreign investment and their national gas markets are developing. As important transit countries for Russian gas to Western European markets, commercial involvement in this region is of strategic importance. Since dependence on Russian gas supplies is very high, national governments have developed policies for fuel- and gas-supply diversification. This is why some countries with domestic coal reserves still heavily rely on this fuel in spite of environmental pollution and possible cost disadvantages. Additionally, the coal mining industry provides significant employment, another reason not to shift too quickly to gas. Southeast-Central Europe (i.e., Romania, Bulgaria, Moldavia) is also an important corridor for Russian gas to Turkey and Greece and has some strategic importance for the long-term development of connections to gas supplies from the Caspian Sea and the MiddleEast. However, under present market conditions and the stage of technological development, these connections are not profitable. Romania and Bulgaria are candidate members of the European Union, with prospective entry in 2008. The national gas markets still have to be developed, the institutional and regulatory frameworks need substantive improvements. The stages of regulatory reform are quite different throughout the two regions addressed in this chapter. Algeria is far from liberalisation. State-owned firms control the gas sector. Some private investment is allowed under the leadership of the national gas and oil company. In the near future no significant gas market reform is expected in this country. Southeast-Central European countries are still in the process of transition from a Soviet-type economy towards a

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m a r k e t - o r i e n t e d system. Overall political a n d institutional structures n e e d to be s t r e n g t h e n e d . The gas m a r k e t r e f o r m can only be successful as a p a r t of this transition process. N o r t h e a s t - C e n t r a l E u r o p e a n countries are m u c h further in this respect. In this p a r t of Europe, r e f o r m of the gas sectors is at a stage w h i c h is close to EU r e q u i r e m e n t s . H o w e v e r , there is still a long w a y to go to realise o p e n a n d c o m p e t i t i v e m a r k e t structures.

Literature Commission of the European Communities (2002) Towards the Enlarged Union: Strategy paper and report of the European Commission on the progress towards accession by each of the candidate countries, Com (2002) 7000 final, 9/10/2002, Brussels. EU Enlargement Watch (2000) The Role of Natural Gas in Europe, http:// www.energiaklub.hu / englishweb/climate/climpub/Gasstudy.htm, October 2000. Energy Information Administration (2002) Country Analysis Briefs: Arab Magheb Union. January 2002 http://www.eia.doe.gov Energy Information Administration (2002) Country Analysis Briefs, North Central Europe, April 2002. http://www.eia.doe.gov Gelder, J.W. van, (1999) Het buitenland: deel 16 Algerije, In: Tijdschrift Gas, July/ August, pp. 24-28. International Energy Agency (1998) Natural Gas Information 1998, Paris: OECD/IEA. International Energy Agency (2000) Black Sea Energy Survey 2000, Paris; OECD/IEA. Slovakian State Gas Company (2002) Slovensky Plynarensky Priemysel, Annual Report 2002. Sonatrach (2000) Annual Report 2000, http://www.sonatrach-dz.com www.Sonelgaz.com.dz

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P A R T III

Perspectives

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Chapter 14 National Prospects in the Dawn of the Internal Gas Market MAARTEN J. ARENTSEN AND ROLF W. KONNEKE

14.1. Introduction

The rich and detailed analysis in the previous section illustrated the emerging dynamics and change in national gas markets. These have clearly been initiated by the requirements of the EU Gas Directive. Only the pioneering gas market reform in Great Britain preceded EU liberalisation requirements. The process to attain common ground for the internal gas market was long and full of political disagreement. It took many years to find a compromise, which in the end resulted in a rather minimal Gas Directive. It was not an inspiring and motivating piece of EU legislation, and only provided weak guidance for establishing the new legal order of a competitive internal gas market. The directive left too many issues unresolved and allowed too much freedom. Countries were free to shop the diverse set of regulatory requirements of the directive and, as previous chapters have shown, countries took the freedom to make regulatory changes in context of their specific national settings without too much concern for a common and unified EU gas market. This final chapter summarises and comparatively analyses the changes in the national gas markets. The aim of our analysis is to compare national developments, to trace patterns in gas market development in Europe, and from there, to assess the prospects of national positions in the emerging competitive internal gas market in Europe. The comparative analysis concentrates on the gas markets that have been analysed in the second part of this book. Additional to developments in these markets, this chapter includes as much as possible the developments in Southern and Eastern European 329

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countries and Algeria as described in Chapters 12 and 13. Our analyses will be guided by the central research question of the book: What are the major developments in the structure, technology and socioeconomic performance of national gas industries and what evolutionary patterns might be identified in the European gas market? Section 14.2 comparatively analyses gas market development in the various countries. This section focuses on national developments with the help of the three ideal-type models introduced in Chapter 4. This allows for a classifying of change in national positions in context of the emerging European gas market. Section 14.3 comparatively analyses the major developments in terms of structure, technology and performance of gas markets in Europe. This section focuses on functional developments in the European gas market. Based on this national and functional comparison, Section 14.4 analyses the major challenges of establishing a competitive European gas market.

14.2. Change of National Gas Markets

The analyses of change and development of national gas markets in the previous section showed how the EU Gas Directive in many countries induced gas market reform. The UK is one exception, having begun its reform process much earlier than other EU countries. Norway, Russia and Algeria, the three non-EU countries included in the book, also deviate from the EU-induced reforms. These gas producing countries anticipated the EU gas market reform, but initiated little change in the organisation of their domestic gas markets. They tried to strengthen their prospects as gas suppliers of the EU region. In fact these countries reviewed their national interest position as gas producing country in the prospect of the opening of the European gas market. The Netherlands, a significant gas exporting country within the EU, initially was also quite reluctant to liberalise. Gasunie remains the most dominant player. Third party access (TPA) to the networks was quite unfavourable for newcomers and only recently improved. In the present Dutch political climate it is still uncertain, to what degree the planned legal unbundling of Gasunie will be achieved. Especially for gas exporting countries it appears that the preservation of national interest positions is quite persistent. National governments and incumbent gas firms have much to lose and therefore are often fierce opponents of liberalisation. However, compared with the other gas producing countries, the Dutch gas market is the most liberalised, at distance followed by Norway, Russia and Algeria.

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This section systematises the patterns of change of national gas markets across Europe with the help of the three ideal-type models elaborated in Chapter 4. Departing from a dominant focus in national gas policies, Chapter 4 distinguished the public property model, the public utility model and the commodity model, each characterised by a specific set of institutional, technical and performance characteristics. The country analysis in the previous section showed that the public property and public utility model have guided gas market development in Europe in the pre-liberalisation era. The EU harmonisation requirements now force all EU countries to open up their national gas markets and to introduce competition. The EU directive did not specify the structure of a competitionbased gas market, other than in terms of basic conditions, such as third party access to pipelines, unbundling of trade and transmission and free choice of gas supplier. Chapter 4 went one step further and elaborated the core of a competition-based gas market within the commodity-oriented gas market model. Therefore, the commodity model will serve here as a reference point to evaluate the recent changes in the gas markets analysed in great detail in the previous section. The evaluative analysis that follows concentrates on the question of whether and how countries managed to integrate the initial public property or public utility orientation in national gas policies with the commodity orientation induced by the liberalisation requirements of the EU. Our analysis starts with the public property oriented national gas markets and will continue with the public utility oriented national gas markets.

14.2.1. The public property model in the prospect of liberalisation Prior to liberalisation the national gas markets of Norway, the Netherlands and Russia have been classified in Chapter 1 of the book as guided by the public property model. This section analyses how each country coped with liberalisation and harmonisation in Europe.

Norway: maintaining the property model Although Norway is not a formal member of the European Union, in terms of gas policy this country is clearly affiliated with the EU region. As a member of the European Economic Area, Norway is obliged to fulfill the requirements of the EU Gas Directive. In the 1992 European Economic Area Agreement, 1 the single market of the EU 1See for example: http://secretariat.efta.int/euroeco/

332

National Reforms in European Gas

was extended to three out of the four EFTA2 countries, Norway, Iceland and Liechtenstein. 3 As the largest European gas supplier, Norway is strongly dependent on gas trade with the EU and therefore also has an economic interest in complying with the new market regime. As the analysis in Chapter 5 showed, of all gas producing countries, the development of the Norwegian gas market almost perfectly matches the public property model. The national political focus was and still is entirely on gas resource policy. Norwegian performance is perfectly in line with the objectives, of maximising national welfare and prosperity. Norway most clearly developed a policy focus on the production and export of gas, almost completely neglecting the development of a domestic consumption market. Domestic consumption is minimal, restricted to specific industries and incidental residential use. Norwegian national energy provision strongly relies on hydro-based electricity. Natural gas was and still is perceived nationally as a polluting energy source and for that reason has not been considered as an alternative for 'clean' hydro-electric energy. Norway had no internal incentives to change its current gas policy. Moreover, Norwegian gas policy clearly holds anti-competitive elements. The Gas Negotiation Committee GNC for example was initiated to strengthen the position of the three gas traders Statoil, Norwegian Hydro and Saga in European bargaining. The entry of production and supply is strictly controlled and regulated in favour of the Norwegian publicly owned firms. The Norwegian property model even goes beyond the national gas industry by favouring Norwegian industry as suppliers of the Norwegian gas industry. In this respect, foreign concession holders of Norwegian gas fields have been forced to invest in the so-called Goodwill Program pursuing R&D for Norwegian industries. Shipping and transport, maritime engineering and consulting are important sectors benefiting from this programme. Norway's focus on production and export of natural gas is also reflected by the mature upstream pipeline system. The system is very well connected to major continental gas markets, including Britain, Belgium, Germany and France. The Norwegian gas industry fully depends on the needs and requirements of the European gas market. Norway has no national outlet for gas and no domestic incentives

2EFTA: European Free Trade Association, which holds its headquarters in Geneva. 3Switzerland voted to not join the European Economic Area.

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333

or pressures to change this position or to reform its well-organised upstream activities. Norway tried to keep its dominant European supply position as long as possible and only in 2002 addressed European pressure to reform its property-focussed national gas model. The European pressure was responded to by considering the partial privatisation of Statoil, by dismantling the GNC export monopoly and by erecting an independent transmission company. These all clearly reflected Norwegian willingness to open up its monopolised upstream gas market. At the same time however, Norway established a new company, Petoro, which was charged with the management of the state's interest portfolio in the operation of pipelines and the exploitation of the Norwegian gas fields. This is a clear signal of Norway keeping close to the property model and maintaining its national interest position in the emerging open European market. Table 14.1 illustrates the strong national orientation of upstream activities of the Norwegian gas sector.

Table 14.1.

The Norwegian

gas m a r k e t prior a n d after 2000.

I Public property

Public utility

Dominant policy focus I Resource policy Political-economic organisation Ownership structure Governmental control and regulation Economic regulation Number of actors Barriers to entry

Eligibility Pipeline infrastructure Interconnectivity Dominant functionality

Public dominance Focus on resources Producer oriented Focus on upstream: Controlled access and limited number of actors Not relevant International orientation Matured upstream system (production, transport, storage) Performance

Economic Public

Maximisation of state revenues National welfare and prosperity Petroleum activities as basis for new industrial development

[Commodity

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National Reforms in European Gas

The Netherlands: combining the best of two worlds The Netherlands is the second country positioned in the propertyoriented gas model although its national development pattern is rather different from that of Norway. The Dutch combined gas exports with a strong, well-developed nationwide domestic gas consumption market. The Netherlands had and still has one of the best-developed gas infrastructures in the world connecting both the industrial and household segments of the market to the Dutch gas fields. Natural gas is the most important primary energy source of the country as well as of power production. The Dutch developed a centralised national gas market model with one central co-coordinator at the core. A clear and consistent gas policy guided the development of the Dutch gas market. Policy initially gave priority to the domestic market, but quite quickly also waked to develop the Dutch export position. Strategic depletion of the Dutch gas fields became an important point of reference in Dutch gas policies from the beginning of the 1970s, aiming at the long-term security of national gas supply. The strong focus on long-term security undermined the European supply position of the Netherlands, but this was an explicit political choice. The Dutch gave priority to domestic gas supply until the end of the 1980s. Only then were the export restrictions relieved, allowing Gasunie to develop its European trade position. In this way, the Dutch managed to optimise the economic value of natural gas. As Chapter 6 showed, over the years gas revenues have been tremendous allowing the Netherlands to build a well-developed welfare state. In the first half of the 1990s the national sentiment was that the liberalisation debate of the EU would undermine the effective harmony of the centralised Dutch gas market model. For that reason the initial position of the Dutch in the liberalisation debate was rather reluctant. Until the mid-1990s Dutch governments were rather passive in the liberalisation debate reflecting a position that the best change was no change at all. Gasunie, the central gas market co-coordinator, held the same position and remained rather passive for a couple of years. Until late 1998 Gasunie did not anticipate the coming changes of the European gas scene, whereas the Dutch government had already announced liberalisation of the Dutch gas market in 1995.4 Gasunie relied on its strong national supply position and its reputation as an European gas supplier. Both domestically and abroad Gasunie had a strong record of past performance. Dutch customers had been and still

4Ministry for Economic Affairs, Third White Paper on Energy Policy, The Hague, 1995.

National Prospects in the Dawn of the Internal Gas Market

335

were served well at reasonable prices and for Gasunie it was rather unthinkable to give foreign companies access to the Dutch gas market. For European supply Gasunie had been and still was a reliable and well-performing gas supplier. However, in the second half of the 1990s demand for gas market reform increased especially from the side of Dutch industrial gas consumers and significant parts of Dutch energy companies. The industrial segment of the Dutch gas market demanded reform of Gasunie's monopoly position. A producer perspective, the Dutch were reluctant to liberalise whereas the consumer perspective requested opening of the Dutch gas market. This dilemma for the Dutch gas position is further reflected by the liberalisation process. The process only started in August 2000 after the inauguration of the Gas Directive requirements in Dutch gas legislation, and gradually but inevitably integrated the commodity orientation into the persisting property model. Table 14.2 summarises some core features of the Dutch gas market until 2002. Between 1995 and 2001 the Dutch position in the liberalisation debate changed. Initially, continuing the Dutch resource position and the central position of Gasunie were the major points of reference for Dutch reform policies. Gasunie anticipated the coming reforms by offering transmission services in late 1998 some two years before the introduction of the new liberalised regulatory framework. In this way Table 14.2.

T h e D u t c h gas m a r k e t until 2000.

I

Public property

I Public utility

Commodity

Dominant policy focus

I

I

Resource policy

Political-economic organisation Ownership structure Governmental control and regulation Economic regulation Number of actors Barriers to entry Eligibility Pipeline infrastructure Interconnectivity

Public dominance Focus on resources Producer and consumer oriented Focus on upstream and downstream: Controlled access and limited number of actors Regulated monopoly National and international Matured upstream and downstream system

Dominant functionality Performance Economic

Maximisation of state revenues

Public

National welfare and prosperity

Reasonable consumer tariffs and selective services

336

National Reforms in European Gas

Gasunie anticipated increasing criticism of its monopoly position in the Dutch market. By offering transmission services that were independent from volume sales, Gasunie intended to give a clear signal to the market that it was anticipating the introduction of competition in the Dutch market. Competition was indeed introduced in August 2000 when the new regulatory framework came into operation. The new law clearly reflected the ambition to open the Dutch gas market and to introduce competition. The gas law introduced TPA (third party access) and the administrative unbundling of Gasunie's transmission and sales activities by creating 'Chinese walls' between the different parts of this firm. The new law also continued the Dutch strategic resource policy by legally obliging Gasunie to continue the small field policy, a policy aimed at the preferential depletion of the Dutch small gas fields by using the large Groningen field as swing capacity. The new law also set a ceiling for the annual depletion volume of the Dutch gas fields, but at the same time terminated all former restrictions on Gasunie's sales policies. Gasunie was allowed to trade an annual gas volume of 80 bcm either domestically or abroad. From 2000, Gasunie was freed from such restrictions. In this way the Dutch maintained the best of two worlds: continuation of the strategic resource policy and the opening of the Dutch market. The short-term impact of the regulatory changes was a loss of market share for Gasunie in 2000, and a reduction in state revenues. However, by 2001 Gasunie had recovered from the shock by compensating the loss of domestic market share with new export contracts. In 2001 the volume of Gasunie's gas export exceeded domestic sales for the first time. After 2000 foreign gas increasingly entered the Dutch market. 5 The new law clearly broke with the former monopoly-based regulatory gas market model and reflected a serious ambition to introduce competition in the Dutch gas market. Between August 2000 and the end of 2001 the Netherlands made progress in the introduction of competition and the opening of the market. The Dutch gas market regulator, Dte, took a rather advanced position by systematically increasing the regulatory pressure on Gasunie, partly motivated by strong market criticism of Gasunie's access policy. Both regulatory and market pressure impelled Gasunie towards unbundling of trade and transmission activities. In 2002

5An import contract of Dutch electricity producers with Norway dates back to early 1990. This contract was a first attempt to challenge the monopoly position of Gasunie. Financially this contract was not very successful and was a rather isolated initiative for several years.

National Prospects in the Dawn of the Internal Gas Market Table 14.3.

337

The D u t c h gas m a r k e t after 2000.

I Public utility

[ Public property

I Commodity

Dominant policy focus Competition

Resource policy

Political-economic organisation Ownership structure Governmental control and regulation Economic regulation

Public dominance [ Focus on resources Sector-specific regulation geared to competition Network related, economic unbundling of Gasunie and local distributors Formal market opening but still significant market power of incumbents Stepwise opening of the market

Number of actors Barriers to entry

Eligibility Pipeline infrastructure Interconnectivity

High on transport and distribution Matured upstream and downstream system

Dominant functionality Performance Economic

Maximisation of state revenues

Public

National welfare and prosperity

Reasonable consumer tariffs and selective services

Competitive economic structures

Gasunie split into two independent corporations, one for transmission and one for gas trade and Gasunie also improved the conditions for gas transmission and transport. Furthermore, the Netherlands also accelerated the timeframe for market opening. Already by January 1, 2004 the Dutch gas market will be completely open, the date also marks the complete opening of the Dutch electricity market. Since August 2000 the Netherlands has been heading towards market opening and gas market competition 6 (Table 14.3). However, much remains to be done in order to improve conditions for gas competition. One controversial issue that needs to be solved is privatisation of the gas networks. At the end of 2001, there was no political support for privatising the gas network (nor the electricity network) in the Netherlands. Dutch political parties are questioning the ability of privatised networks to maintain the high quality 6Report to the E u r o p e a n C o m m i s s i o n , Vol. 2, p. 83.

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National Reforms in European Gas

reliability and security of Dutch gas supply. The changes in the Dutch gas market are summarised below and Table 14.3 illustrates the Dutch gas sector's hybrid structure; holding major elements of all three gas market models, after the introduction of liberalisation in 2000.

Russia: improving the property model Like Norway, Russia is not directly affected by EU gas market liberalisation, but the EU initiatives do have consequences for Russia. Russia holds the largest gas fields in the world and the country is situated close to the European gas market. Russia therefore is in a position to benefit from European gas demand now and in the future. However, thus far Russia has not managed to benefit from its tremendous gas reserves as effectively as for instance Norway and the Netherlands. The Russian gas industry has long been integrated in the communist-planned economy of the former Soviet Union. With the dismantling of the Soviet Union, the country's economy is in a process of transition. As for other Eastern European countries, the reform of the Russian gas industry became part of the nationwide economic and political transformations. The challenges are tremendous because Russia misses much background or experience in a market-based economy, while writing to improve the organisation and the performance of its economic system. The Russian gas industry, dominated by Gazprom, is facing the same challenge: improving the effectiveness and efficiency of the company, while improving its economic performance. The success of this effort is very important for Russian society because the performance of Gazprom determines the extent to which it will benefit from the tremendous gas fields. Gazprom is the country's major taxpayer and major contributor to foreign currency and of foremost importance for the national economy. As the analysis in Chapter 7 of the book showed, Russia is still lacking a consistent energy policy leaving the actual control of the nation's gas reserves to Gazprom. At the same time, Gazprom is closely tied up with the Russian governmental bureaucracy, leaving no room for any independent governmental control and regulation of the national gas industry. The Russian gas industry was and still is Gazprom and the company holds a national monopoly position along the whole gas chain. Table 14.4 clearly illustrates this point. Since 1992 there have been attempts to improve the state control of Gazprom, but thus far without significant success. In 1992 Gazprom was transformed into a state-owned Joint Stock Company as a condition for financial donation by the IMF. The IMF required that Russia unbundled the strong ties between Gazprom and the Russian

National Prospects in the Dawn of the Internal Gas Market Table 14.4.

339

The Russian gas market prior and after 2000.

]

Public property

I

Public utility

I Commodity

Dominant policy focus Resource policy. Industrial development. Political instrument to support the prevailing political system Political-economic organisation Ownership structure Governmental control and regulation Economic regulation Number of actors Barriers to entry

Public dominance Focus on resources Producer oriented Focus on upstream: Controlled access and limited number of actors Regulated monopoly

Eligibility

Pipeline infrastructure Interconnectivity Dominant functionality

International orientation Matured upstream system (production, transport, storage)

Selective Limited development of downstream system

Performance Economic

Public

(short term) Maximisation of state revenues by energy export. Stimulation development energy sector. Stimulation of industrial development and employment.

Low tariffs for residential customers (cross subsidisation)

bureaucracy in the expectation that these changes would improve the performance of Gazprom. The IMF's pursued structural change in fact strengthened Gazprom's national monopoly position. In the same way, the 1992 privatisation programme for the Russian gas industry failed. The programme enabled a theoretical privatisation of 60% of Gazprom's shares, but no private investor managed to get a shareholder position in Gazprom thus far. So all attempts to change Gazprom and to improve its performance have not thus far been successful. The technical and institutional modernisation of Gazprom and more broadly the Russian gas sector could be highly beneficial for Russian society. Domestically Russia could benefit much more from the national gas fields for economic development. However, under the

340

National Reforms in European Gas

communist regime, the gas industry was concentrated on the exploitation and export of gas. The former Soviet Union used the gas for economic exchange and political control of its communist allies in Eastern Europe and for that reason emphasised investment and development of upstream activities. The upstream activities were and still are strictly controlled and in fact only open to Gazprom. Currently G a z p r o m is more open for cooperation with Western companies, but companies other than Gazprom are not producing any Russian gas. The upstream activities are monopolised by Gazprom and the same holds for the transmission and export of the Russian gas. The Russian upstream pipeline system is more matured and some of the Russian gas fields are connected with Eastern European countries and from there to the European pipeline system. The domestic transmission and distribution pipeline system is far less developed only connecting large urban areas with the Russian gas fields. Natural gas takes a share of about 62% in the national energy balance. 7 Gas is used for electricity production and as energy resource for industries, but direct household consumption accounts for only 5% of the overall national gas consumption. 8 Generally, domestic gas market of Russia in general is still in an infant stage of development. In the short-term Russian interests lie in the improvement of the property model in order to benefit as much as possible from increased European gas demand. Improvement of the property model would require further transformation of Gazprom to bring the operation and performance of this company up to Western standards. A closer cooperation with Western gas industries would certainly contribute to improvements in technical and economic performance of the Russian gas industry. There are m a n y examples of international joint ventures for Gasprom, including the Dutch Gasunie and Italy's ENI. However, for the Russian government these joint ventures are primarily a means to develop new export markets, rather than the modernisation of its national gas industry. For the near future Russia will be challenged by improving the structure and performance of its national gas industry in general and

7International Energy Agency IEA, Energy Balances of non-OECD countries 1999-2000, 2002 Edition, p. II 165. This number refers to the total primary energy supply. 8In part, this is the consequence of the widely used district heating systems, especially for bigger cities. Most apartments use district heating, rather than stand-alone gas heating systems. District heating systems are often gas-fired, but their consumption is registered as commercial use. Besides, there are also regional differences in the use of gas. East of the Ural gas plays only a small role in the energy balance; west of the Ural, gas holds a very dominant position in the energy balance.

National Prospects in the Dawn of the Internal Gas Market

341

the performance of Gazprom in particular. From the perspective of the background and heritage of the Russian gas industry it could be wise to focus on the improvement of Russia's export position. In this way it is possible to increase the economic value of Russian gas for Russian society. On the other hand, further development of the huge domestic market could also contribute to the modernisation of the Russian gas industry. Entrance of new market parties, and limited competition as with the first phase of liberalisation in the EU, have proven to be strong incentives for modernisation. However, a fundamental reform of the domestic gas market is very difficult to obtain and under the current conditions unlikely to happen. Foreign gas firms taking significant market shares in Russia might be seen as political and economic threats rather than as solutions to the present problems of the gas industry.

Algeria: relieving isolation Algeria is not subject to EU legislation, but is encouraged by the IMF to restructure its economic regime. Opening up the domestic market and privatisation of key enterprises can contribute to the further economic development and modernisation of this country, according to the IMF. But there are also strong economic reasons for opening markets to foreign investment, as the brief description of this country showed. During the 1980s, Algeria suffered competitive disadvantage, because of lost market share due to increasing inefficiencies of the national oil and gas industry. At that time the country was quite isolated. After having gained independence in the early 1960s, the gas and oil industry was nationalised in the 1970s, with Sonatrach as the most important actor. Sonatrach was not able to catch up autonomously with gas innovations. For example the company did not manage to exploit new gas fields. Even the exploitation of existing fields became inefficient because of the declining natural pressure of these fields. Only with the help of foreign investors could these problems be solved and the national reserve position of the country improved. However, Sonatrach is still the dominant and only leading gas and oil company in the country, and foreign investment initiatives are submitted to the long-term plans of Sonatrach. Further privatisation and liberalisation are under serious discussion, but the government seems reluctant, and privatisation meets considerable opposition, from others such as labour unions. Among the gas producing countries included in the book, Algeria clearly is most reluctant to restructure its gas industry. The Algerian oil and gas sector fits very well into the public property model, without any significant changes before or after the introduction of the

342 Table 14.5.

National

Reforms in European Gas

The Algerian gas market prior and after 2000. Public property

Public utility

]Commodity

Dominant policy focus Resource policy. Industrial development. Political instrument to support the prevailing political system Political-economic organisation Ownership structure Governmental control and regulation Economic regulation Number of actors Barriers to entry

Public dominance Focus on resources Producer oriented Focus on upstream: Controlled access and limited number of actors

Eligibility

Regulated monopoly Pipeline infrastructure

Interconnectivity Dominant functionality

International orientation Matured upstream system (production, transport, storage)

Limited development of downstream system

Performance Economic

Public

(short term) Maximisation of state revenues by energy export. Stimulation development energy sector. Stimulation of industrial development and employment.

EU liberalisation policy. Table 14.5 shows significant resemblance between the gas markets of Algeria, Russia and Norway. In all three countries, gas and oil are the most dominant export products, but Algeria is the extreme case with a gas share of 95% of total exports. Consequently, there is a strong political need to control this vital sector. In order to stimulate economic development and successfully diversify into other economic activities that are less dependent on gas and oil, Algeria needs to open its domestic markets. The gas and oil reserves can help to improve the economic structure and social welfare of the country. Since the oil and gas reserves are finite, they can only temporarily be utilised in this process of economic and social

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343

development. Striving for long-term sustainability includes an economic and social restructuring process. Algeria is at a very early stage of this development.

14.2.2. The public utility model in the prospect of liberalisation A second group of countries, the UK, Germany and France, developed national gas markets guided by a utility orientation. This section analyses whether and how the gas markets of these countries changed in the dawn of liberalisation.

United Kingdom: pioneer of the competitive gas market The UK is clearly the European pioneer and front-runner in gas market liberalisation. British reform had a rather unique driving force, which was the economic reform policies of the Thatcher administration. Reforms were initiated in the 1980s and cumulated in a radical change of the British gas market in the 1990s. The British market was transformed in different steps and resulted in the most competitive gas market in Europe at the turn of the millennium. The reform process deviates in many respects from changes in other European gas markets. The gas market regulator was in charge of the reform process and backed by the British government. The regulator took an initiating and leading position in the reforms. Britain created its competitive market through systematic deregulation of the gas chain. In this way it completely transformed the initial public utility oriented model into a commodity-oriented model. For a long time the British gas market had a rather isolated position in Europe. Except for some LNG until the mid-1980 and a pipeline connection to the Norwegian Frigg gas field, the British gas market was literally an island in Europe. The British chose to bring the British gas to Britain and to develop a utility-oriented domestic gas market. A nationwide gas market was created in some 15 years, initially exempting power production from gas consumption. Britain gave priority to the household segments of the market and selected industrial segments. Until the beginning of the 1980s the wholesale and retail market was under monopoly regulation with British gas in a monopoly position. The dismantling of the monopoly position of British Gas began in 1982 with a change of legislation followed in 1985 by privatisation of British Gas. From that time on, the UK was systematically headed for competition in both the wholesale and retail markets. Upstream the market was already open and regulated by a system of concessions and licenses.

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National Reforms in European Gas

The UK also anticipated the continental gas market reforms by initiating the Interconnector between Britain and continental Europe. The pipeline was intended to improve British exports. The move towards export sales indicated radical changes in British gas policies between 1982 and 2000. The British intended to sell their gas resources either on the competitive domestic market or by export to Continental Europe. For the longer-term the Interconnector was meant to safeguard security of British gas supply by means of imports. In the short-term, however, the export volumes flowing through the Interconnector still exceed the import volumes. By 2000, the British reform process had made the British gas market the most competitive in the European market. The British market is an appealing example for those countries pursuing competition. The British case not only serves as example from a regulatory reform point of view, but also in terms of innovative business strategies. In this regard, Centrica provides a tempting example of how to innovate gas sales in the retail market by integration of other consumer products such as credit cards and mobility services. Tables 14.6 and 14.7 summarise the specific features of the British gas market before and after liberalisation. The radical differences between both situations illustrate the change from a public property model to the commodity model.

Breaking up market dominance: the German case Germany's gas industry has a tradition of more than 150 years. Town gas or coke oven gas was initially used for public lighting in the bigger cities, and later for industrial and residential purposes. In the Ruhr area, coke oven gas was a by-product of the strongly developing coal industry in this region. By the 1920s the mining companies had plans to develop a nationwide gas pipeline system for gas supplies to big cities. This revolutionary plan was strongly opposed by the regional and local gas firms that feared competition. It took more than 15 years before this local opposition was broken down. Because of military interests of the German war industry it is was possible to transform local opposition into what became the development of a nationwide gas network. Natural gas was introduced in the mid 1960s, after the discovery of the Dutch gas reserves. The Netherlands, Russia, Norway, Denmark and the UK became the major gas suppliers for Germany. Germany also has domestic gas reserves accounting for about 20% of the annual gas supply. Between the 1970s and the 1990s the German market developed rapidly and today about 75% of new houses are supplied

National Prospects in the Dawn of the Internal Gas Market Table 14.6.

345

T h e U K g a s m a r k e t p r i o r to l i b e r a l i s a t i o n .

I Public property

] Public utility

[Commodity

Dominant policy focus Resource policy

Political-economic organisation Ownership structure

Governmental control and regulation

Economic regulation

Number of actors Barriers to entry

Eligibility

Public dominance: Public ownership midstream and downstream, Public and private initiatives in exploration Focus on resources; Governmental veto right over gas imports and exports; Licensing and exploration regime Licensed Midstream oriented: exploration Monopsony buying of gas power of British Gas fields by private firms Upstream: Midstream and Controlled access and Downstream: Monopoly: British Gas limited number of actors Regulated monopoly: Fuel for premium applications: households and selected industry

Pipeline infrastructure Interconnectivity

Selective: UK as a gas island

Dominant functionality

Matured upstream and downstream system

Performance Economic

Optimise state revenues

Public

Overall benefit of the UK economy: providing cheap and clean energy for as long as possible

Reasonable consumer tariffs and selective services

with natural gas and nearly half of space heating systems are based on this fuel. The political-economic organisation of the German gas market prior to liberalisation was dominated by self-regulation of the gas industry. The Germans never developed specific gas policies at the federal level. Industry itself initiated the development of the politicaleconomic organisation for the coordination and support of the technical, economic as well as the political activities and interests of

National Reforms in European Gas

346 Table 14.7.

The UK gas market after l i b e r a l i s a t i o n . Public property

Public utility

[Commodity

Dominant policy focus Competition

Political-economic features Ownership structure Governmental control and regulation Economic regulation

I Private dominance Sector specific regulation geared to competition policy Network related (access, tariffs); unbundling of network and commercial activities Market driven Active stimulation of new entry, New business models, convergence of infrastructures and other business Competitive market

Number of actors Barriers to entry

Eligibility

Pipeline infrastructure Interconnectivity

Limited on international transport (Interconnector) and high on national level. Potential to increase international connectivity (Norway and Netherlands). Matured upstream and downstream system

Dominant functionality Performance Economic

Public

Reasonable consumer tariffs and overall services

International business orientation, convergence into other sectors (electricity) Competitive economic structures, although with questionable success.

the gas industry. For that reason, German industrial self-regulation, almost naturally, led to the development of economic cartels, granting gas firms their own supply areas for the benefit of their economic interests. The cartels were legally encouraged as a means to promote the provision of gas to industry and households. In this way the development of the German gas industry was strongly guided by economic interests but absent of competition. Prior to the EU liberalisation, Germany had a fully matured physical gas infrastructure and a stable institutional framework. The long tradition of self-regulation is characteristic for Germany, see Table 14.8.

National Prospects in the Dawn of the Internal Gas Market Table 14.8.

347

The G e r m a n gas market prior to liberalisation.

I

Public property

I Public utility

[Commodity

Dominant policy focus

] Market failure

I

Political-economic organisation Ownership structure Governmental control and regulation Economic regulation Number of actors Barriers to entry Eligibility

Public and private ownership Self regulation No specific federal regulation Upstream and downstream: Controlled access and limited number of actors I Legalised cartel Pipeline infrastructure

Interconnectivity

National and international Matured upstream and downstream system

Dominant functionality Performance Economic

Reasonable consumer tariffs and selective services

Static and dynamic efficiency

Public

Merging liberalisation in the EU region forced the German gas industry to reconsider its political-economic organisation. This challenged industry to combine the long tradition of self-regulation and cartelisation with the requirements of a liberalised, competition cartels oriented, gas market. During the reform process, the Germans again relied on the self-regulatory performance of the gas industry. In line with the requirements of the EU Gas Directive, the federal government only provided a new legal framework for the liberalised gas market. The Energy Act 1998 fully opened the German gas market and delegated the actual establishment of openness of the market and access to networks to the gas industry. After tough negotiations the German gas industry managed to agree on a negotiated access regime and this Verbdndevereinbarung fitted in the minimal requirements of the Gas Directive. Furthermore, the German government decided not to establish a sector regulator for the gas market as all other EU countries, but instead, the Germans relied on competition authorities and competition regulation to introduce competition in the German gas market. It is not clear yet whether this typical German regulatory model will be able to improve the competitiveness of the German gas market. Apart from the self-regulatory model, Germany is also facing a high degree of market concentration. The German gas market always has been and still is controlled by a small number of gas companies with

National Reforms in European Gas

348 Table 14.9.

The G e r m a n gas market after liberalisation.

I

Public property

I Public utility

Commodity

Dominant policy focus

I

I

I Competition

Political-economic organisation Ownership structure Governmental control and regulation Economic regulation

Public and private, with increasingly private dominance Competition policy Network related selfregulation (access, tariffs)

Number of actors Barriers to entry Eligibility

Market driven Oligopolistic market Pipeline infrastructure

Interconnectivity

National and international Matured upstream and downstream system

Dominant functionality Performance Economic

Public

Reasonable consumer tariffs and selective services

Static and dynamic efficiency Competitive economic structures and allocative efficiency

significant market shares. Continued mergers and acquisitions (e.g., E.ON and RWE), further increased market concentration and the dominance of privately owned companies vis-a-vis the many publicly owned municipal gas companies (Stadtwerke). The market dominance of this small group of companies is a serious barrier for competition in the German gas market and relieving this barrier is a core regulatory issue (see Table 14.9).

France: minimal change The utility-oriented French gas model still is focussed on elementary national public services and the French are confident that the established institutions meet this objective. The French generally have a high level of confidence in their national institutions and in the gas industry in particular. Thus far there has been no endogenous stimuli for change, because the gas sector is economically and socially efficient, at least in the perception of the French public. Consequently there was and still is minimal support for any gas market liberalisation, with France being one of the strongest opponents in the EU liberalisation debate. Of course France is committed to the Gas

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349

Directive, but the country did not make any legal changes before the deadline of August 10, 2000. At that time the new French gas legislation was still under preparation. France opted for minimal opening of the gas market. For potential third party entrants, the access to the French gas network still has major obstacles, which a r e largely related to the dominant market position of Gaz de France. New gas suppliers only have very limited success, as their market share is less than 5%. 9 Recent changes initiated by the EU Gas Directive have hardly affected Gaz de France's dominant position. Moreover, France is one of the two EU countries that will only open the gas market in line with the minimal threshold required by the directive, whereas all other EU countries exceeded the minimal threshold. In the case of France it is most clear that external EU pressure initiated change in the structure and organisation of the gas market. French gas companies need to comply with the unfolding competitive structures in Europe in order to safeguard long-term economic survival. This includes geographic diversification and re-orientation of the core business in which new opportunities for specialisation and synergies arise. The French market cannot neglect these changing business strategies in European gas. The French market holds a particular position. The gas market was clearly guided by the public utility model, but for French energy policy gas is subordinate to electricity. France's national energy policy combines both the property and utility orientations. The lack of significant domestic fossil energy resources led to a strong nuclearbased French electricity industry, which still is the major focal point of French energy policy. France developed a gas industry in addition to the electricity industry and compared with electricity, gas accounts for only a small share in the country's energy consumption. The French developed a gas market oriented towards resource management and this orientation is also reflected in the institutional organisation of the market. The ownership structure is completely dominated by the state, allowing only some private investments in upstream activities, including domestic production, transport and storage. The economic features of the French gas market are primarily determined by the positioning of Gaz de France as a regulated monopoly that dominates imports, transport, storage and distribution.

9Report to the European Commission, Vol. 2, p. 34.

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National Reforms in European Gas

Market access is strictly regulated, both for upstream and downstream activities. The EU driven market reforms led to a limited opening of the market for industrial consumers. For the initial step (in 2000), the opening of the market only involved 150 industrial sites, followed by another 300 in 2003, and ending with some 720 industrial consumers in 2008. Compared with the full opening of the market in other EU countries, the French opening is minimal. In Chapter 11, Finon argues that the emergence of internal incentives and external pressures could initiate a further opening of the French market. From a technical point of view, the French gas market is well suited for competition. The country's pipeline systems are well connected to the major European pipelines and to the important gas fields in and around Europe. Finon concludes, 'At present, the French gas system is technically and economically mature and could handle a competitive market'. From a technical point of view there are few obstacles for the introduction of competition. The obstacles are basically found at the institutional level and at the political level which has strong focus on public services and national interests. For France, institutional and political path dependency might be the major obstacles for introduction of competition in the French gas market. Time will tell whether the external competitive forces unfolding in Europe will be strong enough to push the French gas market towards more openness and competition. Table 14.10 illustrates the orientation of the French gas sector towards the public utility and public property model, even after the initial phase of liberalisation.

Southern Europe: getting connected to the market In Southern Europe, natural gas becomes increasingly important as a primary energy source. Currently, Italy is the third gas consumption market in the EU with a highly developed gas infrastructure, the Spanish gas industry is strongly developing and Portugal is building its gas market. Despite these differences in infrastructure and industry development these countries suffer from the same fundamental problem: limited access to international pipeline connections as a consequence of their geographical location. Because of this the physical conditions for competition from different gas suppliers are restricted. In order to diversify gas supplies, Southern European countries invest in LNG facilities. Since liquefied gas can be transported by ship, diversification in gas supply is no longer a technical problem but rather a matter of economic profitability. Under the current economic conditions, pipelined gas is still often cheaper than LNG.

National Prospects in the Dawn of the Internal Gas Market Table 14.10.

351

T h e F r e n c h gas m a r k e t b e f o r e a n d after 2000.

I Public property

Public utility

[Commodity

Dominant policy focus Management of national energy resources

Market failure

Political-economic organisation Ownership structure Governmental control and regulation

Economic regulation Number of actors Barriers to entry

Eligibility

Public dominance Overall energy policy, with priority given to electricity, in order to avoid too high import dependency for gas. Oriented on all stages of (national) energy value chain Focus on upstream and downstream: Controlled access and limited number of actors. Restricted development of national consumer market [ Regulated monopoly

Pipeline infrastructure Interconnectivity Dominant functionality

National and international Restricted upstream and downstream system

Performance Economic

Public

Static and dynamic efficiency within the framework of publicly defined goals and objectives. Restricted commercial development of GDF. Security of national energy supply; National industry policy; International relations.

Reasonable consumer tariffs and selective services

Public service obligations

Of these countries, Italy holds the best prospects for further liberalisation of its gas and oil industry. Next to the domestic production of some 20% of consumption, Russia (30%) and Algeria (34%) are the important gas suppliers of Italy. Dutch gas and LNG imports play a minor role. Although the development of new pipeline connections is quite expensive, the mid- and longer-term prospects for supply diversification and new market entrance appear promising. The Italian government made progress in the liberalisation process. The dominant gas company SNAM as well as the distribution companies have been legally unbundled. Complete opening of the

352

National Reforms in European Gas

market is planned for January 2003. Italy clearly is heading for liberalisation, but is still facing serious problems, in particular market dominance of SNAM and its long-term import contracts. In Spain gas consumption is still less than the EU average and further development of the Spanish gas market will require significant improvement of the current gas infrastructure. The Spanish dependence on Algerian gas is high (60%), whereas the GN (Gas Natural) group dominates 90% of Spanish gas supplies. The Spanish government developed ambitious plans for the further liberalisation of the gas market among others by announcing full market opening in 2003 and reducing the maximum market share of any supplier to 70% of the supply market. It is still unclear whether these initiatives will stimulate further development of the Spanish gas market. They concurrently show that the Spanish government is heading for more competition in the Spanish gas market, but clearly in the context of a utility-oriented gas market model. The Portuguese gas market has been derogated from the EU Gas Directive as an emerging market, but the country is facing some specific problems. Portugal is located at the periphery of the European gas network infrastructure, which gives the country an unfavourable supply position. Currently, the country completely depends on Algerian gas supply without any other gas fields nearby. Portuguese gas supply therefore, can primarily diversify only by means of LNG. Portugal indeed is investing in new LNG landing facilities. Furthermore, the Portuguese gas network is still immature and concentrates in the urban regions of the country. Therefore it will need huge investment to develop gas consumption in Portugal. Finally, the Portuguese gas industry is dominated by the national gas company GDP, which currently controls all vital parts of the Portuguese gas market. Portugal is challenged to solve these problems before 2008 when it is committed to the liberalisation requirements of the EU. Given the country's isolated position in the European gas network and the restricted reach of a mature Portuguese gas market in the European context, it is uncertain how the Portuguese gas market will develop over the next couple of years. The ambition of the Portuguese government is to develop the national market in the European context as a public utility oriented gas market.

East-Central Europe: managing the transition East-Central European countries are still in a transition phase from the Soviet-type planned economy to market economies, although they are at very different stages. Northeast-Central European, countries

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353

including Poland, the Czech Republic, the Slovak Republic and Hungary, will join the European Union in 2004. The countries are far ahead in the transition process as they satisfy most of the EU requirements for entrance. With respect to the liberalisation of the gas market they tend to satisfy the minimum requirements, hence they are certainly not forerunners in the reform process. The national gas markets need further development in the European context, both with respect to the physical infrastructure and the institutional requirements of liberalised markets. There is room for private initiative and foreign investment, but state-controlled firms still dominate the domestic markets. A high degree of dependence on Russian gas is a common problem for these countries, but they increasingly are succeeding in diversifying their suppliers. The public property model best describes the gas sector in this region. Northeast-Central European countries are strategically important for the provision of Russian gas to the Western-European market. These countries provide vital transit corridors for the interconnection of the Russian-European pipeline systems. Major pipeline connections run through Poland, the Slovak Republic and the Czech Republic. The gas markets of Southeast Central Europe (Romania, Bulgaria, and Moldavia) are still at an immature stage of development. The countries are nominated for EU membership in 2008 and therefore still have time to meet the minimum EU standards. However, all gas markets in the region still suffer from institutional instability and deficient physical infrastructure development. Under these conditions foreign private investment is unattractive. The current markets in the region fit in the public property model. In the long-term, Southeast-Central European countries might serve as transit corridors for gas pipelines from the Middle-East or the Caspian region. However, for the current European gas scene these investments are not profitable.

14.2.3. Conclusion: changing national positions This section has systematised the rich and detailed country analysis with the help of the three gas market models developed in Chapter 4. It showed that the public property and public utility orientation has guided national gas market development in Europe. Furthermore it showed how countries are handling required change within their gas markets and try to integrate the commodity orientation in their former utility or property orientation in gas policies. The general picture is still quite diverse. Each country naturally follows its own route of change. Some countries take a rather advanced position in market

354

National Reforms in European Gas

opening, like the UK and, in a formal sense, Germany, whereas other countries opt for a more gradual route of change, like the Netherlands and France. Thus far the two major European gas suppliers, Norway and Russia, have hardly moved their initial national position, but EU pressure to open up the Norwegian monopsony position is growing. Russia still faces severe internal transformation problems and trying to be more open for European gas industries. The position of Algeria is similar to that of Norway and Russia. The EU liberalisation requirements hardly affected Algerian gas policies and in counter distinction to Norway, the country is not committed to the EU in any respect. Algeria clearly fits into the public property model, without any significant change before and after liberalisation of EU gas markets. Spain and Italy resemble the public utility model characteristics, but the organisation of the gas markets changed due to the EU Gas Directive. Italy changed its regulatory regime for the gas market and is trying to increase competition by putting restrictions on the dominant market position of ENI. Spain is also committed to the requirements of the Gas Directive and, like Italy, is facing the problem of dismantling the dominant position of the incumbent gas company. Portugal is challenged with developing a domestic gas market and with making institutional arrangements for the introduction of competition in 2008. Countries in East-Central Europe are best categorised by the public property model, since the process of restructuring is at its best in preparation. Table 14.11 summarises the national positions before and after the introduction of liberalisation. Of course these kinds of classifications are necessarily arbitrary and subject to discussion, because they can only reflect the situation at a certain moment in time, whereas gas market changes continue. Table 14.11 therefore reflects the legal and policy changes in national positions at the end of 2002. Table 14.11.

Changing national gas market positions. Policy focus before liberalisation

Public property Policy focus after liberalisation

Public property Norway Algeria Russia

Public utility

Commodity

Netherlands

Publicutility

Portugal France Spain East-Central European countries UK Germany Italy

Commodity

National Prospects in the Dawn of the Internal Gas Market

355

Norway, Russia, and also Algeria are still strongly oriented towards the public property model. Although these countries are not legally committed to the EU requirements, they actually did not anticipate liberalisation. The changes in France have been minimal and the country was and still is strongly oriented towards the utility-oriented gas market model. The UK changed its focus from the public utility model to the commodity model already before the EU Gas Directive became effective. The UK was already oriented towards the commodity model in the 1990s and this was not affected by EU liberalisation. In fact, the EU requirements found fertile soil in Britain. The country clearly takes a front-runner position in the establishment of an open and competitive gas market. Only two countries have changed more significantly in the aftermath of the Gas Directive, the Netherlands and Italy, but their change pattern is quite different. The Dutch approach to competition is top down oriented, due to the strong initial position of the Dutch government and the Dutch gas market regulator. The Dutch initiated competition with strong regulation and by putting strong regulatory pressure on the market. At the same time, the Dutch tried to maintain the property orientation by adjusting its resource policy to the emerging competitive market. Recent initiatives to further dismantle Gasunie clearly indicate the Dutch ambitions to develop a competitionbased gas market in the European context. Italy, Europe's third gas market, is the second country to make progress towards the introduction of more competition. As with the Netherlands, the national government appears to be dedicated to competition and private initiatives. However, the market is still dominated by ENI, and there is only limited physical infrastructure capacity for new entrants. At the same time, the national government has restricted ENI's dominant position by forcing the company to sell part of its gas imports. Germany introduced a new gas law requiring third party access and the full opening of the gas market whereas the actual establishment of a competitive market is left to the market with the German competitive authority in a referee position. The economic market structures in Germany are still very closed, and therefore the legal introduction of competition and market opening is not reflected in the actual accessibility of the German market. At the end of 2002 it was unclear whether the legal changes made in Germany indeed improved the actual market access and degree of competition in the German market. In all other countries displayed in Table 14.10 the EU liberalisation initiative has not yet resulted in significant legal or policy changes.

356

National Reforms in European Gas

Portugal and the East-Central European countries were and still are characterised by the public property model, whereas the differences between the national gas markets are still substantial. Regarding the maturity of the gas market, all countries still deviate from the average West European standard. But the Central European countries nominated to join the EU in 2004 are much ahead of other countries in the Eastern region, i.e., Bulgaria, Romania and Moldavia. To conclude, two extreme positions appear to determine the range of change in country positions for the near future. At the one end we find the British model with the commodity focus dominating all functions and segments of the national gas market. The British market most clearly displays openness and competition. At the other end of the spectrum are the countries that are making only minimal changes in national gas market regulation and national gas policies. France is a clear example of this. In the French model statism, national energy policy objectives and public service obligations are still major points of reference in national gas policies. Furthermore, the French model is somewhat hostile to competition in the national gas market. Germany is a special case in the European spectrum. The country's regulatory change has been significant, but the actual market change is left predominantly to the incumbent market players. In the benchmarking report of the EU, German access conditions have been classified as rather poor, indicating that there is still significant imbalance between legal and actual change in German gas policies. In the Netherlands and Italy the actual progress made in market opening is more promising. Italy established an independent system operator and the Dutch are considering the same. Both countries have strong gas market regulators clearly focussing on improving the conditions for competition in the national gas market.

14.3. Changing Structures, Technology and Performances in European Gas The previous section comparatively analysed the changes in the national gas markets in Europe and showed that countries, each in their own way, moved from the initial property- or utility-oriented focus towards a more commodity-oriented focus in national gas policies. Further, countries develop their own pattern of change, with some countries in a front-runner position and some countries in a more backward position. This section analyses the recent changes in European gas from a functional perspective, by focussing on change in terms of the structure, technology and performance at the European level.

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14.3.1. Changing political-economic organisation The national stories told in the previous section showed that changes in European gas in general have been initiated by EU legal forces. Despite the initial Union-wide hesitation about any regulatory or industrial change, member states in fact followed the directive in a rather advanced way, at least from a legal point of view. With only a few exceptions, all member states committed to the deadline of August 2000 for inaugurating national gas market regulation as requested by the directive. In a country like the Netherlands, this EU requirement initiated the first nationwide public legislation on gas. In general, countries did not attempt to frustrate the legal harmonisation, but instead initiated new legal regulatory frameworks in line with the directive. Remarkably, almost all EU members opted for full market opening instead of the 34% as required by the directive. Germany opened its gas market completely in 2000 and almost all other EU members announced full market opening within a few years time. Only France and Denmark kept to the minimum requirements of the directive. Portugal and Greece, considered as emerging markets are therefore entitled to delay their market opening until 2008. Denmark is also short of full market opening, allowing only 43% free access in 2008. Almost all countries made legal provisions for third party access to the pipeline infrastructure on the basis of regulated TPA, instead of negotiated TPA, as was initially expected. Countries also made provisions for unbundling transmission and trade activities of the vertically integrated national gas companies. These companies had long dominated national gas markets as central co-coordinators of national gas supply and as national operators of the transmission pipeline infrastructure. These 'national champions' not only dominated the national gas markets across Europe, but they also controlled and co-coordinated the cross-border flow of gas. The Gas Directive initiated the unbundling of the trade and transmission activities of these companies, which have been vertically integrated for many years. Initially, the unbundling of trade and transmission only met the minimum requirements of the directive for administrative or financial separation of accounts. In 2001 several companies decided to more radically separate both types of activities by establishing separate and independent organisations for trade and transmission. The Dutch company, Gasunie, is a clear example of taking this second step of unbundling. On January 1 2002, the company divided into two separate companies, a separation that responded the dynamics of the gas

358

National Reforms in European Gas

market. Taking this step, Gasunie was ahead of the reform policy of the Dutch government. Given recent changes in the policy climate for this country, it has yet to be seen whether this step was too fast or not. Except for Germany, all member states established sector specific regulators, most of them integrated for gas and electricity. Germany insisted on competition regulation of the federal competition authority, the Bundeskartellamt. Both approaches satisfy the requirements of the EU directive to create legal provisions for dispute and conflict resolution. The general idea is that strong and independent supervision is needed in order to enforce the development of competitive markets. Sector-specific regulation and competition regulation are based on quite different assumptions and philosophies of how to stimulate the evolution of competitive markets. Sectorspecific regulation is ex-ante or ex-post oriented, and based on the intervention of a regulatory body that determines the terms and conditions for pipeline and market access. Competition regulation trusts the self-regulatory capacity of the market and is mainly focussed on enforcing competitive market structures without making differences between specific industries of sectors. For gas market regulation all EU countries adopted the sector regulatory model except for Germany. But the revision of the Gas Directive, still in discussion at the end of 2002, might force Germany to establish a sector regulator for the gas market. To-date however, all member states have established mechanisms to oversee the adequate functioning of a liberalising gas market. In this way the long and intensive EU political debate on energy market reform was followed by rather fast and at some points unexpectedly radical legal change of national regulatory frameworks for gas. In the first eight months after the inauguration of the new legal order it became clear that the legal reforms had not settled the barriers in the free trade of natural gas across Europe. At the legal level, the directive had initiated some regulatory harmonisation, but in practice the barriers to pipelines and market access were tremendous. It soon became clear that the legal changes were only a necessary first step and that the real opening of the European gas market was still at its beginning. The basic problem to be solved was the technical, economic and managerial compartmentalisation of the European gas market. The integration of the technical system, needed for an European-wide free gas flow, turned out to be a tremendous challenge, not only for national governments, but also for national regulators, the gas industry and gas consumers. The actual harmonisation of access regimes of the European pipeline systems each with their own technical and managerial national background has proven particularly

National Prospects in the Dawn of the Internal Gas Market

359

difficult. Harmonisation at this complicated system became the major topic of the further harmonisation of the internal market. A tough topic given the strong interests involved. 1~ The access to pipelines represented the access to the markets, as those controlling access to pipelines would also control the market. An EU-initiated review indeed revealed restricted progress in openness and competition in the national gas markets in Europe in the first eight months after liberalisation. 11 The review pointed to emerging competition in some countries but also to serious access problems in almost all countries except for the UK and to a lesser extent for the Netherlands. The average level of third party access across Europe increased by 2.2% between August 2000 and March 2001, representing some 30% of the total gas volume traded in Europe. The report also mentioned newcomers to the gas market, basically gas traders and producers directly supplying gas to consumers without intervention of traders. Consequently the political-economic organisation in Europe changed in the first months after the introduction of liberalisation, leading to some openness of national gas markets that had been rather closed until then. Across Europe TPA regimes were established and vertically integrated companies were unbundled. The political-economic organisation of European gas was enriched with a sector regulator, who took the regulatory job quite seriously for all of Europe. All European countries in one way or another adapted to the commodity orientation in national gas policies, although the initial changes were restricted to the formal and legal level. These changes show the significance of the Gas Directive for change in political-economic organisation of the European gas market. The directive was a necessary first move towards initiating any change across Europe at all.

14.3.2. Changing technology In terms of technical change for the European gas pipeline infrastructure, the Gas Directive was far less initiating than in the case of change in regulatory framework and political-economic organisation. The technical aspects of the European gas system to a

1~ for instance the agenda of the Madrid Forum. 11Data are taken from DRI-WEFA, Report to the European Commission Directorate General for Transport and Energy to determine changes after opening of the gas market in August 2000, Vol. 1 and 2, Brussels, 2001.

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National Reforms in European Gas

large extent have been determined by the ilocation of the gas fields. The prospect of liberalisation did however, initiate new investments in pipeline infrastructure in Europe. The drive was to improve the European resource position and from the perspective of the producing countries, to improve their trade position within Europe. During the 1990s Europe heavily invested in new pipelines. In the north, the Norwegian gas fields on the Continental Shelf became connected with continental Europe by four major gas pipelines. I n the late 1999s Gazprom constructed the Yamal pipeline connecting the Western Siberian gas fields with Continental Europe. The Yamal pipeline improved the gas supply to north-western Europe. In the south, France and Spain established an interconnector between the countries' gas pipelines; and Algeria developed three different pipeline routes to connect its gas fields with the European gas market, two running to Italy and one running to Spain. France and Italy are currently constructing a connection between the two countries. Finally, in the west, Europe connected to the British gas fields on the British part of the Continental Shelf, a connection that became operational in 1998. Due to these investments, European pipeline infrastructure increased by some 54% to 18.834km in 1997.12 The increasing importance of LNG is referred to in various country studies. During the 1990s several years before the EU agreement on gas market harmonisation, the European gas industry invested in the European gas pipeline infrastructure with the expectation of increased gas consumption in Europe. Under liberalisation the new connections with the production fields in and around Europe gained importance. Gas is generally recognised as the booming energy resource in Europe, with the power sector as one of the most promising market segments. A well-developed pipeline infrastructure both upstream and downstream is a necessary condition. The European landing points of the important gas pipelines are well-positioned to develop hub functions. Such a hub is currently under development at Zeebrugge, where British gas connects to the continental pipeline system. The prospects of developing a hub in northern Germany are promising too where Norwegian and Danish gas land in continental Europe. Consequently for the upstream part the European pipeline system is quite wellprepared for competition and openness of the European market, although some countries have better prospects than others. Southern European countries especially suffer disadvantages in this respect, whereas Eastern-Central European countries are still very dependent 120ostvoorn & Boots, p. 23.

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361

on Russian supplies; but these countries increasingly succeed in diversifying their supplies from other sources. One of the major challenges Europe currently is facing is to interconnect the different national high-pressure pipelines to really establish a free and unconditional flow of natural gas all across Europe. The technical part of the challenge is to harmonise the technical operation of the different systems all across Europe, to deal with the differences in gas qualities within the European pipeline system, to make optimal use of the storage facilities across Europe, to balance the systems, and respond to requests for transport capacity. The establishment of technical interconnectivity between the different systems is a minor problem compared with the non-technical challenge to establish interconnectivity between the European pipeline systems. The institutional and managerial barriers in the European pipeline system are still tremendous and both European gas transmitters as well as European gas regulators must address the barriers. A prerequisite for an open and competitive-based European-gas market is that the cost of gas transport reflects the scarcity of transport capacity in Europe. The current transmission tariff systems in Europe do not refer to capacity yet, but instead are based on transported volumes. Due to the current separation between the transmission systems in Europe, both in terms of ownership and in terms of management, third party transport is facing the problem of 'pancaking'. Each system transporting a certain volume of natural gas, charges its own tariffs, resulting in cumulating transportation costs the more systems the gas volume passes. At the end of 2001, 'pancaking' was one of the most serious complaints of European shippers and industrial consumers next to lack of transparency on capacity availability of transmission tariffs. The commodity model requires pipeline infrastructure allowing for entry exit tarification all across Europe. This kind of tarification was not a reality at the end of 2001, although there were signals of change in this respect. The high-pressure pipelines across Europe were still offering access services calculated with volume-oriented methodologies and tariffs, whereas the commodity model requires capacity based calculation methodologies. Such a capacity-oriented transportation system would require far more integration between the different European pipeline systems. It is questionable whether this will ever be established given the strong institutional separation between the current high-pressure pipelines in Europe and the tremendous financial interests and risks at stake for the owners of the systems.

362

National Reforms in European Gas

14.3.3. Changes in socio-economic performances The Gas Directive affected the initial socio-economic performance orientation across Europe. All European countries have to take the commodity orientation into consideration, meaning that they no longer can resort to a public property or public utility orientation. The emerging opening of the European gas market forces countries to compromise the dominant performance focus in their gas policies. Countries gifted with their own natural gas resources adjusted their resource policies in anticipation of liberalisation. The most extreme case in this respect is the Netherlands. The Dutch government decided to change its resource strategy, allowing for an annual depletion of 80 bcm of Dutch natural gas, leaving to Gasunie the decision of how and where to sell this volume. At the same time the country no longer considers the long-term security of domestic supply as the basic point of reference of resource policy, expecting foreign gas to flow to the Dutch market (as indeed happened after the market opened in 2000). The Dutch government did however continue its small field policy as one of the public service obligations of Gasunie keeping the Dutch gas reserves operational as long as possible. Whatever their initial performance position, countries are forced to integrate competition and openness into their performance orientation. The public service obligations many countries fostered in their national gas policies before liberalisation have been transformed in new public service obligations under liberalisation. Some countries only opted for a minimum set of public service obligations, regulating only basic security and reliability issues in particular for the private gas consumers. Other countries initiated a broader package of public service obligations also including environmental and energy saving issues. As a result, the organisation, technical aspects and performance of the European gas scene are changing, but there is still a long way to go to establish a real competitive European gas market. The next and final section of the book discusses some future lines in European gas market developments.

14.4. From National Regulatory Reform to European Competition? This book opened with the claim that a national perspective in EU gas market liberalisation and harmonisation is important. The detailed histories of national gas market development in the second section underlined the significance of such a national focus. Unfortunately the book could not include all gas markets in the EU region and could

National Prospects in the Dawn of the Internal Gas Market

363

only concentrate on representative but important gas markets of Europe. The set of representative national stories included here, confirm the significance of a national analysis of gas market change and reform. In Europe, gas markets have been designed and developed in a state-dominated process and with a strong national interest focus. States have long controlled the national value chain of gas. Private companies were only allowed in the upstream production of natural gas, but in these activities too, the state took a strong partnership and regulatory position on all production locations in and outside the EU region. Midstream and downstream state-owned companies dominated the gas scene everywhere in Europe. The country analysis further showed how national gas policies guided the initial design and development of gas markets in the EU region and the specific nationally oriented political decisions countries took in this respect. No national development is similar, even for countries that have adopted similar points of reference in their national gas policies. Furthermore, the analysis shows that liberalisation does not seriously affect the national focus. Countries respond to the harmonisation requirements with strong reference to national gas policy interests, in many cases with the state in a managerial position of the change process. At the end of 2001 the changes still concentrated on the national regulatory frameworks, access to national pipeline systems and opening of national gas markets. The European gas scene has hardly changed thus far. European gas markets are still operating independently from each other, and the cross border gas flows in Europe are still basically the volumes contracted bilaterally in long-term contracts in the pre-liberalisation era. Thus far, liberalisation has initiated change in national gas markets in Europe, but has not yet affected the outlook of the European gas scene. Changing the European gas scene, dominated by bilateral long-term gas contracts, will be the next major challenge in the process of establishing a competitive internal gas market in Europe, next to improving access to national pipelines and national gas markets. Given the moves of countries thus far, it might be expected that improvement of access to national pipelines and national markets would be a minor challenge. Since the mid-1990s much has changed in the gas markets of Europe and these changes are far from consolidated. The first year of liberalisation in particular displayed quite some dynamics. National legal frameworks changed from monopoly to market-based regulation. Almost all European countries dismantled their national champions, the vertically integrated national gas market co-coordinators, and erected strong gas market regulators to establish and regulate access to the gas network and market. At the

364

National Reforms in European Gas

same time, the European energy industry displayed high business dynamics by developing new alliances, entering new functions into the gas chain, by developing activities across the gas and electricity chain, and by merger and acquisition. Although there are still many problems to be solved, national gas markets are opening up and national governments are trying to introduce competition into the national gas market. Member states no longer only express the ambition of competition but in general all are making efforts to establish the necessary conditions. Some countries have revised initial positions in regulatory reform, for instance by taking stronger steps in the unbundling of trade and transmission and by strengthening the position, power and instruments of the gas market regulator. At the national level, the privatisation of gas companies and the pipeline systems operated by these companies might be a major issue in the near future. It is far from clear how countries will respond to the privatisation of companies and pipeline systems. Only the UK clearly opted for privatisation, but in general, European countries are reluctant to privatise. Perhaps the late 2001 political debate on the issue in the Netherlands is representative of Europe in this respect. The Dutch government does not allow the privatisation of the property of the national gas and electricity networks and only allows the privatisation of their utility. Hence, prospects for further opening of national gas markets and the introduction of competition in these markets are quite promising when looking at the reforms and business dynamics thus far. This expectation is much more difficult to maintain when looking at the process of establishing an internal competitive market in Europe; a wholesale market at the European level connecting the conglomerate of national gas markets. The process of establishing this internal market is only at its beginning and is facing serious political and institutional barriers, apart from other minor technical and contractual problems. From a technical point of view establishing the internal wholesale gas market is no problem. The needed high-pressure pipeline infrastructure already exists (as described in the previous section which detailed new initiatives and investments in this respect). New pipelines and new connections between them are currently under construction in attractive European gas trade locations. The contractual barriers refer to the current occupation of the European pipeline system by gas volumes contracted under long-term contracts. The volumes under these contracts are still significant and therefore could restrict competition in the European wholesale market. Longterm contracts could of course be renegotiated in a competitive wholesale market of course. Whether or not this will happen will be

National Prospects in the Dawn of the Internal Gas Market

365

decided by the question whether Europe manages to develop a real competitive wholesale market on the continent. As noted previously, the success of this operation will be decided by the settlement of the political and institutional barriers involved. The short-term prospects to relieve these political and institutional barriers are not that promising because their settlement touches the most sensitive issue in the EU: national autonomy and national identity. Establishing a competitive wholesale market in Europe requires much more integration of the operation and management of the high-pressure pipeline systems in Europe and these systems all still are nationally focussed and managed. At the end of 2001 the management and operation of these systems was still quite different as were the access conditions and access tariffs. A European wholesale market would require much more institutional and organisational integration and managerial coordination between these systems, which are currently still only technically connected systems. Only under these conditions the pipeline system would allow for real gas-to-gas competition at the European level based on European-wide harmonised competitive-based access conditions and tariffs reflecting capacity supply and demand. It is obvious that an integrated European-wide pipeline system, reflecting European demand and supply conditions is an appealing prospect, but at the same time an unrealistic expectation in today's Europe. Despite efforts to push the regulatory harmonisation of the European gas markets, the trajectory will be long and difficult and full of pitfalls and barriers. It is trajectory that can only proceed by taking small steps forward, because of the national sentiment and interests involved. Much will depend on the positions of national governments in this regard and the willingness of national pipeline operators to develop a more competitive and European orientation in system operation and system management. To conclude, the next step in the process to establish a competitive internal gas market in Europe will be decided at a national level, by national governments, national regulators and national system operators. The willingness of these actors will determine the shortterm potential of moving towards openness and competition in the European (wholesale) gas market. This brings us back to the core issue of the book, the national positions in the European gas market. National gas markets in Europe are indeed changing and this book showed that some of them are indeed transforming into a 'fundamentally different type of market organisation' as noted by Jonathan Stern in the opening quote for this book. The next national

366

National Reforms in European Gas

c h a l l e n g e will be to a g g r e g a t e the n e w m a r k e t o r d e r to the E u r o p e a n gas scene.

Literature DRI-WEFA (2001) Report for the European Commission Directorate General for Transport and Energy to determine changes after opening of the gas market in August 2000, Vol. 1 and 2, Brussels. International Energy Agency (IEA) (2002) Energy Balances of Non OECD Countries 1999-2000. 2002 Edition. Ministry for Economic Affairs (1995) Third White Paper on Energy Policy. The Hague. Oostvoorn, F. and Boots, M.G. (1999) Impact of market liberalisation on the EU gas industry. ECN-RX-99-023.

Index A Yamal II pipeline 312 Abuse of monopoly supply 52 Access position 6 Access regime 6 Act Reorganising Energy Business Law 223, 239 Adaptability 57, 58, 60 Adaptive expectation 59 Aerial photography 15 AGAS 270 Agip 100, 288, 321 Agip Service 276 Agip Servizi 277 Aker and Kvaerner 91 Aker and Kvaerner groups 90 Aker Maritime 92 Aktiengesellschaft fiir Kohlenverwertung 214, 229 Algeria 27, 61, 66, 80, 84, 92, 173, 247, 248, 252, 253, 255, 309, 317, 318, 321-323 Algerian gas 8, 84, 269, 283, 284, 294, 318-320, 323, 352 Algerian gas fields 8 Algerian gas industry 323 Algerian LNG 255, 319 Algerian LNG production 319 Alliance Gas 85 Allocative efficiency 48, 57, 348 Aluminium industry 49 Ancillary services 39 Aquifers 19-20, 247 Aquitaine 247 Arco 170, 322 Argentina 277 Arzew 319

A~sgard field - Krst (N) 102 Asgard Transport 102 Asia 277 Asian countries 158 Asian installations 319 Asian LNG 319, 324 Asian market 157 Austria 20, 83, 277, 312 Avacon AG 228, 229, 238 Bacton 28, 116, 172, 174, 175 Balladur 271 Balladur government 272 Baltic countries 155 Baltic economies 147 Baltic states 141 Bank of Finland 147, 150 Barcelona 270 Barents Sea 68 Base-load supply 19 Basel 27 BASF AG 216, 227, 228, 234 Bavaria 28 Bayerngas GmbH 228, 229, 231, 233 Bayernwerk AG 226 BEB 86 BEB Erdl-Erdgas GmbH 236 BEB Erdgas und ErdlGmbH 216, 217, 228, 229, 231, 236, 237, 238 Belarus 157 Belarus-Poland line 157 Belgian initiative 59 Belgium 21, 28, 45, 84, 86, 317, 322 Bergemann GmbH 231, 232 Bergen 88 367

368

Index

BG Group 196-198, 200, 206 Bilateral long-term contracts 50 Bilateral transactions 263 Bilbao 270 Biomass 28-29 Black Sea 157 Blending stations 21 Blending 21, 24, 29 Blue Stream Pipeline 157 Board Gais Eireann 85 Bordeaux 251, 270 Boulton 276 BP 217, 227, 228, 232 Brent 173 Britain 10, 49, 51, 61, 89, 260 British BP 321 British companies 90 British export position 46 British gas 82, 46, 86, 163, 164, 168, 171-197 British Gas Corporation (BGC) 171 British gas market 10, 55, 59, 61, 270 British interconnector 59 British market 10, 163 British National Oil Corporation (BNOC) 167, 171 British North Sea 276 British sector 84 British Telecom 178 Brussels 21 Bulgaria 309, 314, 322, 323 Bundesverband der deutschen Gas- und Wasserfach e.V. (FIGAWA) 222 Caister 276 Calorific value 21 Canada 277 Capacity 56 Capacity costs 25 Capacity of the pipelines 18 Carbon 14 Cartel 50 Caspian gas 317 Caspian Sea 309, 314-315, 322 Catalunya 270

CB&H process 29 CCGT plants 228 Central coordination 59 Central Electricity Generating Board 177 Centralisation of France's energy industry 273 Centralised coordination 50, 59 Centrica 117, 182, 196, 197, 200, 203, 266, 267, 270 CEPSA 270 CFDT 273 CFM (GDF 55, TotalFinaElf 45) 250, 251, 263, 266-267, 273 Change process 6 Characteristics of national gas markets 47 Cheaper Asian LNG 318 Chemical industry 49 Chemical products 4 Chicago 27 Chicago Hub 27 Chinese Wall 260 CHP 28, 33, 123, 222, 225 CHP plants 88, 222, 225, 241 CHP unit 28 CIS 141, 143, 147, 155-156 CIS countries 139, 155-156, 158 CIS markets 155 City gas 4, 46, 53 Claire Spottiswoode 188, 190 Climate change 28-29, 222 Climate change policies 53 Climate policy 239 CMEA 139 CMEA countries 139 CMEA trade 139 CO 29 CO2 13, 16, 18, 28-29, 73-74 CO2 eossopms 222 CO2 tax 73 Coal gas 4, 13, 15, 164, 310, 320 Cofatech 276 Co-generation 257, 263, 267 Combined heat and power generation (CHP) 24

Index Commission de R6gulation de l'Energie 264 Commission Guillet 254 Commodity 10, 46-47, 54-57, 59, 61 Commodity model 9, 54, 57-58, 329 Commodity Service System (CSS) 25, 119 Commodity-oriented gas market model 58 Commonwealth of Independent States (CIS) 139 Compagnie Fran~aise du M6thane (CFM) 250, 251 Company SPP 314 Competition 9, 36, 50, 55, 58, 108, 133, 258, 264 Competition-based gas market 55 Competition-based market 55 Competition-based supply 57 Competition effects 266 Competition in European gas supply 50 Competition in the gas market 55 Competition in the gas sector 143 Competition-oriented routines 60 Competition rules 55 Competitive advantage 55 Competitive gas market 47 Composition of natural gas 14 Compressor stations 22 Concession policy 68 Concession regime 68 Concessionary system 68 Condeep platform 90 Conditions of competition 57 Conoco 150 Consorsio Mexigas 277 Consumer market 52 Consumer prices 57 Consumer protection 5 Consumer routines 60 Consumption 45, 135 Contestable market 52 Contigas G 227 Continental downstream markets 98

369

Continental Europe 5, 28, 46, 86, 96, 318 Continental Shelf 16, 20, 27, 51, 100 Contracted swings 20 Contractual regulation 254 Control and enforcement of the competition rules regulation 55 Coordination model 50 Cost structure 26 Cost-components of natural gas 24 Cost-plus principle 144 Cost-plus regime 97 Cost-reflectiveness 56, 264 Costs of pipeline infrastructure 16 Costs of transport 28 Council for Mutual Economic Assistance 139 CRE 264 Cross-border trade 43 Crude oil 25 Crude oil price 74 Cubic metre of natural gas 24 Cushion gas 20 Czech Republic 10, 80, 233, 234, 309-314, 324 Daily balancing 25 Dalkia 268, 276 Dangas 85 Danish Maersk oil 321 DEGAZ 277 Demand and supply 55 Demand market 53 Demand-side factors 144 Deminex GmbH 217 Denmark 80, 85, 217 Depleted gas fields 20 Depletion policies 49 Deregulated market regime 67 Deregulation 9, 26, 65-66, 92, 97-98, 140 Deutsche BP AG 232 Deutsche Shell AG 217, 237 Deutz Erdgas GmbH 216 Directive 39, 261, 263

370 Directive 98/30 249, 269 Directive 98/30/CE 260 Directive 98/30/EC 219, 223 Director General of Gas Supplies (DGGS) 182, 183 Discovery 49 Discretionary powers 9 Distance-related tariff system 25 Distance-related transportation tariff 25 Distribution 13, 20, 22, 25, 54, 135, 251, 255, 256, 267 Distribution companies 34, 46 Distribution cost 258 Distribution networks 22, 23, 255, 263, 265, 270 Distribution system 22 Distributors 263 Distrigas 86, 117, 266, 267, 272 Distrigaz 82, 83 Domestic coal reserves 310 Domestic consumption 45, 52, 314 Domestic energy consumption 320 Domestic gas market 49, 88 Domestic gas production 216 Domestic market 49 Domestic oil consumption 136 Domestic suppliers 136 Dominant regulatory model 52 DONG 117 Downstream 56, 267 Downstream activities 51 Downstream competition 97 Downstream deregulation 97 Downstream distributors 50 Downstream gas pipeline infrastructure 56 Downstream gas system 54 Downstream market 50 Downstream sector 31 Draugen field 68 Draupner E - Emden 101 Dry natural gas 14 Dunkerque 101 Dunkirk 27 Duopoly 279

Index Dutch case 13 Dutch gas 14, 21, 49 Dutch distribution system 20 Dutch gas consumption 20 Dutch national pipeline system Dutch natural gas 18 Dutch offshore 276 Dynamic efficiency 56-57 Dynamics 60

22

E.ON 217, 225, 226, 232, 273, 346 E.ON AG 217, 225-228, 231-233, 238, 241 E.ON Energie AG 226, 233, 238 Eastern Europe 8, 10 East European countries 50 East-Central Europe 309 Eastern European countries 133, 141, 144 Eastern European gas markets 61 Eastern Siberia 158 EC 269 ECO gas 28, 29 Economic Agreement 96 Economic culture 245 Economic efficiency 246 Economic factors 7, 9, 246, 309 Economic functions in the gas infrastructure 58 Economic significance of gas technology 9 Economic transition 133 Economically Recoverable Reserves (ERR) 15 Economies of scale and scope 52 EDF 251,254, 259, 261,262, 267, 268, 272, 273, 275, 278 EDF/GDF merger 271, 273 Edison 267 EEA 95-96 EEG - Erdl Erdgas GmbH 216, 217, 238 EFTA 330 Egalitarian principle 254 EGAZ 277 EIA 155

Index

Ekofisk 82, 255 Ekofisk committee 77 Ekofisk field 86, 90, 100, 101 Ekofisk gas 77 Ekofisk reservoirs 77 Electricit6 de France (EDF) 249 Electricity 97 Electricity Directive 6, 33, 40, 43-44 Electricity industry 249 Electricity prices 88 Electricity production 53, 284, 320 Electricity sector reform in Norway 65 Electricity sector 92 Electricity supply companies 215 Electricity supply 273 Electricity system 60 ELF 82, 276 Elf Aquitaine 249-250, 259, 267, 270 Elf-Aquitaine Gaz 273 Elf Gas & Power 270 Elf Petroleum 102 Elf Petroleum Norway 100, 101 Elgin 276 Eligibility 33, 263, 267 Eligibility threshold 267 Eligible clients 268 Eligible customers 31-33, 36, 57, 97, 260 Eligible segment 260 Elyio 268 EMB 277 Emden 28, 77, 82, 86, 100 Emergent market 36, 37 Emerging competition 47, 59 Enagas 83, 86 EnBW AG 228 End-consumer 23, 25 ENEL 269, 289, 291, 292 Energy consumers 60 Energy Council 33 Energy demand 312 Energy deregulation initiatives 65 Energy exports 135 Energy industry 136-137

371

Energy markets 262 Energy policies 53, 252 Energy provision of Europe 316 Energy reserves 148 Energy sector 133 Energy services 276 Energy strategy 135, 140, 144 Energy taxation 125 England 77 ENI 150, 157, 287 ENI-SNAM 267 Entry barriers 56 Entry-exit approach 264 Environment 53 Environmental policy 239 Environmental pollution 322 Erdgas Mfinster GmbH 229 Erdgasversorgungsgesellschaft Thiiringen-Sachsen mbH (EVG) 229, 231 Erdl-Raffinerie Deurag-Nerag GmbH 238 ERR 15-16 ESSO 217 ESSO Deutschland GmbH 217, 228, 232, 237 Esso Norway 101 Esso Norway a.s 102 ESTAG 277 EU 4, 9, 58, 60, 67, 80, 92, 95-98, 155, 157, 309-310, 312, 314, 323 EU area 82 EU countries 46, 80 EU deregulation 66 EU directive 3, 9, 96, 98, 322 EU end-user markets 98 EU gas and electricity directives 312 EU gas directive 3, 7, 9, 31, 46, 55, 57, 60, 92, 313 EU gas imports 317 EU gas market 60, 309 EU gas market liberalisation 45 EU gas market reform 4 EU harmonisation 8 EU harmonisation process 59 EU legacy 3-4, 6, 8

372

Index

EU liberalisation 7 EU regimes 97 EU regulation 7, 96 Europe 3, 7-8, 21-22, 24, 25-28, 45, 49-53, 55, 57-61, 66, 83-84, 95, 98, 148, 155, 158, 246, 249-250, 258, 261, 262, 309, 314, 322 European-Continental buyer oligopoly 98 European Commission (EC) 269, 219, 260, 269, 270, 273 European companies 248 European competition law 67 European continent 51, 84, 98, 318, 322 European Council 270 European countries 4, 45-46, 52, 59, 246, 260, 261, 269, 278 European Court 96, 260 European dependency 96 European deregulation 67 European Directive 247, 260 European Economic Area (EEA) 8, 36, 66, 96 European Economic Area Agreement 95 European Economic Cooperation 66 European economic integration 279 European Energy Charter 8 European energy markets 66 European gas 3, 7 European gas chain 6 European gas companies 84, 272 European Gas Directive 245,260, 288 European gas exchange system 278 European gas fields to 54 European gas market 3, 8, 7, 10, 45, 46, 54, 57, 59, 86, 97, 92, 246, 317, 322 European gas network 27 European gas suppliers 10, 79 European gas supply 14 European gas system 5 European gas trade 28 European hub 28 European import price 253

European integration process 246 European internal market integration 269 European load centres 51, 60 European market 50, 80, 96, 309, 314, 315, 317 European market integration 246 European market via LNG 322 European offshore area 16 European order 5 European Parliament 223 European pipeline system 9 European purchasers 255 European regulation 66 European rules 246, 269 European transmission pipelines 51 European Union 5, 18, 65, 80, 155, 156, 259, 268, 269, 279, 314, 317, 322, 323 European Union in 2004 312 European Union regulations 246 Europipe 101 Europipe II 102 Evolution of gas markets in Europe 60 Evolutionary patterns 7 EWE AG 216, 229, 233 Exploitation 4, 5, 49 Exploitation of gas fields 5, 16 Exploration 15 Export 45 Export regulations 135 Export restriction 147 Exporting countries 66 Exxon 78, 121 ExxonMobil 227

Federal Association of German Industry (BDI) 223 Federal Cartel Office 225,232 Federal Energy Commission 145 Federal Energy Regulating Committee (FERC) 26 Federal Minister of Economy 223, 232

Index Federal Ministry of Economics and Technology (BMWi) 219, 242 Feeder Stations 23 Ferngas Nordbayern GmbH 231 Fertilisers 4 Fields 46 Fina 100 Final equilibrium 60 Finland 157 Fixed cost problem 59 Fixed prices 144 Flexibility to competition 58 For salt caverns 20 Fortum 150 Fos 270 Fos terminal 271 France 10, 27, 28, 52, 53, 60, 61, 86, 245-247, 249-251, 256, 258, 260, 261, 270, 271, 273, 274, 276, 278, 279, 317, 318, 321, 322 France-T616com 259 Frankfurt 28 Franklin 276 Fred Olsen 90 Free consumer choice 57 French companies 251 French consumers 255 French energy companies 271 French energy policy 259 French energy sector 272 French exports 252 French gas 18 French gas company 255 French gas industry 245, 246, 249, 250, 258, 247, 252, 259, 260, 272, 279 French gas market 263, 264, 269, 270 French gas supplies 248 French gas system 270, 278 French government 263, 270 French identity 261 French law 247 French liberalisation policy 28 French LNG technology 252 French market 247, 262

373

French natural gas industry 247 French oil companies 249, 250, 261, 268, 272, 278 French production 249 French public authorities 259, 262 French public enterprises 259 French public gas company 246 French public organisation 255 French public service model 245 French single-energy company 247 Frigg 82, 171-174, 206 Frigg field 82, 90, 101, 172 Frigg gas 82 Frigg gas field 341 Frigg pipelines 77 Frigg Transport 101 Fuel balance 165 Fuel oil 19 Functionality 9, 47 GALP Energia Group 301 Gas 273, 320 Gas Act 250, 314 Gas chain 23-24, 50 Gas companies 53 Gas consumers 23 Gas consuming countries 4 Gas consumption 5, 18, 45, 52, 125, 310, 314 Gas Council 164, 168, 170-172 Gas De France 86 Gas demand 19, 52 Gas directive 3, 6, 7, 9, 32-33, 38, 43, 44, 95, 98, 246, 260, 262, 263, 265, 269 Gas distribution 52, 53 Gas distribution companies 53 Gas distribution networks 253 Gas drew 4 Gas export 45 Gas exporting 46 Gas exports 154 Gas fields 3-5, 8, 9, 15, 16, 19, 49, 56, 320 Gas fields in Europe 53 Gas grid 52-53, 95

374 Gas Gas Gas Gas Gas Gas Gas Gas

Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas Gas

Index grid regime 97 hubs 56, 60, 130 imports 252, 260, 266, 310 industries in Europe 53 industry 3, 5, 7, 11, 49, 57, 58, 135, 136, 139, 141, 254, 320 Initial In Place (GIIP) 15 Law 249 market 3, 5, 7, 14, 23, 24, 26, 28, 29, 45, 47, 57, 60, 61, 143, 314 market change in Europe 61 market coordination 59 market development 45, 46, 48 market in Europe 47 market reform 4, 45, 58, 60, 323 market technicalities 9 markets in East-central Europe 322 Natural 269, 270, 272 Natural-Enagas 270 Natural Group 295 Negotiations Committee (GNC) 66, 67, 80, 83, 85, 95, 96 network 45, 46, 51, 54, 60, 268, 310, 349, 352 pipelines 4, 77 pipeline infrastructure 16, 29, 47, 49, 54, 55 pipeline network 22, 55 pipeline system 19, 56 policy 47, 135 price reform 146 prices 16, 52, 144 processing 16 producers 23, 276 producing countries 4, 47, 48 production 45, 52, 134, 135 production system 95 quality 16 quality conversion costs 16 Receiving Stations (GRS) 23 reform 251, 260 Reform Act 260 reform in France 259 reserves 45, 46, 49, 50, 52, 164

Gas Gas Gas Gas Gas Gas Gas Gas Gas

revenues 107 sector 133, 313 sector deregulation 144 sector reform 144, 143 storage 18-20 storage capacity 27 supplier 46, 95 supplies 84 supply 19, 25, 46, 52, 60, 143, 259, 270 Gas supply business 261 Gas Supply Committee (GSC) 67, 85 Gas technology 9 Gas technology in a liberalized gas market 23-29 Gas terminal in Emden 83 Gas trade 77 Gas traders 20 Gas transmission 18 Gas transport 25, 26, 96, 256 Gas transport companies 24 Gas treatment costs 16 Gas turbines 22 Gas turbine industry 49 Gas value chain 246 Gas-driven city-buses 88 Gas-fired local CHP 88 Gas-to-gas competition 5, 10, 25, 43, 240 Gas-Union GmbH 228, 229, 231 Gasag Berliner Gaswerke AG 214, 231 GASAG 214, 277 GASEBA 277 GASENA 277 Gasification of biomass 29 GasMetropolitan 277 Gassco 67, 94-95 Gassco AS 94 Gasunie 20, 21, 23, 25, 26, 28, 34, 42, 46, 82, 104, 105-121, 127, 131, 272 Gasversorgung S~iddeutschland 228 Gaz de France (GDF) 217, 240, 249, 250, 251, 255, 259, 270, 347, 278 Gaz de Strasbourg 273

Index Gaz du Sud-Ouest (GSO) 250, 251 Gaz Naturel 269 Gazexport 143 Gazprom 117, 133, 134, 137, 140, 141, 142, 143, 145, 146, 150, 155-157, 159, 160, 227, 228, 230, 234, 235, 240 Gazprom-ADR 142 GDF 82, 83, 249-264, 266-269, 271-279 GDP 301 Gelsenberg 232 Geographic diversification 246 Geographical equalisation of tariffs 254 Geological research 15 Georgia 26 German Association of Gas and Water Engineers (DVGW) 221, 222 German market 312 German Mobil (MEEG) 83 German pipeline network 157 German Ruhrgas AG 142 German VNG 86 Germany 10, 21, 23, 27, 28, 46, 53, 59-61, 77, 82, 83, 86, 155, 157, 248, 256, 258, 260, 277, 312 GIIP 15 Glavgazprom 135 Global competition 322 GNC 80, 83-86, 95, 98 GNC/GSC systems 96 GNC/GSC, the Norwegian 94 Golden share 141 Governance 252 Government 67 Gravimetric research 15 Great Britain 60, 80 Greece 309, 314, 322 Green certificates 114 Green energy 28 Green house effect 29 Green tax 222 Greenhouse horticulture 49

375

Grenoble 251 Grid code 264 Grid-based gas supply system 80 Grid-bound gas supply 52 Groningen field 17, 46, 84, 98, 122 Groningen gas 14, 20-21, 107 Groningen gas field 14, 17, 46 GSC 85, 95 GSO 260, 263, 266, 267, 270, 273 GSO (TotalFinaElf 70, GDF 30) 250 Guiding principle 47 Gullfaks 83 Gullfaks 1 Group 82

H-gas 21 Haltenpipe 101 Harmonisation 5, 6, 8, 11, 9, 43, 45, 55 Harmonisation proposals 6 Harmonisation requirements 41 Harmonised European gas market 7 Hassi Messaoud oil field 317 Hassi R'Mel field 317, 318 Heat and power 33 Heat service 276 Heatsave 277 Heidrun Field 101 Heimdal 83 Heimdal Group 82 Helicopter Services Group (HSG) 89 Henry's Hub 27 Hewitt 170, 171 High calorific gas (H-gas) 14, 21 High connectivity 56 High-pressure pipeline system 51 High-pressure transmission networks in Europe 54 Holland 27, 260 Horizontal integration 262 Households 312 HTL 23 Hub 27, 270, 271 Hub operator 27 Hub-Holland 28 Humber Power Company 270

376 Hungary 10, 85, 277, 309, 310-314, 324, 353 Hydro 320 Hydrocarbons 15 Hydrocarbons Great Britain Limited 168 Hydrogene gas 29 Hydropower sector 65, 68 Ideal-type 47 IEA 143, 146, 149, 150, 153, 156, 157, 248, 258 IEA calculations 317 Illinois 26 IMF 143, 147, 321, 339 Imperial Continental Gas Association 213, 214 Imports 259 Import contract 256, 265 Imported gas 310 Imports of LNG 247 Increasing return 59, 60 Increasing returns to adoption 59 Indefatigable field 170, 171 Independent electricity producers 267 Independent regulator 313 Indexation clauses 256 Indexation on oil products 256 India 277 Individual contracting 67 Industrial consumption 320 Industrial organisation 9, 249 Industrial policy 271 Industrial strategy 271 Inertia 60 Innovation 55, 57, 59 Institutional background 4, 6 Institutional change 59 Institutional models 4, 5 Institutional organisation 4, 50, 53, 58, 59 Institutional path-dependency 246, 259, 278 Institutional stability 246 Integrated energy markets 246

Index Integrated gas companies 59 Interconnection 27, 312 Interconnector 27, 28, 45, 117, 173, 197, 202, 205-208, 270, 277 Interests 85 Internal EU gas market 5 Internal gas market 327, 361, 363 Internal gas market in Europe 59, 60 International gas trade 25 International Monetary Fund 321 International trade 40, 164 International trader 320 Internationalisation 255, 257, 276 Interruptible contracts 25, 176 Interstate pipelines 27 Interventionist economic culture 245 Investments 5 IPP 263 Iran 255, 317 Ireland 25, 85, 86 ITAG 216 Italian Agip 321 Italy 8, 10, 27, 86, 155, 248, 258, 260, 266, 272, 276, 277, 278, 312, 317, 318, 322 Itera 155 James McKinnon 179, 183, 188, 190, 191, 209 Jospin 271 Jupp6 271 Krst 83, 88 Krst (N) - Emden (D) 102 Kollsnes 88 Kollsnes- Sleipner, IIB: Kollsnes - 101 Kvaerner 92 Kvaerner Company 29 Kvaerner Group 90 Kyoto Agreement 29 LACAL 27 Lacq 247, 270

Index Lacq deposit 249 Lacq-field 18 Landfill gas 28 Large consumers 26 Large end-consumers 23 Large fixed set-up costs, learning effects, coordination effects 59 Large gas customers 23 Large gas fields 28 Lasmo 276, 321 Latin America 277 Lattice 197-200 Law of the Sea Conference 168 LDCs 23, 28, 28-29 Legal unbundling of the networks 263 Legal-institutional aspects 9 Legitimacy 246 Leman Bank 170-172 Liberalisation 3, 6, 9, 10, 24, 26, 28, 29, 32, 37, 45, 46, 55, 98, 134, 139, 148, 159, 226, 239 Liberalisation of the gas market 261 Liberalised energy markets 28 Liberalised gas markets 20, 23-27 Liberalised market 23-25 Liberalising gas markets 13 Libya 278, 318 Line-pack 28 Liquefied natural gas (LNG) 173, 284 Liquid Natural Gas (LNG) 19 LNG 23, 27, 80, 264, 270, 271, 277, 318, 319, 321, 324 LNG chains 262 LNG facilities 318 LNG imports 269 LNG peak shaving installations 23 LNG producer 318 LNG production 319 LNG shipment 318 LNG technology 324 LNG terminal 27, 270

377

LNG terminal in Zeebrugge 27 LNG transport terminals 318 Load centres 9 Loaning 27 Local distribution companies (LDCs) 23 Location of the gas field 15 Long distance transmission systems 5 Long-term contractors 97 Long-term contracts 4, 16, 46, 265, 266, 279 Long-term contractual arrangements 262 Long-term energy supply 49 Long-term import contracts 271 Long-term national welfare 49 Long-term security of supply 49, 310 Long-term take or pay contracts 66 Longer-term availability of natural gas 49 Longer-term competitive advantage 57 Longer-term prosperity 51 Low caloric Groningen gas 17 Low calorific gas (L-gas) 14 Lower prices 60 LPG 19, 25 LPG/air supply 28 Madrid Gas Regulatory Forum 44 Madrid harmonisation process 269 Maghreb-Europe Gas pipeline 296, 319 Mandil Report 260 Mannesmann AG 232 Margaret Thatcher 171, 174, 175, 178, 179, 207 Market economy 133 Market opening 32-33, 37, 112, 127 Market organisation 3 Market-based principles 246 Markets 133 Marseilles 27 McAdam 276

378

Index

MEDGAS project 319 Member states 4, 58 Methanation 29 Methanol 88 Mexico 277 Mezhregiongaz 143 Middle East 74, 309, 314, 324, 315 Middle East countries 314 Middle-East and Caspian Sea gas 315 Middle-East countries (Iran, Qatar, Saudi Arabia and United Arab Emirates) 315 Minimal Liberalisation Reform 260 Minimum threshold system 36 Ministerial supervision 245 Ministers 270 Ministry of Oil and Energy 96 Ministry of Oil and Gas Industry 137 Ministry of Petroleum and Energy (MPE) 85, 95 Mitteldeutsche Gasversorgung GmbH (MITGAS) 233 Mobil 78, 321 Mobil Norway 101, 102 Mobil Norway A/S 102 Mobil-Erdgas-ErdlGmbH 216, 217, 227, 229 MOL 85 Moldavia 309, 314 Mono-energy company 278 Mono-energy scheme 274 Monopolies and Mergers Commission (MMC) 182-188, 190, 193, 199, 208, 209 Monopolistic supply of natural gas 50 Monopoly 159, 279 Monopoly distribution 54 Monopoly regulation 5, 52, 258 Morecambe Bay 168, 170, 173, 174, 197, 200 Morocco 135, 318 Moscow stock exchange 142 MPE 85

Multi-energy supply 274 Multi-utility companies 7 Multiple equilibria 60 Municipal distributions 267 Murdoch 276

NAM 120 National asset 4, 45 National champion 7, 273 National developments 8, 9 National dynamics 7 National electricity supply 53 National energy balances 310 National energy infrastructure 49 National energy markets 312 National energy policies 49 National focus 4 National gas 59 National gas consumption 310 National gas industries 6, 7 National gas industry 60 National gas infrastructures 4 National gas market development 61 National gas markets 4, 9, 52, 58-61, 314 in Europe 6, 56 National gas policies 46, 58 National gas reserves 310 National heritage 59 National institutional models 5 National institutional structure National interest positions 5 National interests 4, 6, 26 National models 45 National or regional supply monopolies 5 National Petroleum Directorate 87 National pipeline systems 56, 59 National positions 4, 6 National Power 83 National reserves 320 National treasury 50 National welfare 51 National Gas Company 271

Index

Natural gas 13-15, 17, 20, 27, 29, 49, 53, 58, 97, 320, 321 Natural gas consumption 312 Natural gas exports 154 Natural gas production 134, 150 Natural monopoly 4, 55 Naturkraft AS 83 NCS 68, 80, 85 Negotiated access 38 Negotiated TPA 269 Neste Petroleum A/S 101, 102 Netherlands 4, 8, 10, 21, 23, 25, 27-29, 45-46, 49-53, 60-61, 80, 84, 86, 217, 247, 248, 253, 256, 310 Network company (Gasunie) 26 Network industry 268 New entrants 60 New gas fields 60 New interconnections 27 New York 27 New York Stock exchange 93 Nigeria 255, 269, 317 Nigerian LNG 269 Nodal pricing 264 Non-discriminatory access 264 Non-eligible clients 265 Nordic countries 79 NorFra pipeline 27 Norpipe 77, 100 Norpipe pipeline 82 Norsk Hydro 66, 70, 75, 77, 83, 85, 86, 93, 100-102, 150 Norsk Hydro a.s 102 North Sea 16, 77, 79, 89, 94-98 North Sea deposits 273 North Sea gas grid 94 North Sea gas pipeline grid 75 North Sea gas producers 267 North Sea offshore production 273 North Sea reserves 318 North Sea suppliers 66 North-sea gas 14 Northeast-Central Europe 309, 310, 312, 322

379

Northeast-Central European countries 323 Northern Basin 163, 172, 174, 175 Northern Basin fields 170 Northern Europe 270 Northern Ireland 190, 195 Northern region 8 Northwest Europe 7, 8 Norway 4, 7, 8, 10, 27-29, 45, 46, 49, 51, 53, 60, 61, 65-68, 75, 77-80, 82, 83, 86, 88-90, 92, 95, 96, 98, 100, 102, 217, 247, 248, 252, 255, 276, 310 Norway's electricity sector 65 Norwegian Agip 102 Norwegian authorities 77, 89, 91 Norwegian bargaining position 66 Norwegian companies 66, 68, 70, 89, 91, 98 Norwegian Conoco 101, 102 Norwegian Conoco Mobil 102 Norwegian constructors 90 Norwegian consultants 91 Norwegian consulting companies 91 Norwegian Continental Shelf (NCS) 68, 81, 82, 85, 89, 94-96, 98, 100 Norwegian contractors 89, 90 Norwegian drilling and production competence 77 Norwegian economy 68, 76 Norwegian energy policy 88 Norwegian engineering 91 Norwegian gas 80, 84, 86, 96, 269 Norwegian gas exports 86 Norwegian gas market regime 67 Norwegian gas model 92 Norwegian gas production 98 Norwegian gas regime 92, 95, 98 Norwegian gas resources 77 Norwegian gas sales 80 Norwegian gas sales model 79 Norwegian gas sector 86

380

Index

Norwegian Government 65, 68, 73, 76, 93-96, 275 Norwegian industry 89 Norwegian interests 70, 92, 100 Norwegian Ministry of Oil and Energy 82, 83 Norwegian model 65-67, 92, 96 Norwegian national control over petroleum resources 70 Norwegian national interests 76 Norwegian negotiators 82, 84 Norwegian offshore production 98 Norwegian offshore 91 Norwegian oil and gas deregulation 66 Norwegian oil and gas model 75, 85 Norwegian oil and gas policy 65 Norwegian oil and gas regime 65, 67 Norwegian oil policy 75 Norwegian Petroleum Consultants 90, 91 Norwegian Petroleum Directorate (NPD) 68 Norwegian petroleum tax system 74 Norwegian petroleum 89 Norwegian pipelines 98 Norwegian policy revisions 95 Norwegian position 82, 92 Norwegian producers 85, 98 Norwegian protectionism 98 Norwegian R&D 89 Norwegian regime 96, 97 Norwegian sector 84, 100 Norwegian seller 85, 98 Norwegian Shelf 71, 77, 83, 98, 99, 101, 102 Norwegian ship owners 89 Norwegian shipyard 49 Norwegian side 80 Norwegian state companies 66 Norwegian State 73, 85, 94

Norwegian state-owned companies 67 Norwegian States Direct Financial Interests (SDFI) 93 Norwegian strategy 77 Norwegian sub-contractors 91 Norwegian supply-contract philosophy 98 Norwegian tax reform 71 Norwegian Trench 77, 83 NPC 91 Nuclear energy 53 Nuclear industry 53 Nuclear-free energy supply structure 219 Occidential, BP/Amoco, Samsung 321 Oder 28 Odorisation 24 OECD 82, 138, 144, 146, 148, 258 Office of Fair Trading (OFF) 184, 186, 187, 190, 193, 208 Office of Gas and Electricity Markets (Ofgem) 199 Office of Gas Supply (Ofgas) 182, 183, 185-188, 190, 192, 193, 195, 198-200, 204, 208 Offshore equipment industry 49 Offshore gas fields 16 Offshore gas production sites 18 Offshore production 15, 16, 18, 51 Offshore Supplies Office (OSO): 167, 179 Oil 13-14, 17 Oil and Gas Enterprise Act: 168, 175, 178, 182 Oil and gas export routes 158 Oil companies 272 Oil exploration 66 Oil prices 144 Oligopoly 66 Onshore or offshore production 16 Onshore production 15, 16, 71 OPEC 71 OPEC cartel 74

Index Open market 10 Operation 23 Organisational 58 Oslo 82, 93 Oslo Stock Exchange Ownership 53

92

P6chiney 266 Paris 27, 258 Parity principle 105 Path of development 59 Peak demands 19 Peak shaving 19, 20, 23, 25, 28 Perestroika 136, 160 Petoro 92-94, 98 Petoro AS 93 Petro-Canada 217 Petroleum 154, 320 Petroleum concessions 68 Petroleum industry 65 Petroleum tax reform 71 Petronas 276 Petronet 277 Phillips 82 Phillips Group 82 Phillips Petroleum 82, 100 Pipeline capacity 19, 322 Pipeline connections 309, 312 Pipeline gas 322 Pipeline infrastructure 5, 310 Pipeline network 55, 57 Pipeline system 23, 25, 58 Pipeline technologies 13 Pipeline transport 317 Pipeline transportation 141 Pipelines 3, 9, 80, 88, 270, 276, 320 Planned economy 133, 135 POGC 85 Poland 10, 85, 157, 309-310, 312, 314, 322 Policarbo, Castagnetti, Zanzi 277 Policy focus 48 Policy-driven environment 57 Political risks 309 Political science 9

381

Political-institutional organisation 53 Political-economic organisation 57 Politico-institutional view of gas market reform 9 Portgas 277 Portugal 8, 10, 277, 317 Position in the European gas chain 6 Postage stamp system 40 Power generation 4, 49 Power generation systems 3 Power producers 23 Power production 123 Pozagaz 277 Preussag Energie GmbH 216, 217, 232 PreussenElktra AG 226 Price and export regulation 144 Price-cap 255 Price regulation 145 Price transparency 24 Primary energy source 310 Primary gas consumption 150 Principal focus in gas policies 57 Principle of equality for the supply of essential goods or services 245 Principle of speciality 275 Private industry 49 Private ownership 133 Privatisation 65, 67, 93, 113, 134, 139, 141, 142, 180, 181, 246, 274, 322 Privatisation and deregulation of the gas industry 141 Privatisation programme 321 Production 13, 50 Production costs 15 Property 46, 57 Pseudo-Groningen gas quality 20 Pseudo-Groningen standard 21 Public authorities 262 Public companies 245, 252 Public devices for distribution 49 Public gas enterprise 274

382

Index

Public monopoly 254 Public organisation 258 Public ownership 258 Public policy 258 Public policy objectives 258 Public property 10, 46, 47, 49-52, 54, 58, 61, 163 Public property model 9, 329 Public service 245, 253, 262, 265 Public service model 245-247, 272, 273, 278-279 Public service standard 253 Public services obligations 7, 41, 52, 54, 246, 265 Public utility 10, 46, 51, 52, 54, 58, 61, 271 Public utility model 9, 331, 349, 354, 355 Public-private partnership 50 Publicly owned gas companies 53 PV 28 Qatar 316, 318, 324 Quality conversion 16 Quasi-monopoly 253 Quasi-regulated 263 RAG Beteilligungs GmbH (RAg AG) 232 Ranger Oil 276 Real costs of transport 24 Reciprocity 33 Reference models 47 Reform of the national gas industries 260, 322 Regional transport networks 23 Regulated gas markets 25 Regulated monopoly market 23, 50 Regulated prices mirroring 50 Regulated tariffs 265 Regulated TPA 26, 263, 269 Regulating authority 26 Regulation 5, 23, 26, 50, 55, 182, 252, 264

Regulation of the gas industry 135 Regulation of the pipeline system 23 Regulator 264 Regulator of the competition 55 Regulatory authorities 75 Regulatory body 264 Regulatory changes 60 Regulatory framework 67 Regulatory organisation 47 Regulatory reform 323 Regulatory requirements 60 Reliability 54 Removal of CO2 and sulphur 18 Removal of hydrocarbons and water 17 Renewable based technologies 28 Renewable energies 219 Renewable sources 29 Reserve policy 103, 106, 114, 121 Reserve position 109 Reserves 50 Residential customers 310 Resource exploitation 48 Retailers 23 Return on investment 16 Rhenag AG 233 Rhodia 266 Romania 157, 309, 314, 322, 323 Rotterdam 23 Rough field 168, 198, 200 Routines 59 RPI-X 182 Ruhrgas 34, 82, 83, 86, 256, 267, 272, 273, 276 Ruhrgas AG 214, 215, 225-233, 238, 239, 241, 242 Ruhrgas Energie BeteiligungsAktiengesellschaft (RGE) 230, 231 Ruhrgas Industries GmbH 231 Russia 7, 8, 10, 22, 27, 28, 50, 60, 61, 66, 80, 84, 92, 133-135, 139, 144, 148, 150, 154-159, 248, 252, 310, 315, 317

Index Russian and Baltic economies 150 Russian (energy) policy 133, 134 Russian economic transition 134 Russian economy 134, 146, 148, 153, 155, 159 Russian energy policy 150 Russian energy supply 157 Russian exports 155 Russian gas 46, 269, 309, 310, 312, 314, 315, 322, 324, 338-340, 353 Russian Federation 138, 140-142 Russian gas exports 155 Russian gas industry 133-135, 140, 159 Russian gas market 135, 148 Russian gas pipelines 310 Russian gas reserves 149 Russian gas sector 133, 134 Russian gas supplies 50, 322 Russian imports 139 Russian pipeline network 155 Russian Republic 137 Russian shareholders 142 Russian state 141 Russian--Chinese negotiations 158 Russian-European pipeline systems 312 Russian-Ukrainian transit dispute 157 RWE 128, 226-227, 346 RWE AG 226-228, 232-234, 241 RWE-DEA 216 RWE-DEA AG 216, 217, 232 RWE Gas AG 226-228, 232-234, 241 Saga 86, 275 Saar Ferngas Ag 228, 229, 231 Saga Petroleum 70, 83, 85, 100, 101 Saga Petroleum ASA 101, 102 Saga-Wingas 86 Saint-Gobain 266 Salt cavern 19 Saratov 135 SAUR-Bouygues 261 Schubert KG 231, 238

383

Scope 52 Scotland 82 Scottish Power 83 SDFI 73-74, 76, 93 Seasonal demand 19 Second World War 252 Sectors, Norwegian and British 89 Security 37 Security of supply 46, 54, 107, 108, 110, 120, 130, 292, 305 Seismic research 15 SEP 83, 86 Shareholders 53 Shell 121, 150, 217, 227, 228, 232, 237 Shippers 23 Shipping 89 Shipping and transport 89 Shipping industry 89 Short-time storage 24, 28 Single buyer 260 Single supplier 37 Sir Dennis Rooke 178, 179, 195 Skikda 318 Skogn 88 Sleipner field 84, 101 Sleipner Platform 84 Slovak gas market 314 Slovak Republic 10, 309, 310, 312, 323 Slovakia 157, 277, 310, 312, 314 Slovenia 317 Small field depletion policy 113 SNAM 83, 86, 256, 266, 269, 272, 288 SNAM long-term contract 278 SNAM's gas release programme 278 SNCF 262 SNPA 249, 259 Soci6t6 G6n6rale 278 Social efficiency 246, 259 Social industrial relations model 245 Socialist countries 139 Socio-economic performance 7 Sofregaz 277 Solvay 266 Sonar 15 Sonatrach 276, 318-320, 322

384

Index

Sonelgaz 320 South Europe 8, 61 South Korea 158 South-East Europe 157 Southeast-Central Europe 309, 310, 314, 322, 323 Southern Basin 173, 174 Southern Europe 317, 322 Soviet energy policy 139 Soviet Energy Program 136 Soviet energy trade 139 Soviet era 148 Soviet gas 256 Soviet legacy 135 Soviet planned economy 134, 135 Soviet Republics 139 Soviet Union 137, 139, 150, 155, 217, 247 Spain 8, 10, 25, 27, 86, 260, 270, 271, 272, 317, 318 Spanish Cepsa 318, 321 SPP 277 St Fergus 82, 172, 174, 175 St~idtische Gaswerke AG 214 Stadtwerke 227, 346 Stadtwerke Bremen swb AG 231, 233 State control of investments 275 State intervention 52 State monopoly 135 State owned enterprises 49 State regulation 67 State-owned monopoly 245 States Direct Financial Interest (SDFI) 73 Statfjord 82, 83, 171, 175 Statfjord B 90 Statfjord field 84, 101 Statfjord Group 82 Statfjord negotiations 84 Statkraft 67 Statoil 66, 70, 73, 75-80, 82-87, 91-94, 100, 101, 206, 228, 238, 240, 274, 275, 276 Statoil (SDFI 46.95) 102 Statoil (SDFI 60) 101, 102

Statoil (SDFI, 65) 101 Statoil AS 100 Statoil Group 79 Statoil policy 75 Statpipe 101 Stavanger 79 Storage 28, 39, 54, 56, 120, 230, 255 Storage access 269 Storage capacity 19, 20, 263, 264 Storage facilities 20, 23, 27 Strasbourg 251 Strategic energy partnership 157 Structure 7 Substitute natural gas 164 Suez 278 Suez-Lyonnaise 261 Suez-Tractebel 268, 274 Supplier competition 28 Suppliers 23, 25 Supply 37 Supply capacity 20 Supply natural gas 59 Supply network 29 Supply of natural gas 13 Supply pattern 26 Supply security 265 Supply station 23 Sustainable development 28 Swap contract 269 Swap-based transmission 56 Sweden 157 Switzerland 269 Synthetic Natural Gas 29 System operator 24, 113, 118 Take-or-pay (TOP) 32, 34 Take-or-pay (TOP) contracts 265 Take-or-pay obligations 222 Takeover 246 Tamanligas 277 Tariffs 56, 253 Tariff regime 97 Tariff system 25 Tarification methodologies 41 TCPL 277

Index

Technical background 4, 9, 58 Technical change 45 Technical infrastructure 13 Technical reliability of the system 56 Technical-physical view of gas market reform 9 Technigaz 277 Technology 7, 9 Technological change 59 Technological infrastructure 13 Technological system 51 Territorial diversity 254 Territorial equalisation 253 THGA AG 231 The Hague 260 Thermal-based European electricity systems 46 Thermal-based power generation 3, 4 Third Party Access (TPA) 38, 56, 57, 104, 111, 118, 120, 159, 219, 260 Three-dimensional seismic technology 15 THT 23 Thyssengas 86 Thyssengas GmbH 229, 233 ThyssenKrupp AG 232 Tjeldbergodden 88, 101 TOP 34-37 TOP clauses 262 TOP contracts 41, 43, 265 TOTAL 100, 101, 250, 273, 276, 321 Total Fina Elf 150, 275 TOTAL Norway A.S 102 Total opening 269 Total/Elf 271 Total, Elf-Aquitaine 272 TotalFinaElf 250, 266, 267, 268, 270, 274, 279 Town gas 299 TPA 40, 98, 111, 143, 223, 239, 241, 260, 262, 263, 264, 266, 268, 270 Trade 59 Trader 23, 25, 27 Trans-Mediterranean pipeline 318

385

TransCanada 276 Transco 195, 196, 198-200, 203 Transcontinental pipeline connections between 315 TRANSGAS 83 Transgas AS 233 Transit corridor 309, 312 Transition countries 133 Transit Directive 269 Transmission activities 55 Transmission of natural gas 13, 25, 50, 57 Transparency 263 Transport 20, 22, 25 Transport and distribution 20 Transport infrastructure 27 Transport networks 268 Transport system 136 Transportation 255 Troll 84, 262 Troll agreement 84 Troll field 70, 83-84, 98 Troll-Sleipner 255 Trondheim 88 TSO (transmission system operator) 43 Tunisia 318 Turkey 157, 309, 314, 318, 323 Turkmen exports 155 Turkmen gas 155 Turkmengazprom 139 Turkmenistan's natural gas production 155 Turkmenistan, Kazakhstan, Uzbekistan 315 UES 146 UK 27, 65, 85, 86, 97, 217, 248, 258, 270, 276, 277 see also United Kingdom UK-Continent Interconnector 273 UK Offshore Supplies Office (OSO) 167 Ukraine 155-157, 312 Ukrainian pipelines 155, 156 Ukrgazprom 139

386

Index

Umoe 92 Unbundling 31, 40, 104, 112, 274, 260, 279, 288 Unbundling of transmission and trade activities 57 Underground gas storage 19 Underground storage 23, 24, 27, 247, 255 Unified Electricity System (UES) 146 United Kingdom 6, 8, 10, 25, 28, 45, 61, 248, 277 see also UK United States 26 see also US, USA Upstream 38, 50, 51, 56, 97, 266 Upstream competition 97 Upstream integration strategy 272 Upstream integration 246, 276 Upstream networks 37 Upstream North Sea deregulation process 66 Upstream pipeline network 97 Upstream pipeline system 18 Upstream producers 97 Upstream regulation 97 Upstream system 51 Urengoy 149 Uruguay 277 US gas hubs 27 US 26-27, 78, 87 see also United States USA 317, 322 see also United States Usage of natural gas 13 USSR 135, 137, 256 Utility 57 Utility focus 53 Utility-focussed gas market 52 Utility model 53, 54 Utility-oriented gas market 52 Value chain 13 Value chain of natural gas 15, 59 Varley Assurances 168 Veba Oel AG 217, 232 Veba Oil & Gas GmbH 217 Verb~indevereinbarung 223, 345

Verb~indevereinbarung-Gas 219, 223 Verbundnetz Gas 83 Verbundnetz Gas AG (VNG) 238, 225, 228, 231, 232, 235, 238, 239 Vertical integration 249 Vertically integrated firm 320 Vertically integrated gas companies 5, 57 Vertically integrated supply 55 VEW AG 226, 233, 241 Viking 170, 171 Visund 275 Vivendi 261, 268 Vivendi Group 276 VNG 225 Vodafone 232 Volatility 74, 266 Von Rautenkrantz E&P 216 VV Gas II 224, 242 West European countries 133, 155 West European gas markets 134, 309 West European market 309, 312, 322 West Sole 170, 171 Western Europe 134, 157, 160, 310 Western Siberia 149 Westf~ilische Ferngas AG 226 Wheeling 27 Wholesale control 51 Wholesale competition 266 Wholesale traders 23 Wholesale trading 270 Wieringermeer 28 Willoch government 76 Wind 28 WINGAS gmbH 235, 236 Wingas 86, 235, 236 Wintershall 216, 217, 227, 321 Wintershall AG 234 Wirtschaftsverband Erdl- und Erdgasgewinnung e.V. (W.E.G.) 216, 222, 243

387

Index

Wobbe band 21 Wobbe index 21 World ban 153 X factor

182, 186, 188, 199, 209, 210

Yamal 136, 157, 262 Yamal peninsula 149 Yamal pipeline 157, 312 Yamal-Nenetz region 142

Yamburg

136, 149

Zarubeshgaz 228 Zeebrugge 27, 84, 130 Zeebrugge gas hub 116, 125 Zeebrugge terminal 23 Zeebrugge, IIA 101 Zeepipe 84, 101 Zeepipe I 27, 101 Zeepipe II 27

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