Financial Aspects in Energy: A European Perspective

Financial Aspects in Energy

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Andre´ Dorsman Wim Westerman ¨ zgu¨r Arslan Mehmet Baha Karan O l

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Editors

Financial Aspects in Energy A European Perspective

Editors Prof. Dr. Andre´ Dorsman VU University Amsterdam Finance De Boelelaan 1105 1081 HV Amsterdam Netherlands [email protected] Prof. Dr. Mehmet Baha Karan Hacettepe University Business Administration Beytepe Campus 06800 Ankara Turkey [email protected]

Dr. Wim Westerman University of Groningen Economics, Econometrics and Finance Nettelbosje 2 9747 AE Groningen Netherlands [email protected] ¨ zgu¨r Arslan Assoc. Prof. O Hacettepe University Business Administration Beytepe Campus 06800 Ankara Turkey [email protected]

ISBN 978-3-642-19708-6 e-ISBN 978-3-642-19709-3 DOI 10.1007/978-3-642-19709-3 Springer Heidelberg Dordrecht London New York Library of Congress Control Number: 2011930792 # Springer-Verlag Berlin Heidelberg 2011 This work is subject to copyright. All rights are reserved, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilm or in any other way, and storage in data banks. Duplication of this publication or parts thereof is permitted only under the provisions of the German Copyright Law of September 9, 1965, in its current version, and permission for use must always be obtained from Springer. Violations are liable to prosecution under the German Copyright Law. The use of general descriptive names, registered names, trademarks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. Cover design: eStudio Calamar S.L. Printed on acid-free paper Springer is part of Springer Science+Business Media (www.springer.com)

Preface

Over the 10 last years, the trading of infrastructure-bound gas and electricity has become a mainstream activity in Europe. Following the liberalization of these energy markets in the first years of the century, a whole plethora of activities has emerged for trading, as well as for portfolio and risk management. On the one hand, these activities replace (and improve upon) the dispatch mechanisms being employed in the old monopolistic structure for the daily physical generation and flows. So the trading activity has a strong component in the daily determination of physical generation, transport and delivery. On the other hand, these trading and portfolio/risk-management activities have expanded into the financial realm. Partly, these are new aspects to the world of energy and gas trading. Some of these new financial activities were not preceded by a visible equivalent in the old monopolistic world. One of the most striking examples is the trading of standardized futures contracts for delivery or cash-settled. Liquidity in such markets has grown over the years, on exchanges like power exchanges and gas exchanges, as well as on facilities trading “Over the counter” (OTC), thus in many ways resembling other traded markets like the markets in commodities or in stocks and bonds. In addition, the newly liberalized energy markets have created a whole new practice in almost every aspect of financial discipline. Price determination, for instance, is done differently. Asset valuation is done from a different perspective. Efficiency is achieved in totally different ways. Financing of investments, either for regular electricity generation, for infrastructure activities or for renewable generation is done under totally different circumstances. This book deals with many of these new practices and new realities, seen from the financial angle. The authors look into many financial aspects of the market structures, rules and practices that have grown over the last ten years. Those developments are still evolving as we speak, at the time of this introduction. So in a way, this book takes a snapshot of an ever-moving reality. At the same time, it is more than a snapshot. While the practices are still evolving, many of the underlying principles have already been set and will remain, at least to some extent,

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in the future. So the picture taken will give you, as the reader, not only knowledge that is applicable today, but also a solid basis from which you can extend your knowledge, learning from the ongoing changes in the nearby future. A recurring theme in many chapters is the dependency on the underlying market mechanisms for physical trade. As I have learned in my experience at APXENDEX, an energy exchange in both physical and financial products, a basic understanding of the physical arrangements and attached regulation is sometimes a prerequisite, but at least always very helpful for understanding the financial structures and consequences. Because of this, the world of energy markets may seem more complex initially than some other areas of expertise. Fortunately, this book gives you the backgrounds in order to unravel at least part of that complexity. Then, you will also find out that in the end, some of the outcomes are surprisingly familiar. You will also often acknowledge the importance of a European scope, at the same time leaving room for different local implementations. Then, after reading this book, one might ask: is the current situation, after the liberalization and introduction of markets, really a better one than before, in the monopoly situation? The answer is, now, undoubtedly Yes: it is better now 10 years after the start, but it took some years before we achieved that situation. This view may seem strange from someone like me, being the CEO of an energy exchange. However, many have forgotten that the old world of monopolistic delivery had its own way of achieving efficiency, sub-optimal though as it was. The breakdown of these old structures did destroy some of these old efficiencies upfront, and it has taken time and experience and improvement for the new market-based mechanisms to first match the old efficiency levels, and then improve upon that. We are now safely in that latter, more optimal situation, and still developing in the right direction. The European energy market is a mature market with electricity achieving an ever-better optimum in an ever-integrating market with a wider, more integrated European scope. This is due to a professional trade and financing structure around many financially oriented markets based on a sound underlying, internationally integrated, physical trade facilitated more and more by market coupling across the national borders in Europe. Recent experience shows that the gas market is following suit, catching up fast. This book will give you tour around this exciting field of expertise. I wish you energetic reading. May 2011

Bert den Ouden CEO-APX-ENDEX, the Dutch-British-Belgian energy exchange

Contents

1

Introduction: Financial Aspects in Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 ¨ zgu¨r Arslan, Andre´ Dorsman, and Mehmet Baha Karan Wim Westerman, O

Part I

Markets

2

The Development of Energy Markets in Europe . . . . . . . . . . . . . . . . . . . . . . . 11 Mehmet Baha Karan and Hasan Kazdag˘li

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Renewables in the Energy Market: A Financial-Technological Analysis Considering Risk and Policy Options . . . . . . . . . . . . . . . . . . . . . . . . . 33 Onno Kuik and Sabine Fuss

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The CO2 Trading Market in Europe: A Financial Perspective . . . . . . . 51 George Daskalakis, Gbenga Ibikunle, and Ivan Diaz-Rainey

Part II

Prices

5

Market Perfection in a Changing Energy Environment . . . . . . . . . . . . . . . 71 Andre´ Dorsman, Kees van Montfort, and Paul Pottuijt

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The Price Forming Process in Energy Markets . . . . . . . . . . . . . . . . . . . . . . . . 85 Don Bredin and Cal Muckley

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The Electricity Market, Day-Ahead Market and Futures Market . . . 109 Goknur Umutlu, Andre´ Dorsman, and Erdinc Telatar

Part III 8

Regulations

The Disintegration of the Concept of Sovereignty and the Energy Sector in the Europe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 131 Jennifer Westaway and John Simpson vii

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9 The EU Energy Policy After the Lisbon Treaty . . . . . . . . . . . . . . . . . . . . . . . 147 Johann-Christian Pielow and Britta Janina Lewendel 10 The Development of the European Electricity Market in a Juridical No Man’s Land . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 167 Simone Pront-van Bommel Part IV

Firms

11 Value Creation from Wood-Based Energy Sources . . . . . . . . . . . . . . . . . . . 197 Satu Pa¨ta¨ri and Wim Westerman 12 Tackling with Natural Monopoly in Electricity and Natural Gas Industries . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 213 ¨ zgu¨r Arslan and Hasan Kazdag˘li O

Chapter 1

Introduction: Financial Aspects in Energy ¨ zg€ Wim Westerman, O ur Arslan, Andre´ Dorsman, and Mehmet Baha Karan

Abstract European energy markets have been becoming increasingly integrated and competitive; take for instance the markets for renewable energy and emission allowances. Prices on spot markets and futures markets follow suit and a new pricing regime emerges. Also, whereas the supervision as to e.g. energy contracts remains in their hands, European states hand over much sovereign power to the European Union. While governmental controls in energy industries thus remain valid, firms have an opportunity to create economic value in this regulatory framework. In this vein, this book provides a timely guidance armed with chapters covering a wide spectrum of financial aspects of energy, particularly regarding the scope of a speedily changing environment. Keywords Energy firms
Energy markets
Energy prices
Energy regulations
Energy risks
Energy and value

Europe has engaged in a debate aimed at building an integrated and competitive energy market since the early 1990s. Leaving the previous nationally oriented energy frameworks models aside, the European Union (EU) has taken up the responsibility to develop a strategic policy to change current trends. A truly competitive, single European electricity and gas market is expected to be a free market and open to competition of Europe-wide operating companies. The latter may stem from Europe, but also from countries such as China and others.

W. Westerman (*) University of Groningen, Groningen, The Netherlands e-mail: [email protected] ¨ . Arslan O Hacettepe University, Ankara, Turkey A. Dorsman • M.B. Karan VU University Amsterdam, Amsterdam, The Netherlands A. Dorsman et al. (eds.), Financial Aspects in Energy, DOI 10.1007/978-3-642-19709-3_1, # Springer-Verlag Berlin Heidelberg 2011

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Several parties have responded to these changes by developing new products and markets. Specifically, the physical energy markets that they have been creating are different from traditional financial markets. Stock, bond and derivatives markets trade abstract goods. The “law of one price” holds here, but not for the commodity markets, such as energy. Furthermore, although (commodity) energy markets and financial energy markets are closely interrelated, differences in their characteristics and behaviour patterns are substantial. This entails price formation and complex exchange processes. Both risk managers and investment managers want to understand the above mentioned differences and how these differences impact both on investment decision-making and effective risk management approaches. Given that securing energy supply is still seen as being vital at a country level, the same may count for regulatory authorities. Furthermore, both academics and students will find it interesting to study these exciting advancements and consultants may resort to an update on academic debates and practical developments. Following the above motivation, Financial Aspects in Energy: The European Perspective deals with the interface of Europeanisation tendencies, energy issues and accompanying financial aspects that emerge. This book is organised around four themes: markets, prices, regulations and firms. Chapters 2–4 elaborate on the energy markets developments in Europe while in Chaps. 5–7 the emphasis is on price developments. The developments are so vast that regulations have to be adjusted. In this vein, the steps being taken are discussed in Chaps. 8–10. Chapters 11 and 12 (“firms”) show the impact of the markets, prices and regulatory developments at the specific energy firm level.

1.1

Energy Markets

In Chap. 2, Karan and Kazdag˘li sketch the developments in Europe. The EU has been building an integrated and competitive energy (“single”) market for about 20 years now. Still being far away from this aim, the markets have moved towards regional fragmentation. Karan and Kazdag˘li also find that the energy markets have become considerably efficient. The same counts for the corresponding financial markets. Despite physical, economic and political barriers, the number of financial market players is continuously increasing. Chapter 3, by Kuik and Fuss, introduces renewable energy technologies from the European perspective through discussing their advantages and disadvantages along risk profiles. The authors find that support policies at the EU level and in the member states are heterogeneous and add uncertainty to potential investors. German, Spanish and British experiences lead to some challenging insights (for example, solar energy investment stimulation). A review of these issues from a financial theory perspective helps to fuel current and future policymaking. In Chap. 4, Daskalakis et al. assess the trading of ‘CO2’ emission allowances. The EU Emissions Trading Scheme (EU ETS), a Europe-wide market for the

1 Introduction: Financial Aspects in Energy

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trading of emission allowances, has grown tremendously. In this vein the chapter evaluates the successful operation of the market during its trial phase, focusing on the functioning of exchange platforms and the financial regulations of the market. The pitfalls of the scheme provoke policy implications for the post-2012 period, making the financial markets behave in a less risky manner.

1.2

Energy Prices

Chapter 5 by Dorsman et al. deals with the imperfections of the electricity spot markets caused by the limited capacity of the interconnectors that are used for transporting electricity from one grid to another. The electricity networks used to be linked only with interconnectors with limited capacity. Such a limitation is an imperfection and may lead to an inefficient price-forming process. The capacity of the interconnectors has increased and the limitations of a free flow between the electricity networks have diminished. Yet, the authors show that the capacity is at times fully used and electricity prices of interconnected grids in turn may differ. In Chap. 6, Bredin and Muckley examine the price formation process in European energy markets in the years 2005–2009. The authors adopt factors including prices of both energy and EU allowance and also control for important influences such as economic growth. They use multivariate cointegration likelihood ratio tests to estimate potential theoretical relations. Their findings are indicative of a new pricing regime emerging since January 2008. The regime empirically interlinks the coal, gas and oil markets with EU allowance futures contracts. In Chap. 7, Umutlu et al. note that a deregulated electricity market consists of at least two parts, a day ahead so called spot market and futures markets for future delivery or hedging activities. Market participants attempt to hedge risks of a nonstorable electricity commodity with new energy based financial products. The authors illustrate this argument with data of APX-ENDEX, a regional power and energy derivatives exchange. They also perform an empirical analysis about the relationship between spot and futures electricity markets of APX-ENDEX.

1.3

Energy Regulations

Westaway and Simpson argue in Chap. 8 that the EU has weakened the ability of sovereign states to determine what is most appropriate for their own territories, imposing policies and laws that reflect common interests on the energy sector instead. The authors assess the implications of the dissolution of the concept of state sovereignty within the EU on the development of sustainable energy policies. They also provide an econometric analysis on country risk with energy industry stock market data and related political risk indicators. Pielow and Lewendel reason, in Chap. 9, that the Treaty of Lisbon, which went into force in 2009, fuels the integration process within the EU. The new Treaty

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chapter on “Energy” shows that energy policy has evolved into a European subject. The EU may rely on a new energy competence concerning the domestic policy and will issue new acts in the future more easily than before. The authors wait with suspense whether the measures of the legislative package for the energy internal market will be successful. Bommel, in Chap. 10, discuss supervision on various sorts of energy contracts per category of energy suppliers, trade mechanism and time frame. They find that supervision is aimed at counteracting market abuse and not at delivering secure supply. The EU leaves discretionary powers to the member states to execute and comply with its new articles of supervision. The supervision of the financial aspects of energy transactions requires substantial expertise and measures, as well the closure of holes in the supervisory framework.

1.4

Energy Firms

P€at€ari and Westerman discuss, in Chap. 11, the value creation concept within renewable wood-based energy sources. Firms that (re-) direct activities to this area can create value on the interplay between firm-specific capabilities and new business opportunities opening up. The authors show this with an augmented Dephi study on innovating and re-defining business models in the mature Finnish pulp and paper industry. This way, she exemplifies how economic value creation can be assessed at ultimately the firm level. In the final Chap. 12, Arslan and Kazdag˘li start by holding a plea for increasing government control of natural monopolies in the natural gas and electricity industry. European countries have conducted energy reforms since the early 1980s. The Turkish reform example has two aspects. Within the electricity industry, the regulation of entities is undertaken by giving various types of licenses to the firms. The regulation of natural gas markets aims at dismantling the vertical integration in the industry and the study explains the tools that can be put in place to achieve this.

1.5

Energy and Value

Through discussing wide array of concepts touching on European energy markets, prices, regulations or firms, the book ultimately has a financial standpoint. Actually, it has also a perspective of value creation which does not just necessarily mean ‘exploiting resources’, ‘reducing risk’, ‘making money’ or whatsoever. Nevertheless, it may well be the intended outcome of market, pricing, regulatory, or internal processes with governments, consumers, suppliers, companies or other stakeholders. Yet, in pursuing such an aim for the sake of the stakeholders, value creation boils down into financial value creation for them (Rappaport 1986). However, financial markets should do their work properly. The financial value of any activity or item is related to its expected economic earning capacity (see Grinblatt and Titman 1998). This perspective has especially

1 Introduction: Financial Aspects in Energy

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taken off in finance, which studies the trade-offs between the present and the future. The finance view does not treat energy differently from other inputs of production like capital, labor, land, and materials. Yet, the various valuation techniques it has developed can be used to value energy stocks, flows, and claims. Value is the monetary equivalent of the discounted expected cash flows. In valuing energy, the view takes into account uncertain cash flows and uncertain discount rates. The goal of stakeholders is maximisation of the financial value they are entitled to, being: V ¼ CFL1 =ð1 þ kÞ þ CFL2 =ð1 þ kÞ2 þ CFL3 =ð1 þ kÞ3 þ



þCFLn =ð1 þ kÞn with: V ¼ financial value of the stake CFLt ¼ expected free cash flow at time t k ¼ (weighted average) cost of capital The financial value is the sum of the free cash flows, discounted by the cost of capital. The cost of capital consists of the risk free rate of return and several additions for risk components one of which is energy risk. In the wake of the financial crisis, the risk components in the cost of capital have gained importance. In the past, when governments fixed energy prices from time to time, the consequences were treated as exogenous factors. With deregulation of markets, governments no longer determined the prices. Now markets establish the prices. Energy risk, the cash flow volatility from energy price changes, became not only larger, but also endogenous. Its change from being exogenous to endogenous enabled organisations to manage their risk positions. This is what the authors of Financial Aspects in Energy: The European Perspective point out.

1.6

Energy Risks

The risk components of the cost of capital are made up of operational factors as well as financial factors. The former have to do with the business activities of the firm, whereas the latter include risks of interest rate, currency and energy. Especially since the latest credit crisis, many people are aware of the meaning of interest and currency risk. However, most of the people, including many economists, have no clue about what energy risk is. Nevertheless, energy risks have become more important over the years, even without the financial crisis of the late 1900s. For example, a spiking of the oil prices may recur sooner rather than later (Gok 2009). As another example, the electricity market changed from government dictated pricing to a situation where a price is the highly volatile result of market supply and demand. Reduction of energy risk creates – providing that the cash flows remain at the same level – stakeholder value. If being a market party (that is, a relatively small energy consumer to whom energy risk is of little relevance), it does not pay to manage energy risk and a fixed price contract or hedged price will be preferred.

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However, if a company is a relatively large energy consumer, managing energy risk becomes relevant. Still, managing energy risk is not the same as selecting the option with the lowest risk. For example, fuel costs are a main cost component of Ryanair and have a substantial influence on its profit. If Ryanair always manages its open fuel risk position to zero, this policy implies that it is ultimately bringing money to the markets. So, in cases when energy risk is relevant for a certain firm, the company treasurer may want to manage the risk position at a certain level and report upon this. The control of structural risks, such as energy risk, could then be left to the market. It is the task of the treasurer to inform the market about the energy risk position of the company and by doing so the market can use this information in the pricing of the shares of that company in a proper way. Yet, during the height of the ‘credit crunch’ (late 2008 and early 2009), Ryanair was following another strategy. According to The Times (February 3, 2009), Ryanair ‘screwed up’ its policy. The firm locked in fuel prices at US$ 124 a barrel for 80% of its consumption during the third quarter of 2008. The carrier subsequently lost money, as the price of oil collapsed to a low of US$ 133 a barrel during that period. However, it was reported that a lack of hedging in the fourth quarter would enable Ryanair to take full advantage of the low oil price at that time. By only partly (80%) fixing the fuel position, Ryanair was creating a position that deviated from her competitors. So, if the pricing in the market is against the company, it will be difficult to explain company actions to shareholders. Yet, one could argue as follows. Maximisation of shareholder wealth is the firm’s goal, but that goal specifically applies to the normal operations of the firm. In other matters such as hedging market risks, management should be risk averse as the shareholders would be a lot more angry if the fuel position were unhedged and money was lost. Therefore, Ryanair management took a responsible position in removing uncertainty from the fuel price rather than make a speculative gain on the fuel price. As mentioned the shareholders would be livid in the event of a speculative loss. One should not be too quick to accuse managers of irresponsibility in losing money through hedging. With thoughtful energy risk management, parties are well equipped to raise and manage their ‘energy value’. Especially when prices are highly volatile and the future supply of different energy inputs is uncertain, energy risk management is a ‘must’. Given the strategic nature of energy in an energy-intense world, it is evident that this energy value counts at micro, meso and macro levels. However, different objectives, systems, and people are needed at each level in order to satisfactorily manage energy value and energy risk (see also Burger et al. 2007).

1.7

Concluding Remarks

Recently, European energy markets have become increasingly integrated and competitive. The imperfections decline and perhaps so do the inefficiencies. The financial structures at the EU, country and industry levels are following suit. Spot

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and futures financial markets have been established and the number of market players is steadily increasing. Buyers and suppliers can exploit unprecedented private value creation potential as regulatory bodies discover value creation mechanisms to be used for aligning market players with societal aims. Not withstanding the above, the contributors to Financial Aspects in Energy: The European Perspective show remarkable deficiencies of energy markets and financial structures. These include, for example, the handling of sovereignty issues, the coherence of energy programs, the stimulation of sustainable energy sources, the holes in the regulatory frameworks, the tackling natural supply monopolies, the incomplete interconnectedness of networks, the interlinking of prices at the diverse markets and the riskiness of primary and derivatives products. Although the authors of this book do point at solutions for closing the gaps, they must also admit that the issues to be handled are without precedents and very complex. Furthermore, whilst at a European level considerable achievements have been made, a large part of the challenges are occurring at a worldwide level and there is a need for feasible global policies, directives and measures. Nevertheless, as Financial Aspects in Energy: The European Perspective learns, European approaches help to achieve global understanding.

Literature Burger M, Graeber B, Schindlmayr G (2007) Managing energy risk: an integrated view on power and other energy markets. Wiley, Hoboken, NJ Gok T (2009) The financial crisis: a new world order and some implications for energy markets. Energy and Value Letter 2:7–9 Grinblatt M, Titman S (1998) Financial markets and corporate strategy. Irwin/McGraw Hill, Boston, MA Rappaport A (1986) Creating shareholder value: the new standard for business performance. The Free Press, New York

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Part I

Markets

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Chapter 2

The Development of Energy Markets in Europe Mehmet Baha Karan and Hasan Kazdag˘li

Abstract Europe has been engaged in a debate aimed at building an integrated and competitive energy market since the early 1990s. The European Union has instituted to share the responsibility to develop a strategic policy to change current trends, and hence a truly competitive, single European electricity and gas market is expected to open the competition of Europe-wide companies. In this vain, the aim of this chapter is to analyze the developments of European energy markets and regional markets in accordance to the market efficiency criteria and financial aspects of energy. Despite the physical, economic, and political barriers, the number of financial players participating in these markets is continuously increasing and a considerable success has been achieved for efficiency of the markets. However, 10 years after the Lisbon Treaty, the European energy markets are significantly far from the unique energy market goal. Moreover, in Europe’s energy market there are serious malfunctions causing moves to regional fragmentation. Generally, it is agreed that the future structure of the European energy market has not been yet clearly defined. Keywords Electricity market
Energy markets
European Union
Gas market
Market information

2.1

Introduction

The worldwide discussion on energy markets reform started in the early 1980s and then several emerging and developed countries have commenced reform initiates including liberalization, privatization, and restructuring of the energy supply and distribution industry. In this regard, Chile (1982), United Kingdom

M.B. Karan (*) • H. Kazdag˘li Hacettepe University, Ankara, Turkey e-mail: [email protected] A. Dorsman et al. (eds.), Financial Aspects in Energy, DOI 10.1007/978-3-642-19709-3_2, # Springer-Verlag Berlin Heidelberg 2011

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(1989) and Argentina (1992) are the pioneer countries experiencing energy market liberalization. The motivation for the energy market reforms is driven mostly by economic reasons to make the energy sector cost efficient through the introduction of competition among the players (Sioshansi 2006). There are also other drivers for reform namely; political ideology on the faith of market forces, distaste for strong unions, the desire to attach foreign investment and environment concerns (Woo et al. 2003). However, the approach of the European Union (EU) in terms of restructuring energy markets has a broader perspective, which includes not only economic concerns, but also strategic/political goals. Europe, which is heavily dependent on oil and gas from external sources, has been engaged in a debate on building an integrated and competitive energy market since the early 1990s. Leaving aside the previous national energy models, the EU has instituted to share the responsibility to develop a strategic policy to change current trends. A truly competitive, single European electricity and gas market is expected to be a free market and open to competition of Europe-wide companies rather than being restricted to only dominant national actors. The new energy market will improve security supply and boost efficiency and competitiveness. According to a Green Paper, the energy strategy of the EU has three pillars which balance fundamental needs of the Union; securing an expanding supply of energy from both domestic and foreign sources, developing a more competitive internal energy market, and encouraging and supporting environmental protection and development of clean and renewable energy sources (Barroso 2006). The market reform in Europe has started with the British experience and the developments in British markets inspired the EU energy strategy and became the main driver for further developments. Over recent years, a number of changes have occurred in the European energy sector, but 10 years after the Lisbon Treaty the energy markets of Europe still are significantly far from the unique energy market goal (Kroes 2007). The theoretical framework of the European energy policy seems to be suitably designed, but its application is posing considerable problems. The aim of this chapter is to analyze the recent developments in European energy markets and energy trading. In this regard this chapter investigates the stages of energy reform, namely privatization, competition, unbundling, and market efficiency. The expected integration of the regional energy markets in the upcoming years is also discussed. The paper is structured as follows: after a general introduction, Sect. 2.2 reviews the background on the EU’s liberalization and integration. Section 2.3 discusses the EU energy markets with their energy trading, whereas the next section focuses on the barriers of competitive energy markets. Furthermore, market functioning and efficiency of energy markers are analyzed in Sect. 2.5 followed by the discussion of the future of European energy markets is in Sect. 2.6. Finally, the conclusions are given in Sect. 2.7.

2 The Development of Energy Markets in Europe

2.2

13

Background

Since the early 1980s, the most developed countries and also some emerging countries have started to liberalize their infrastructural sectors. Schneider and J€ager (2003) claim that this change is closely related to the increasing importance of infrastructures to modern societies. The energy sector liberalization of the EU is part of the trend toward liberalization and the withdrawal of the state from involvement in infrastructure industries. Jamasb and Pollitt (2005) indicate that currently European energy market liberalization represents the world’s most extensive crossjurisdiction reform of the electricity sector involving integration of distinct statelevel or national electricity markets. Although there have been considerable developments in the last 20 years, it is unfair to praise only the works of the EU member countries. It can be acknowledged that the reform process of the EU is dependent on mostly the driving force of the European Commission (EC). Without the efforts of the EC as a policy maker, the pace of reform in many member states would have been considerably slower. The main advantage of the EC over the individual member states is its approach to the process from a broader perspective and to be free from national interests. It should be noted that the EU’s slow and decisive process, which also includes political goals, is not limited by the adaptation of common rules for member states1 and market integration in Europe is more about moving forward together than about who should adapt to whose trading arrangements. The roots of the energy reform of the union depend on the 1957 Treaty of Rome and the Single European Act (SEA) of 1987, which set the new deadline of 31 December 1992 for the single market’s completion. Then the publication of the 1995 Green Paper on energy policy constitutes a momentum to create a single energy market. This was the initial spark for the new energy market of Europe. Next, European Directives prescribing the liberalization of energy markets entered into force in the second half of the 1990s. Directive 96/92/EC of the European Parliament and of the Council of 1996-12-19 concerning common rules for the internal market in electricity, has made significant contributions towards the creation of an internal market for electricity. A similar approach was implemented for the gas sector in 1998. The role of the Lisbon Strategy (2000) is remarkable in this process. It not only triggered the creation of energy markets in the EU, but also prepared an agenda for the following years. It underlined that without improving the competitiveness of energy markets, the EU would not be the most dynamic and competitive knowledge-based economy in the world, which is an issue aimed at the Lisbon Strategy. The new aims were far more ambitious and global than the first directives on energy markets, and this time gas and electricity were treated jointly in one proposal. 1

U.S. experience is entirely sourced by economic reasons and has never enacted a mandatory comprehensive federal restructuring and competition law, leaving the most significant reform decisions to the states under the politics of de-regulation (Joskow 2008).

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Over the years, several other pieces of energy market legislation have been adopted and political attention has gradually shifted from energy market liberalization towards energy market integration. The second mandated Gas Directive (2003/ 55/EC) regulated Third Party Access (TPA) as the basic rule for all existing infrastructure, as well as moving the level of unbundling of Transport System Operators (TSO) to the level of legal separation. The third package of legislative proposals for the European gas and electricity markets, which provides a general overview of the future energy policy of the EU, was adopted on 25 June 2009. The novelty of the third package is the integration of the energy and the environment objectives of the EU through the use of market-based environmental and other measures. The package also contains measures to reinforce security of supply. The liberalization and integration of European energy markets is a process of discovery, involving continuous interactions between the market players and the regulatory authorities. The historical experience reveals that to reach a more competitive and efficient market structure, the following stages of energy reform should be completed: privatization of publicly owned electricity assets; the opening of the market to competition; the extension of vertical unbundling of transmission and distribution from the generation and retailing; and the introduction of an independent regulator (Pollitt 2009a). Although these stages are interrelated, they are not being developed even in the various European countries.

2.3

EU Energy Markets

The new energy market of the EU is expected to encourage diversification and flexibility to react to market conditions across the countries. It also provides a more powerful bargaining position for European energy companies when sourcing energy in global markets, since there is a larger range of options available with regard to supply routes and there is better access to customers. However, the short experience of the EU revealed that, due to political and economic barriers, the EU would not be able to reach her goals in the near future. These barriers caused significant development differences among the regions, which have different, trading arrangements. After the adoption of the second energy package in June 2003, the EU’s approach to the single market goal in energy markets became much more crystallized and the third package emphasized and routed this objective by the detailed sanctions. In this direction, the EU followed the idea that the final aim of a single electricity market could be achieved by the creation of regional markets as an intermediate step. Currently, European electricity and gas markets are separated into seven and three different regional initiatives respectively, as can be seen in Table 2.1. So, the energy markets have been moving to a regional segmentation. Currently, the regional nature of the energy market is motivated by EU policy makers hoping to manage them more easily in the future than many small markets.

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Table 2.1 Electricity and gas regional initiatives of EU Electricity Regional Initiative (ERI) Regions Countries Central-West Belgium, France, Germany, Luxembourg and the Netherlands Central-East Austria, Czech Republic, Germany, Hungary, Poland, Slovakia and Slovenia Central-South Italy, Austria, France, Germany, Greece, and Slovenia Northern Denmark, Finland, Germany, Norway, Poland and Sweden South-West Spain, France and Portugal Baltic Latvia, Estonia and Lithuania France-UKIreland France, Ireland and the United Kingdom Gas Regional Initiative (GRI) The Netherlands, Belgium, Denmark, France, Germany, Ireland, Sweden North-West and the United Kingdom South Spain, France and Portugal Austria, Italy, Bulgaria, Czech Republic, Greece, Hungary, Poland, South-South East Romania, Slovakia and Slovenia Source: European Commission (2010b) From regional markets to a single European market, prepared by Everis and Mercados EMI

The main advantage of this bottom-up regional approach is that it enables the involvement of the relevant stakeholders more than it is usually possible on a European level. In addition, the regional approach can also better take account of regional specificities, where divergences from the European standards are needed on an exceptional basis. At the same time, the regional approach enables a step-by-step development towards an integrated European energy market. However, it should be noted that, in contrast with the original regional strategy, the regions are different and overlapping. In practice, countries involved in more than one region can of course not be equally committed to every region at the same time. As the spot markets develop, a similar trend in financial markets on energy is being observed with the growth of a variety of derivative instruments. Currently the structure of Europe’s power markets seems considerably complex. There are more than half a dozen exchanges, most of which offer trading in both spot and futures contracts. Some of them started to broaden their activities beyond the national borders.

2.3.1

Electricity Market

The electricity market is the leading market of the EU energy sector even though it has some important problems with competition among member countries and its effectiveness. Although the EU has recognised seven regional electricity initiatives, specifically the European electricity market can be observed in three regional groups: the United Kingdom, the Nordic Countries and Continental Europe. The

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markets differ in not only their historical experience, but also as to their regional characteristics. A recent research indicates that the UK’s energy market remains the most competitive in the EU and G7, since it moved from pure monopolies to a market economy (OXERA 2007). The level of consumer participation in UK energy supply markets is among the highest of any retail energy market throughout the world. The annual switching rate of 18% also compares well with other retail services in the UK, such as fixed and mobile telecommunication, insurance products, mortgages, and personal current accounts. Almost all consumers (96%) know that they can change energy suppliers and most (70%) feel confident that they know how to do this (Ofgem 2009). The Nordic energy market, which is established by integration of the markets of Denmark, Finland, Norway, and Sweden, is the most harmonized cross-border electricity market in the world since the mid 1990s. Nordpool is established by Norway and Sweden as the first international power exchange and next Finland (1998) and Denmark (1999–2000) joined the Nordic spot market. A few major power producers have a dominating position in their markets, but none of them has a big share (more than 20%) of the Nordic market. It indicates that the degree of integration increases the level of competition among the market players. Public ownership is still dominating the region (Amundsen and Bergman 2006). The level of consumer participation in Nordic energy supply markets is relatively high given that customers can easily change their suppliers and tariffs. Since the main feature of Nordic countries is the relatively higher level of annual electricity consumption than in other European countries, this provides an incentive for customers to take an active interest in the market (Littlechild 2006). The Nordic market has properties that distinguish it from the rest of Europe. Amundsen and Bergman (2006) claim that the adoption of the Nordic experience in other countries is not easy, as the success of the Nordic model depends on area-specific factors, such as ample supply of hydropower and significant inter-connector capacities. In particular, the Nordic experiences suggest that a “deregulated” market for electricity works well if there are no price regulations and constraints on the development of financial markets and there is continued political support for a market-based electricity supply system also when electricity is scarce and prices are high. The energy market reform process in most Continental European countries has been driven by the initiation of Germany in the late 1990s, a decade after the advances made in the UK and Norway with the Directives of the EC. The German electricity market is the biggest in continental Europe by number of players and generation capacity. It is also the fastest to open up, with immediate 100% full customer choice without any restructuring of the industry. France has a mass market with more than 3.5 million eligible customers, which makes it third in size among all open markets within the EU (Barthe 2005). The French government postponed liberalization at the beginning, then after 2004, the status of public company EDF has been changed and the market is opened to liberalization. Austria’s electricity market was partly opened to liberalization in 1999, then the whole market was liberalized during the early 2000s and a voluntary energy spot

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market of Austria – EXAA – was established. Four regional companies (EPZ, EPON, UNA and EZH) were dominating the generation in the Netherlands until 1998. Although the Dutch government had planned to organize a “national champion” by merging the four companies into SEP that would have competitive power in the EU market, the merger failed and the major restructuring feature was a sellout to big companies of Europe (Electrabel, Reliant E.ON) (Van Damme 2005). In Belgium, the process has been dominated by Electrabel, which is controlled by the French Suez Group through the intermediate engineering contractor Tractebel. Electrabel and Tractebel were merged in 2005 to be an important player in EU and the world market (Haas et al. 2006). According to the report of the International Energy Agency (2009), Spain has made substantial progress in its energy policy, over the last 4 years. Together with Portugal, it has set up the common Iberian electricity market, MIBEL, and has strong ambitions in developing it further. Spain is determined and successful in promoting renewable energy and puts increasing emphasis on improving energy efficiency. Furthermore, all South East European countries agreed to adopt the EU legislation. Central European countries are physically integrated within the western European grid, and have taken the first steps towards adopting the EU Western Europe model with regulated third party access for larger customers. Poland and Hungary were the forerunners of energy reform (Kaderja´k 2005). The central European electricity market is the largest regional market in Europe and it is obvious that further progress towards an integrated electricity market in Europe will depend strongly on the development of this market (Jamasb and Pollitt 2005). However, the last 10 years of experience indicates that the generation capacity of Central Europe is not diversified well and the number of competitors in the market has not increased sufficiently. Therefore, contrary to expectations in the late 1990s, the wholesale and retail markets lagged behind the objectives of the EU.2 Recent research indicates that there is a very strong market correlation between Scandinavian and continental electricity markets (Germany, Holland, France, Austria and Spain) yet Italian and Polish markets are poorly correlated to all other markets (Majstrovic et al. 2008).

2.3.2

Gas Market

European gas markets have gone through a profound restructuring process since 1998, but the decline of indigenous resources and a growing dependence on large share gas supplies are still the main obstacles of market liberalization and integration. Natural gas accounts for 25% of primary energy use in the EU and nearly 60% of consumed gas is imported (Rademaekers et al. 2008). Since 1998, following the 2

Germany and the Netherlands have persuaded mergers; the Netherlands, Estonia, Austria, and Czech Republic have oligopolies that control more than 70% of the market. Portugal and France have supported the concept of national champions (Haas et al. 2006).

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gas directives, EU markets attempted to integrate and harmonize gas markets while asking for country-specific solutions to take into account different national characteristics. As the gas market of Europe is liberalized, the gas market centres and hubs are developed. Particularly the Bunde-Qude, Zeebrugge, and Baumgarten hubs are the main hubs that are dealing with the largest volumes of gas in Europe. Currently, Germany has the most structured market within the EU and it not only consumes natural gas, but also provides a fair amount of gas storage and serves as a transit country for gas, e.g., to France, via Switzerland to Italy or via Belgium to the U.K. At the beginning of 2000, EU was expected to reach full liberalization before the mid-decade, but European gas markets still lacked competition, cross-border integration, and harmonization. Due to the discretion of the European framework regulation, member states can choose to a large extent which regulatory instruments to apply. Although most consumers in Europe can now choose their gas supplier and a significant progress has been achieved towards the harmonization of national legislation as a result of the EU energy policy, obstacles to competition that are related with the market structures or national attitudes of the countries still remain. Although the former monopoly gas companies are still very powerful in many countries, their market shares have been reduced ever since the competition was introduced. Many European energy companies have moved defensively and tended to resist a change to their traditional business model. To compensate for this, many companies invested particularly in Central and Eastern European countries. Many gas companies have also diversified into the sale of electricity and other utility products such as water and telecoms (Harris and Jackson 2005). It should be underlined that currently power companies play an important role in the European gas market, particularly in Italy, Spain, and the U.K. A recent research indicates that the reform brought about a divergent convergence of regulatory regimes that now functions as a framework for natural gas market organization in the EU (Haase 2008). The sectoral inquiry launched by the EC (2007a, b) reveals serious failures in a competitive gas market in the EU. The report points out five important distortions; the first one is the high level of market concentration in the gas market due to insufficient unbundling and the dismantlement of vertically integrated large incumbents. The second defect is the existence of illiquid gas markets and a lack of infrastructure limiting the access of new entrants. The insufficient cross-border competition, lack of reliable information and transparency of gas markets are the other three distortions. On the other hand, International Energy Agency (2008) underlines that after the 2005–2006 supply crises; energy policy has progressively focused on security of supply issues, instead of on market competitiveness.

2.3.3

Financial Aspects of Energy Trading in Europe

During ongoing liberalization of the energy sector in Europe and many other parts of the world, electricity and gas trading has dramatically increased in many

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Wholesale Trading Market

Over The Counter (OTC) Market

Physical

Forwards/ Options/ Structured Products Settlement: physical and financial

Exchange

Physical

Futures/ Options/ Settlement: Mainly physical

Fig. 2.1 The structure of power trading in Europe Source: Rademaekers et al. (2008)

countries and numerous over-the-counter markets (OTC) and energy exchanges have emerged. Despite the multiple obstructions, the number of financial institutions participating in these markets is continuously increasing. Thus, trading in these exchanges became a basic indicator of market liberalization, but also one of the key drivers of the liberalization. Wholesale power trading in Europe is handled in exchanges and OTC, but these are not equally divided in terms of volumes. The general structure of European power trading is given in Fig. 2.1. While OTCs are the main power of power trading, the importance of energy products and derivatives trading are increasing due to the substantial price and volume risks that the markets can exhibit. Energy trading offers the standardized products in Europe to manage the more volatile market conditions and contributes to lower prices for customers. At the same time, promoted market information supports competition and reinforces market efficiency. Liquid day-ahead and forward markets, together with open intra-day and balancing markets are instrumental to integrating markets.

2.3.3.1

Power Exchanges and OTC Trading

The European power exchanges trade spot and energy derivatives. The total exchange in the spot markets was 820,000 GWh in 2007, which was about 30.4%

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of electricity consumption of the EU-27, whereas futures trading in the same year was about 1.1 million GWh. The biggest three electricity power exchanges are Nordpool, EEX and IPEX (Rademaekers et al. 2008). Powernext and APX NL constitute the second group and the third group of exchanges has very low trade volume: APX U.K., EXAA, Towarowa, Belpex and OMEL. The Nord Pool power exchange is the main trading platform of the Nordic electricity market. The Nord Pool is not only a spot market, which determines the prices on an hourly basis, but also operates financial derivatives markets where major players on the market can hedge system price risks. It is one of the most mature, liquid, and volatile financial power markets in the world. Its price volatility is mainly driven by climate conditions and rainfall. EEX is placed in Germany and it is one of the most important power exchanges in terms of volumes exchanged in continental Europe for both spot and future products. IPEX is the Italian power exchange and it was launched in 2004, as part of an effort at liberalizing the national market and introducing competitive price settling in the physical spot market for power. While Powernext (French) offers spot and future trading, APX NL is a provider of power and gas exchanges for the wholesale market, providing markets for short term (spot) trading only in the Netherlands, the United Kingdom, and Belgium. A single wholesale electricity market for UK was created in 2005, with the inclusion of Scotland, by the implementation of the British trading and transmission arrangements (BETTA). Important characteristics of the UK wholesale electricity market are a relatively high number of different players and the strong role of liquid bilateral markets. Power exchanges account for a relatively small share of electricity trading in UK, given that the majority of the trading takes place bilaterally in the OTC markets through power brokers. Although some power exchanges play an important role in Europe, according to the sectoral inquiry of the EU Commission (2007b), the market concentration is still very high in the national wholesale markets and the large energy consumers still do not believe that prices on spot and forward markets are reflecting the competitive prices. A report of European Commission DG TREN (2008) reveals that spot power exchanges show high volatility over the 2002–2007 periods, although with increasing participants and liquidity, volatility tends to decrease over time. It is also found that derivative markets, although less developed than exchange markets, traded higher volumes in 2007. More importantly, they were notably less volatile than the spot trading. In addition, year-ahead contracts are the most traded products in the derivatives market by volumes. Finally, the study found a clear correlation effect among exchange prices over the 2002–2007 periods. The majority of the electricity trading is carried in the OTC markets. The power market has increased in size by a large extent in Europe as a whole from 2006 to 2007 and continues a trend of growth since 2004. An important component of this trend is the focus of trade in the forward physical markets, although very low financial volumes are being traded. Specifically, approximately 1% of total volumes are made up purely by financial trades (e.g., swaps and options). European markets are moving towards greater physical integration, with more market coupling to increase the efficiency of cross-border interconnectors. The spot

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prices of the biggest two EU markets, the French and German ones, show parallel trends, while the Dutch market shows consistently higher power prices. This finding is in keeping with the perceived consolidation of the two major markets, as they increasingly integrate (ECORYS 2008).

2.3.3.2

Gas Exchanges and OTC Trading

There are significant well working gas trading platforms in Europe. These are APXNL, APX ZEE, APX U.K., Powernext, EEX and Endex (future) platforms. EEW has also established a separate gas exchange platform, which has been offering spot and future trading since 2007. APX has a link to the Zeebrugge Gas Hub, the natural gas trading point in Belgium. It is connected to the National Balancing Point (U.K.) via the Interconnector. There are two spot exchanges that offer gas trading on the APX exchange, which are APXNL (Netherlands) and APX Zee (Belgium). The APX Zee is a relatively new and small exchange and its trading volume is pretty low. APX U.K. is the most mature gas exchange in the Europe. Powernext launched a spot and futures national gas market at the end of 2008. The OTC wholesale gas market in the EU depends on long-term contracts (15–25 years) between incumbents. Oil and oil product index contracts are the main instruments of the markets. The main importers and producing companies from exporting countries are the most significant players of OTC markets, like Gazprom in Russia, Statoil in Norway, and Sonatrach in Algeria. The dominant OTC markets of Europe are Zeebrugge (Belgium) and the TTF (Netherlands). Several other ones are emerging; however, their development is hindered by obstacles in transiting gas cross-border within the EU. Currently the UK is one of the largest natural gas producers of the world and it constitutes the biggest gas market in Europe. The prices witnessed in hub trading have begun to be used as the pricing basis for gas supply contracts, leading to the development of markets where gas is priced according to gas-to-gas competition, rather than being indexed to the price of alternative fuels such as gasoline, fuel oil, and coal, as has traditionally been the case (Harris and Jackson 2005). In the well working markets, gas hubs are supposed to be the platforms for short term gas trading and foster competition through trade with multiple buyers and sellers. However, this principle is not valid in most of the gas hubs in the EU. The trade volumes differ largely among European countries. Gas-to-gas competition is well established in the UK and the gas prices in the UK hubs serves increasingly as a reference for long-term contracts and they are beginning to get a foothold in continental Europe. The influence of oil prices as a reference for the gas prices is thus diminishing and the gas price becomes less dependent on short-term reactions in the oil market. Currently, this phenomenon is limited to the UK, but continental hubs should be further fostered to increase competition and to reduce the impact of oil prices on the gas prices (Schwark 2006).

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The Barriers on Competitive Energy Markets

The strategic and economic importance of energy for the countries, its non-storable feature and environmental impacts gave energy products a special and distinguished status among the other commodities. Inevitably, these distinctive features shaped the three pillar energy strategy of the EU. The strategy and objectives are separately rational and achievable, but all together, they have a very complicated and troublesome nature. Actually, none of these goals are completely separate from one another, but during the process, some of the goals create difficulties to achieve others in the short run. Additionally unwillingness and self-seeking behavior of the member states cause additional problems. These problems that decrease the efficiency of the market are caused by not only technical barriers but also economic and political barriers. Nonetheless, some of the barriers have a mixed nature. The technical barriers are connected with the characteristics of energy. Energy relies on a physical network, which makes markets less liquid and adds technical complexity in the operation of markets. This implies some inherent tendency of gas and electricity markets towards regional fragmentation. More importantly, it even creates strong interdependence among regions with respect to the operation of the network. Network operators have to be closely coordinated in order to make trade possible and the existence of geographical barriers does not always permit trade between different regions. The second group of barriers that slow down the efforts towards the single market has a political and economic nature. Governments are directly or indirectly keeping their grip on market competition. Two reasons in particular, namely security of supply and the complexity of this commodity, justify the intervention of the State (Domanico 2007). Energy security is the most important barrier for the single market goal of Europe and it is very closely connected with other economic and political ones. Energy security issues are forcing member states to continue to retain significant national control over national energy markets and external relations with energy producing countries (Belkin 2008). Besides, the energy sector is considered extremely important for the economic development for all other sectors. This situation has led to the lack of economic incentives for efficiency and thus direct and indirect state subsidies have been required to maintain a stable industry. Several problems, such as overcapacity of generators, did not foster competition but resulted in a lack of incentives for innovation. Furthermore, the type of energy source chosen for using in the electricity production process was based on both internal resources and considerations of security of supply rather than on being the cheapest available (Serralle´s 2006). It is also widely observed that the degree of implementation of the liberalization directives and competition law differs from country to country. Some governments have favored the emergence of national champions arguing that they help to secure their energy supplies. According to The EC Benchmarking Report (2009), which underlines this problem, most of the electricity and gas markets have opened competition in retail at a very high level, but the openness of the market does not reflect the effectiveness of the

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Table 2.2 Degree of concentration in electricity (generation) Very highly concentrated (HHI above 5,000) BE, DK, EE, FR, GR, IE, LV, LX, ML, PT, SK, SL Highly concentrated (HHI 1,800–5,000) CZ, DE, ES, IT, LT Moderately concentrated (HHI 750–1,800) AT, CY, FI, HU, PL, UK, NL, SW The Herfindahl–Hirschman Index or HHI, is a measure of the size of firms in relation to the industry and an indicator of the amount of competition among them. Increases in the Herfindahl index generally indicate a decrease in competition and an increase of market power, whereas decreases indicate the opposite Source: European Commission (2009) Progress in creating the internal gas and electricity market. DG 742 Tren Staff Working Document Report, SEC 287

competition. The market concentration in the gas market is much higher than the power market. Shares of the three biggest companies in the electricity market are still very high in major countries like France, Germany, and Spain, yet as seen in Table 2.2 they are less than 50% in the UK. The share of the big three is more than 70% in all of the EU countries. On the other hand, the market liberalization process is still pending in Bulgaria, Cyprus, Hungary, Malta, Finland, and Portugal. National electricity markets within the EU are extremely diverse in terms of their mix of electricity generation. France depends heavily on nuclear power, coal is significant in Germany, hydro is dominant in Norway, and gas is relatively important in Italy and the UK. Since it is relying much on nuclear energy sources, France has a comparative advantage over her neighbor countries. Although she is supporting integration as a main state of the EU, the uneven distribution of the gains is discouraging the French government from pursuing further integration. Finally, some policies, which support the use of renewable energies, have a regional character and might increase the fragmentation of energy markets. Higher incentives for green energy in a specific country or region might increase the cost of electricity and might cause price differences among the EU countries. On the other hand, investment decisions can be distorted by the existence of different mechanisms to support renewable energies and by the different allocation of emission permits in the context of the European Emissions Trading Scheme (Delgado 2008). Neelie Kroes (2007), who is the European Commissioner for Competition Policy, addressed that 10 years after the Lisbon Treaty the energy markets of Europe were significantly far from the unique energy market goal, The findings on the level of energy market competition indicate that there are serious malfunctions in Europe’s energy markets, due to barriers which were discussed above. In particular, the EU has found some strong evidence that wholesale markets are still at a very high level of concentration, choices of consumers are denied due to the difficulties faced by new suppliers trying to enter the markets, there is no significant cross-border competition, a severe lack of transparency prevents new entrants from competing effectively, and finally, prices often are not determined on the basis of effective competition.

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2.5

Market Functioning and Efficiency of the Energy Markets

Recent researches indicate that energy markets are developing in the EU at rapid rates and the deregulation of energy has had successful results, despite the problems which continue to exist (Christopoulos et al. 2008). However, taking a close look at the some stages of the EU energy market reform and effectiveness of markets gives a clearer picture about the current status of EU markets.

2.5.1

Privatization

The privatization stage is an initial but difficult part of the reforms. Although market structures of the countries have changed in the last decades, only a few countries have full private ownership in the electricity market. Figure 2.2 illustrates a strong move away from full public ownership towards more private involvement, but still the public companies are powerful in France, Portugal, Poland, and some other countries. The reason behind this picture is mostly political given that the governments are keeping their power on market competition. In many cases, governments keep considerable economic interests in energy companies, which might constrain business decisions and thus be an obstacle to the acquisition of such firms by private investors.

Public UK Sweden Spain Slovak Rep. Portugal Poland Luxembourg Italy Ireland Hungary Greece Germany France Finland Denmark Czech Rep. Belgium Austria 1980

Mostly Public

1983

1986

Mixed

1989

1992

Mostly Private

1995

Fig. 2.2 Electricity privatisation timeline by country Source: OECD International Regulation Database, 2009

1998

2001

Private

2004

2007

2 The Development of Energy Markets in Europe

2.5.2

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Unbundling

The current EU Electricity and Gas Directives impose minimum obligations on energy network operators with regard to legal and functional unbundling between transmission/distribution networks on the one hand and upstream (generation or production)/downstream (supply) functions on the other. The companies are not obliged to create separate legal entities for network activities, but have to separate their executive management and decision-making with respect to operation, maintenance, and development of the network. Legal unbundling also presupposes the creation of separate accounts. In addition, Transmission Systems Operators (TSOs) are obliged to treat all system users alike, including access to information according to the principle of transparency and non-discrimination. The majority of the EU countries have applied the unbundling regime; however France, Germany, Greece, Austria, and some other small countries have no ownership unbundling of the TSO. Public ownership is very high and many countries have not legally unbundled TSOs in their energy markets. It is important to underline that ownership unbundling would not oblige the member states to privatize the supply and/or the network business. Where both network and supply activities are currently in public hands, it would be possible to retain the public ownership, provided that sufficient structural separation is achieved. According to the Sector Inquiry of the EU Commission (2007a, b), the unbundling provisions as required by the Second Electricity and Gas Directives are not fully adequate. The ineffectiveness of current unbundling requirements is a major reason for the slow pace of the market integration and the low growth in cross-border trade observed in EU electricity and gas markets.

2.5.3

Independent Regulatory Agency

Although national regulatory agencies have been empowered in the EU during recent years, governance of European energy regulation is still characterized by multi-authority structures at the national level. This structure is criticized by some authors. Specifically, Meeus and Belmans (2008) claim that due to a lack of a European-wide energy regulatory authority, market integration in Europe has been mainly driven by informal regulatory networks among the network operators, standardization authorities, and national regulators. The member states did not accept the creation of a common energy regulator and, instead, tried to increase the regulatory impact through enhancing co-operation among national regulators. Each member state must guarantee that its national regulatory authority exercises its powers “impartially and transparently”. To protect the national regulator’s independence, a member state will have to ensure that the regulator has separate annual budget allocations and can autonomously implement this budget, whereas the members of the regulator’s board or top management are appointed for a fixed

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term of 5–7 years, renewable once. Johannsen et al. (2004) developed an “independence index” which based on the four dimensions of independence: from government, from stakeholders, in decision-making and organizational autonomy, using the data of 16 national independent regulators. They found that the scores of the European regulatory agencies are quite different and the regulators in countries with the least amount of market opening score the highest, i.e., most independent. On the other hand, Jamasb and Pollitt (2005) scored the power of a regulatory agency according to five characteristics, which are indicative of its independence from central government. According to their model, a score of 5 indicates the highest level of independence. They revealed in their December 2009 report that Belgium, Ireland, Portugal, the U.K., and Norway scored 5 and Germany, Denmark, Greece Netherlands and Spain got the lowest score (3). The comparative analysis of Larsen et al. (2006) on 16 European regulators found large differences with respect to formal independence as well as to regulatory practice. They concluded that European liberalization of the electricity market is young and, it is early to expect a definite model of the European independent regulator. Since, the current approach of the EU focuses on an integrated approach to climate and energy policy, the regulation cannot be particularly concentrated on market issues. In addition, as expressed by the EU Council on December 2008, regulation must take energy efficiency issues into account (Vasconcelos 2009). But most European Energy Regulators are state owned and ad hoc governmental agencies so that they do not have any sufficiency of qualification on main energy efficiency matters (ICER 2010). In this regard, EURELECTRIC (2004) points out the followings as the basic weakness of the current European regulatory models: • • • • • • •

Lack of appropriate balance in emphasized on all regulatory objectives Inadequate transparency and consultation Insufficient regulatory accountability Lack of clear responsibility for security of supply Inadequate competent resources Lack of co-ordination between regulatory authorities Inappropriate price controls or inadequate returns

2.5.4

Effectiveness of Energy Markets

Recent reports on EU energy markets indicate that the liberalization has had a positive contribution on effectiveness of gas and electricity markets, but still much effort would be needed to reach the expected level. A report by Ernst and Young (2006) shows that the prices in the gas and electricity markets have significantly decreased. The market created a strong incentive to reduce costs, price volatility, and responded to price signals providing appropriate levels of investment. The researches of Steiner (2001), Hattori and Tsutsui (2004), Fiorio et al. (2007), and

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DaSilva and Soares (2008) showed that there is a strong evidence of productivity improvements, weaker evidence of price benefits and some evidence of price convergence in energy markets. Whereas the study by Meeus and Belmans (2008) reveals that there still exist large wholesale price differences of electricity markets among countries in Europe. The electricity prices in Italy, Ireland, and the U.K. are much higher than the prices in such North Europe countries as Poland, Slovakia, Austria, and Slovenia. On the other hand, Zachmann (2008) shows that the electricity market reforms in the last decade that explicitly targeted the creation of a single European market for electricity were only partially successful. Growitsch et al. (2009) investigated the impact of market operation between the entry–exit zones and market integration in the natural gas sector of Germany, which is the biggest in Europe. They revealed a fair price convergence between the entry–exit zones, implying an increasingly integrated market. The results thus support the notion of a competitive natural gas wholesale market through greater market integration in Germany. On the other hand, the high grid charges, discrimination with respect to access to the distribution network, and high transaction costs of the negotiated TPA (Third Party Access) have been criticized (Haas et al. 2006). Yang et al. (2009) found that the Nordic electricity futures market is gradually tending towards maturity. They revealed that the operation efficiency of the market during 2000–2003 is higher than that during 1996–1999. Lastly, Pollitt (2009b) evaluated the effectiveness of the European energy market, using some well-known measures of efficiency; falling prices, price convergence, improved use of available capacity, labour productivity, resource diversity and energy security. His findings are: • EU average prices (excluding taxes) decreased in real terms for householders and industry. • There has been a price convergence across EU countries, especially for large industrial customers. • Supply and demand balance has improved in recent years. • Labour productivity of the electricity and gas sector increased about 5% for 5-year periods 1995–2000 and 2000–2005 across the EU-15. • The diversity trend of electricity generation is positive since 1994. • There is limited evidence that the risk of large multi-country blackouts has increased cross-border trade in electricity.

2.6

Future of the European Energy Markets

While technological, environmental, economic, and geo-political factors are determining the new structure of European energy markets, the EC is leading the way in several dimensions namely: market restructuring, integration of national markets, internalization of environmental costs, and introduction of new technologies (Vasconcelos 2009). Considering the complex structure of the EU, it is not easy

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to anticipate the speed of the works on the energy reform project, but recent developments evidence that it takes more time than initially expected. Not only the strong will of the commission, but also influences of interest groups and universities, institutions of EU, member state governments and external forces such as Gazprom, and some important suppliers will shape the future structure of the market (Eikeland 2008). On the narrow and rough way of the integration process, the role of the Florence forum, which is academically supported by the Florence School of Regulation since 1998, is very noticeable. The Florence forum is a platform for informal regulatory networks to meet and discuss the integration of energy markets. The forum was established as cooperation between the EC, national regulatory authorities, system operators and network users (producers, traders, suppliers, consumers, market operators, etc.). In spite of the positive developments, the EC report (2010a) underlines that the future success of the regional initiatives depends on how they are able to adapt to a number of challenges. The first challenge is to match the “bottom-up” approach of the regional initiatives, and the more “top-down” approach of the third package, particularly in relation to the drawing up of framework guidelines and network codes. Secondly, there is the risk of divergence if different regions implement different solutions to tackle similar issues. In addition, some important technical and political challenges may slow down, pause or reshape the structure of markets (Domanico 2007; Pollitt 2009a). Haase (2008) points out that once the security of supply enters the policy framework, regulations are less likely to follow competitive market models. Expected increase in future geopolitical uncertainties, together with a greater import dependency on fewer suppliers, energy supply security is likely to move up on the political agenda and needs to balance its position vis-a`-vis carbon reduction objectives. On the other hand, Eikeland (2008) shares the similar view that the EU still has no sufficient will to advocate free-market compatible solutions to greater energy-related environmental problems and security of supply problems. Coupled with European industrial competitiveness concerns, this appears to have cooled down the market enthusiasm of energy policy stakeholders. His study claims that interest groups, supply security issues, new technological advancements on renewable energy sources, reactions of incumbents to market liberalization, and the strategies of former incumbents that increase concentration, rapid decarburization of the electricity sector, and national interests, will influence the shape of the future market structure of Europe. As discussed by Domanico (2007), the special situation of the small EU member states may have considerable effect on the speed of market development. The study points out that through broader strategies and possible anticompetitive behaviors, the big European incumbents are increasing their attention towards different markets and new geographical areas towards the creation of giant multi-utilities. On the other hand, Pollitt (2009b) underlined that South East Europe (SSE) is receiving large amounts of technical assistance from the EU and thus will be a test of the transferability of the EU reform model within the EU.

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29

Conclusion

Europe has been aiming at restructuring a competitive and single European energy market since the early 1990s. The Lisbon Treaty is the first EU treaty to make specific reference to energy and aims to ensure the functioning of the energy market and other single and competitive energy market issues. The approach of Europe depends on the three pillar policy of the EU, namely energy security, competitive markets, and development of renewable energy sources, and includes not only the economic, but also strategic and political goals. Initially, the new energy policy is expected to overcome barriers and to develop security supply and increase efficiency. However, recent experience showed that slow decision processes of the EU have incurred significant difficulties to reach the aimed structure in the foreseeable future. The liberalization process will seriously be influenced by not only the inherent characteristics of energy sources which create technical barriers, but also political and economical problems, which are sourced by government interventions, environmental issues, and energy security. With the forcing effect of successive energy directives and energy packages, the EU has made substantial progress towards competitive energy markets, but currently Europe’s energy market has moved to regional fragmentation, the wholesale markets are still at a very high level of concentration, consumers have some difficulties to switch suppliers, and there is no significant cross-border competition and no transparency in markets, and prices are not sufficiently competitive. However, the comparison of the current market structure with other sectors like telecoms, which have relatively limited barriers for competitiveness, implies some rooms for progress (W€olfl et al. 2009). Despite the physical, economic and political barriers, the number of financial players participating in these markets is continuously increasing. As the number of banks and investment companies enter in energy markets, it is expected that not only market liquidity and volume will increase, but also new investment instruments will be developed and therefore attract the attention of new investors. It is apparent that the participation of financial institutions is a significant factor in the rapid growth of trading volumes observed in recent years in certain major European markets. Generally, it has been agreed that the future structure of the European energy market is still not clearly defined. European policy makers have largely followed a ‘trial and error’ approach in order to pass over these barriers and find the appropriate way to establish the rules and regulations so as to govern energy markets (De Jong and Hakvoort 2008). As the chair of ERGEG, Lord Mogg said (CEER and ERGEG 2009), “The 3rd Package is like Lego. The European market has regional energy markets initiatives, the framework guidelines, and network codes are like the pieces of the Lego, but nobody knows which sort of market should be built”.

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Haas R, Glachant JM, Keseric N, Perez Y (2006) Competition in the continental European electricity market: despair or work in progress? In: Sioshansi F, Pfaffenberger W (eds) Electricity market reform: an international perspective. Elsevier, Amsterdam Haase N (2008) European gas market liberalization: are regulatory regimes moving towards convergence? Oxford Institute for Energy Studies, NG 24 Harris N, Jackson M (2005) A picture of European gas trading market in 2005. Pipeline Gas J 232(8):54–58 Hattori T, Tsutsui M (2004) Economic impact of regulatory reforms in the electricity supply industry: a panel data analysis for OECD countries. Energy Policy 32(6):823–832 International Confederation of Energy Regulators (ICER) (2010) A description of current regulatory practices for the promotion of energy efficiency. Energy efficiency report, June International Energy Agency (2008) World Energy Outlook 2008 International Energy Agency (2009) Energy policies of Spain, Resource document. http://www. iea.org/Textbase/npsum/spain2009SUM.pdf. Accessed 21 January 2010 Jamasb T, Pollitt M (2005) Electricity market reform in the EU: review of progress toward liberalization & integration. Energy J 26(Special I):11–42 Johannsen KS, Pedersen LH, Sørensen EM (2004) Independent regulatory authorities – a comparative study of European Energy Regulators. AKF Forlaget, Copenhagen Joskow P (2008) Lessons learned from electricity market liberalization. Energy J 29(Special II):9–42 Kaderja´k P (2005) A comparison of electricity market models of CEE new member states. Ensuring sustainable electricity enlargement, SESSA working paper 14 Kroes N (2007) Improving Europe’s energy markets through more competition, European Commissioner for competition policy, Resource document. http://europa.eu/rapid/press Releases Action.do?reference¼SPEECH/07/175&format¼HTML&aged¼0&language¼EN&guiLanguage¼en. Accessed 22 January 2010 Larsen A, Pedersen LH, Soensen EM, Olsen OJ (2006) Independent regulatory authorities in European electricity markets. Energy Policy 34:2858–2870 Littlechild S (2006) Competition and contracts in the Nordic residential electricity markets. Utilities Policy 14(3):135–147 Majstrovic G, Bajs D, Sutlovic E (2008) Correlation and regression of wholesale electricity market daily prices in Europe. Int Rev Electr Eng 3(4):699–708 Meeus L, Belmans R (2008) Electricity market integration in Europe. Revue E_124(1)-2008 OFGEM (2009) Energy protecting consumer interests: now and for the future. Annual report 2008–2009, 82/09 OXERA (2007) Energy market competition in EU and G7: forward projections, 2007–11. Prepared for Department for Business, Enterprise and Regulatory Reform Pollitt MG (2009a) Electricity liberalization in the EU: a progress report. University of Cambridge, working paper in economics, 0953 Pollitt MG (2009b) Evaluating the evidence on electricity reform: lessons for the South East Europe (SEE) market. Utilities Policy 17(1):13–23 Rademaekers K, Slingenberg A, Morsy S (2008) Review and analysis of EU wholesale energy markets. EC DG TREN, ECORYS Nederland BV, Rotterdam Rademaekers K, Slingenberg A, Morsy S (2008) Review and analysis of EU wholesale energy markets. ECORYS Netherlands, EU DG TREN Final Report Schneider V, J€ager A (2003) The privatization of infrastructures in the theory of the state: an empirical overview and a discussion of competing theoretical explanations. In: E Wubben FM, Hulsink W (eds) On creating competition and strategic restructuring. Edward Elgar, Cheltenham, UK, pp 101–137 Schwark B (2006) Important New Nodes; Gas Hubs and their Impact on Competition, MIR Network Industries Quarterly, December 2006 Serralle´s R (2006) Electric energy restructuring in the EU: integration, subsidiarity and the challenge of harmonization. Energy Policy 34(16):2542–2551

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Chapter 3

Renewables in the Energy Market: A Financial-Technological Analysis Considering Risk and Policy Options Onno Kuik and Sabine Fuss

Abstract This chapter introduces the most relevant renewable technologies from the European perspective, and provides an analysis of their risk profiles and their advantages and disadvantages in the energy mix. The regulatory frameworks for stimulating investments in renewable energy at both the EU level and in the different member states provide a heterogeneous set of incentives and add an additional source of (policy) uncertainty to potential investors. The analysis starts out with policy at the EU level, and gives examples of how the European policy goals are sought to be realized at the country level. The Spanish experiences with solar feed-in tariffs, for instance, should provide a lesson to the British, for example, who are thinking about heavy subsidies directed at renewables to increase their share in the UK energy mix. A thorough review of these issues from a financial theory perspective provides insights for current and future policymaking. Keywords Energy policy
Portfolio selection
Renewables
Risk and uncertainty
Real options

3.1

Introduction

In the past decade, renewable energy has experienced an impressive growth worldwide, with global annual investments rising from USD 33 billion in 2004 to USD 155 billion in 2008 according to the World Economic Forum (WEF 2010). Some scenarios foresee an increase in annual investments to over 500 billion by 2030 (WEF 2010). Renewable power technologies accounted for a quarter of power O. Kuik (*) Institute for Environmental Studies, VU University Amsterdam, Amsterdam, The Netherlands e-mail: [email protected] S. Fuss International Institute of Systems Analysis, Laxenburg, Austria e-mail: [email protected] A. Dorsman et al. (eds.), Financial Aspects in Energy, DOI 10.1007/978-3-642-19709-3_3, # Springer-Verlag Berlin Heidelberg 2011

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generation capacity added in 2007 worldwide. The emergence of China in the area of renewable energy has been impressive. In 2009, more wind capacity was installed in China than in any other country, and China also announced a huge domestic solar program (Ernst and Young 2010). Over the decade, Europe has remained a strong player in the renewable energy market, with six European countries in the top-ten of Ernst and Young’s “renewable energy country attractiveness index” (Ernst and Young 2010). According to the Renewable Energy Policy Network for the twenty-first century (REN21), by 2008, installed wind power capacity in Europe was 65 GW (representing 54% of world capacity) and grid-connected photovoltaic capacity had reached 9.5 GW (representing 73% of total world capacity) (REN21 2009). The EU continues to be the largest market for renewables worldwide with new investment totaling USD 49.7 billion in 2008 (UNEP/SEFI 2009), representing 42% of total new global investment in renewables. The spectacular rise in renewable energy investments in the EU is illustrated by cumulative annual growth rates (CAGR) of 37% between 2006 and 2008. In 2002, by contrast, investment only totaled USD 3.2 billion. Figure 3.1 below shows the development of the volume of electricity generated by renewable sources in the EU over the period 1997–2007. Despite these reassuring developments, the share of renewables in total electricity generation remains low in most countries, even in the EU. According to estimates of the International Energy Agency (IEA), Europe has to significantly step-up its investments in renewable energy to over USD 1,000 billion in the period 2010–2030 if it wants to cooperate in a global effort to limit global warming to below 2 C as agreed in the Copenhagen summit on climate change (IEA 2009). The question arises why the diffusion of renewables has not been more rapid in the light of both the ambitious EU policies targeted at lower emissions from electricity

Fig. 3.1 Electricity from “new” renewable sources in EU27 in the period 1997–2007 (in GWh, excluding large hydro) Source: Eurostat. http://epp.eurostat.ec.europa.eu/portal/page/portal/energy/data/database (accessed 20 April 2010)

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generation and the strong support for specific renewables in some countries. The following sections will try to analyze this question by examining risk and return profiles of different technologies, where we not only focus on renewables, but also consider the possibility to retrofit existing power plants with carbon capture facilities. After a general introduction to risk and return profiles of renewable energy technologies (Sect. 3.2), we discuss the risk and return profiles of major renewable electricity technologies in more detail (Sect. 3.3). In the subsequent section (Sect. 3.4) we specifically discuss support policies and regulatory risk, focusing on three European countries: Germany, Spain and the United Kingdom (UK). Section 3.5 discusses finance-based risk assessment tools such as portfolio selection and real options theory and their applications to renewable energy investments. Finally, Sect. 3.6 concludes the chapter.

3.2

Risk and Return

The future expansion of electricity generation from renewable sources ultimately depends on the financial attractiveness of these investments for individual investors. Like any normal financial asset, the attractiveness depends on the (expected) riskreturn ratio. Traditionally, policy makers in the renewable energy field have focused primarily on estimates of cost per unit of output in terms of megawatthours (MWh) (for example, USD/MWh) and “learning curves”, i.e., the estimated reduction in unit cost when installed capacity doubles. Systematic analyses of the risks associated with alternative generation technologies are less frequently done despite the fact that these risks may affect revenues and costs. As sources of risk, the UK Energy Research Centre (UK ERC 2007) and Gross et al. (2010) distinguish between price risks, technological risks, and financial risks. It may be useful to also include regulatory risk as a specific, additional source of risk. This will be particularly important when adopting a dynamic perspective on investment, as we will illustrate in a later section. Price risks may affect both revenues and costs. Gross et al. (2010) note that the level of exposure to electricity price risk varies considerably between generating technologies. It should also be noted that many support policies for renewable technologies aim at reducing electricity price risks for the generators. Volatile fuel prices pose price risks for costs. It has been noted (e.g. by Awerbuch 2006) that renewable energy technologies do not face this particular type of risk (except for biomass-based technologies that face price uncertainties of feedstock). A recent additional price risk is associated with the uncertain future price path of carbon permits in the EU Emissions Trading Scheme (EU ETS), which is also subject to regulatory uncertainty to some extent. Technological risks may also affect revenues (e.g. through delays in construction, failures, and utilization levels) and costs (e.g. as a result of operating and maintenance, decommissioning). Technological risk is usually assumed to decrease with the level of maturity of a technology. Renewable energy technologies are

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in different stages of maturity. The technological innovation literature roughly distinguishes the following stages: (1) early R&D to proof-of-concept; (2) demonstration and scale-up; (3) commercial roll-out; and (4) diffusion and maturity. For example, investment into R&D might be regarded as risky, since the arrival of an innovation, as well as its impact on costs, are highly uncertain. On the other hand, R&D can also create a technology option on a carbon-neutral alternative, should carbon policies turn out to be more stringent than anticipated. There may be several reasons that lead finance for renewable energy projects to be either restricted or expensive. A major problem for an investor is to achieve leverage by attracting a substantial share of debt finance (in the financial literature this problem is called the “debt-equity gap”). Biermans et al. (2009) note three finance risk categories for “sustainable” projects. Firstly, these projects often have relatively high risk/low return ratios, amongst other reasons because of high transaction and information costs due to technological complexity, a limited “track record” of investors, and often a lack of securities by these investors when they are new players in the market. Secondly, because of technological and other risks, the projects have a downward risk potential, but because of subsidy-dependence they are unlikely to have a large upward potential (it may be assumed that governments will try to minimize “windfall” profits). Thirdly, the positive contribution of “sustainable” projects to the decrease of negative externalities and the increase of positive externalities such as innovations and technological spill-over is not rewarded by the market but depends on government intervention that is unpredictable, especially in the longer run. Renewable energy projects face regulatory risks as was already flagged in the discussion of finance risks. Lensink et al. (2008) argue that support schemes necessarily balance between stability and flexibility. For example, all countries that have employed feed-in systems have over time adjusted the system to account for changing needs and new insights, either to increase its efficiency or to mitigate unwanted side-effects. For the investor, this flexibility will increase the uncertainty over the expected future cash flows. With too frequent policy changes, government support policies can be perceived as “stop-go” policies, and once investors’ confidence has been weakened or destroyed, it may take a long time to restore it.

3.3

Risk Profiles of Alternative Technologies

There are many different renewable energy technologies, of different maturities and with their own risk and return profiles. In this section we briefly discuss wind, solar, ocean energy, biomass, geothermal, and hydro. We also discuss carbon capture and storage in fossil fuel power. On-shore wind power is considered to be a mature technology. There are still advances in turbine design and size, growing from the current average of 1–1.5 megawatt (MW) to about 2 MW (EEA 2009). The main remaining technological

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challenges are experienced in supporting infrastructure, i.e., power storage, wind forecasting, and grid expansion (WEF 2010). Before the financial crisis of 2008–2009, it was feared that supply constraints in blade and turbine manufacturing could turn into a bottleneck for further expansion, but this has not materialized in 2009 (WEF 2010). The financial crisis did constrain the supply of capital, though. Other bottlenecks are planning permissions, especially in the most populated regions in Europe, and, in the longer term, the geographic isolation (and distance to the grid) of additional locations with good wind characteristics. Off-shore wind is a promising technology that is in the commercial roll-out stage of maturity. Off-shore wind turbines can benefit from stronger, more predictable winds and almost unlimited space. On the downside, however, the harsher marine conditions cause more wear and tear and make operation and maintenance more difficult and thus costly. Other challenges include the grid connection to the mainland and the huge up-front capital investments of over USD 300 million per project. General barriers to the further deployment of wind in Europe include grid integration, limitations to further upscaling, social acceptance, a shortage of qualified work force, and lack of harmonization of government support across the EU.1 In addition, wind energy is an intermittent source that poses specific challenges to the wider electricity system (Gross et al. 2010). Some countries, such as Estonia, Hungary and the Czech Republic, have therefore placed limits on the support for wind (COM 2009a). Solar technologies can be divided into photovoltaic (PV) and concentrated solar thermal power (CSP or STEG) systems. PV systems are mature for some applications, but CSP system s on a commercial scale have only recently (as of 2007) become operational in Spain. PV is still one of the most expensive renewable energy technologies and investment is largely driven by subsidies. Where subsidies are capped or phased out, as it is now the case in Spain, investment slows down (WEF 2010). Barriers to the further penetration of PV include high up-front capital investment costs, lack of skilled personnel, use of precious raw materials, and regulatory and administrative barriers such as access to the grid and long waiting times for connection. Like PV, CSP is largely subsidy-dependent. There are large technology risks for large-scale plants that have not yet been properly tested (WEF 2010). Regarding ocean energy, subdivisions can be made between marine current, wave, and tidal energy systems. A 240 MW tidal energy plant has been operated since the 1960s in La Rance, France. Wave energy systems are currently being studied and tested (e.g. in Scotland). The potential for wave energy generation in Europe is high because Europe is exposed to one of the most energetic sea areas in the world. Potentially, the utilization of this energy could cover a significant part of the energy demand in Europe (Cle´ment et al. 2002). Main barriers to the further development of ocean energy include its technical immaturity, grid infrastructure and connections, administrative burdens, and the high costs of plant construction and maintenance in the marine environment. 1

European Commission, Strategic Energy Technology Plan Information System, http://setis.ec. europa.eu/ (accessed April 10, 2010).

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Biomass (wood, energy crops, agricultural residue, waste) is used to generate electricity through incineration, gasification and pyrolysis (thermal conversion) or anaerobic digestion (chemical conversion). Incineration is a proven technology. Co-firing biomass in coal power stations is (almost) competitive and subsidies are usually not generous (WEF 2010). The main bottleneck to the expansion of the use of biomass to generate electricity is feedstock-related, i.e. its long-term availability, price, and sustainability issues surrounding the production and trade of certain energy crops. This barrier gets enforced by the competition over land, where growing populations and increasing living standards indicate positive trends for food demand, while the EU targets for biofuels also demand higher shares of land. On the other hand, biomass-fired electricity generation in combination with Carbon Capture and Storage (CCS) has been under intense discussion as a source of “negative emissions” in order to achieve the stabilization targets that correspond to the 2 C global warming objective. Uddin and Barreto (2007) illustrate with their calculations how the sequestration of carbon through the growing of the feedstock and the capturing of additional carbon generated during the combustion process lead to emissions significantly below zero. Geothermal energy is used for electricity and heat generation. Various levels of technological maturity exist depending on the energy products (electricity, heat) and the conversion process. The so-called Enhanced Geothermal System (EGS) is an innovation over traditional geothermal systems that can tap resources that were previously unavailable. There is, however, little practical experience with these systems to date. Currently, there are only two EGS plants operational worldwide (WEF 2010). Geothermal projects suffer from very long development periods and high costs in part due to expensive and risky exploration drilling (WEF 2010). The European Commission (EC) adds as further barriers a lack of appropriate legislation (regarding subsoil resources) and financial incentives. Support schemes across European Member States are inconsistent and in some cases inadequate. Fragmentation of existing knowledge and gaps in knowledge increase the financial risk. Hydropower is a mature renewable power technology. A distinction can be made between large and medium-sized plants (>10 MWe) and small plants (<10 MWe). It is usually assumed that most accessible large hydro resources have already been tapped and that further expansion is extremely difficult due to environmental constraints. Nevertheless, some additional capacity can be created through the rehabilitation and refurbishment of old plants (see e.g. Elverhøi et al. 2010). Small hydro, e.g. run-of-river hydro, is relatively low risk and the size of investment is limited. In Europe there is an issue with the implementation of the EU Water Framework Directive (2006/60/EC) that may have constrained the expansion of small hydro (WEF 2010; COM 2009a). Additional barriers include inadequate research investment because of the general misperception that hydro is a mature technology with no significant prospects for additional development, and administrative and institutional procedures. The zero emission fossil fuel power (ZEP) technology is in its demonstration phase. This technology aims to capture at least 85% of emitted CO2 and store it permanently and safely in underground locations. A CCS system basically consists

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of three components: (1) capture, (2) transport and (3) storage. The capture part contains chemical devices such as absorbers and desorbers, currently accounting for 70–80% of the total cost. These devices can be in-built or they can be added to an existing plant, which is more costly (Zhou et al. 2010). The estimated maximum potential of ZEP plants by 2030 is 190 GW or 32% of projected gross electricity consumption by that year. CCS still faces economic and technological challenges. Barriers include the high costs of first-of-a-kind plants, administrative procedures for storage sites, public acceptance, and uncertainties in future carbon prices and the carbon trading scheme.2 For a general overview of the projected costs, we refer the reader to the detailed study on CCS deployment in the Netherlands by van den Broek et al. (2008).

3.4 3.4.1

Support Policies Overview of Support Policies

The EU has formulated ambitious targets for the promotion of renewable energy by its member states. Overall, the share of renewable energy in the Community’s gross final consumption of energy should be at least 20% by 2020 (COM 2009b). Member states are required to support electricity from renewable energy sources, but there is no harmonization of support schemes across Europe. According to a recent inventory of the EC, member states operate 27 different support schemes with various policy instruments such as feed-in tariffs; premium systems; green certificates; tax exemptions; obligations on fuel suppliers; public procurement policy; and research and development (COM 2009a). Held et al. (2006) provide a useful classification of support instruments. They distinguish between instruments that are: Regulatory or voluntary. Most of the promotion of renewable energy in Europe is regulatory, but there are voluntary approaches such as the willingness of some consumers to pay premium rates for “green” electricity and, for example, “responsible care” programs of companies (see e.g. W€ustenhagen et al. (2003) for a European and Wiser and Bolinger (2000) for a US perspective). Investment-focused or generation-based. Investment incentives are given as a percentage of total investment cost or as fixed sum amount per installed kilowatt (kW) of a specific renewable technology. Generation-based instruments support generation costs; they can be either price-driven or quantity-driven as explained below. Direct or indirect. Direct instruments affect the profitability of renewable energy directly. Indirect instruments affect the profitability of substitute (non-renewable)

2

For the latter, see e.g. Szolgayova´ et al. (2008) or Fuss et al. (2009).

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energy technologies. The most prominent indirect instrument in Europe is the EU ETS that puts a cap on energy-related emissions of carbon-dioxide in Europe. Price-driven or quantity-driven. Support policies for renewable electricity can be divided in price and quantity-based approaches. Most member states operate feed-in systems, a price-based approach that sets a technology-specific price for renewable electricity that must be paid by electricity companies, usually distributors, to domestic suppliers. Quantity-based approaches require agents in the electricity supply chain (e.g., generator, wholesaler, or consumer) to produce or purchase a fixed share of electricity from renewable sources or to purchase an equivalent volume of tradable green certificates (TGCs) from renewable electricity producers. Another quantity-driven approach is tendering for renewable energy projects. Tendering is used for off-shore wind projects (Denmark). A support system in a particular member state may consist of a single instrument such as a feed-in tariff or a quota obligation, but most often it is made up of several instruments (including investment subsidies, tax exemptions, etc.). Support systems are usually dynamic as governments phase in and phase out and adjust various instruments due to changing goals, learning effects, or budgetary considerations (Dinica 2006). Most member states use some form or feed-in tariff or price regulation as their dominant support instrument. Germany and Spain are the two prominent examples. A few member states use quantity-based approaches (Belgium, Poland, Romenia, Sweden, and the UK). The Renewables Obligation (RO) system in the UK is the main example.

3.4.2

Germany

Germany has a feed-in tariff system since 1991, first under the Stromeinspeizungsgesetz that was replaced by the current Erneuerbare-Energien-Gesetz (EEG) in 2000. Producers of renewable energy receive a fixed tariff for electricity from the grid operator who is obliged to accept the electricity. The tariff is technology-specific (and location-specific for wind) and is fixed for a period of up to 20 years. The tariff for new projects decreases each year (from 1 to 6.5%) to accelerate investment. In 2008, tariffs ranged from 3.5 ct/kWh (large hydro) to 51.8 ct/kWh for small integrated PV systems (Lensink et al. 2008). The costs of the support system are borne by the final consumers of electricity. The increase of consumer prices for electricity has been estimated at 3% (Traber and Kemfert 2009). The share of renewable electricity in Germany has more than doubled in the period 2000–2009 and is currently about 16% of total electricity production. Wind is the most important of the supported renewable energy sources, followed by biomass, hydro and PV. The German feed-in system is often considered a great success and an example for other countries. While comparing the effectiveness and cost of the promotion of wind power by the German feed-in system and

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quantity-based support systems in the UK, Butler and Neuhoff (2008) suggest that the German system resulted in a higher investment level at a lower cost. Their explanation is that the long-term price guarantee provided by the feed-in tariff reduces regulatory and market risk so much that investors are willing to invest more and require less return (see also Held et al. 2006). A more critical note on the German system is given by Frondel et al. (2009), who argue that the German system is excessively expensive (especially with respect to the support for PV) and does not give the right incentives for innovation and cost savings. The system would stifle innovation as the differentiated set of tariffs “compensates each energy technology according to its lack of competitiveness.” (Frondel et al. 2009: 18). The digressiveness of the system (annual reduction of tariffs) that is intended to encourage cost savings and innovation are in practice to a large extent offset by legal amendments to the EEG that have tended to increase the tariffs. For example, tariffs for biomass and wind in 2009 exceeded those in 2000 (Frondel et al. 2009).

3.4.3

Spain

Spain has a feed-in tariff system since 1980 (Law 82/1980 for the Conservation of Energy). The current support system was established in the Law of the Electricity Sector in 1997 (Law 54/97) that has since been adjusted via a series of Royal Decrees. In the current system, renewable electricity generators can choose between a fixed feed-in tariff – such as in Germany – and a premium on top of the market price of the electricity. Since 2007, a cap-and-floor system for support levels is implemented. The floor is the guaranteed minimum level of market price plus premium and the cap is the level of the electricity price above which no premium is being paid (del Rı´o Gonza´lez 2008). The Spanish support system contains relatively many provisions concerning the fine-tuning of demand and supply of electricity, addressing the concerns about the increasing share of intermittent renewable electricity generation on the grid (del Rı´o Gonza´lez 2008). Up to 2007, the Spanish system performed relatively well with annual growth rates of renewable electricity of up to 20%. In 2007, in the context of a general revision of the support system, feed-in tariffs and premiums were increased to levels that would guarantee “very attractive profitability levels for RES-E3 investors” (del Rı´o Gonza´lez 2008: 2926). Indeed, in late 2007 and 2008 investment in solar electricity generation capacity “exploded”. While in the previous two decades up to 2008 a total capacity of about 500 MW of solar power generation had been installed, in 2008 alone 2,500 MW of capacity was added. In the words of The New York Times (2010): “Chinese solar firms were sending container after container, flush with solar panels, to the country.” In 2008 alone, Spain committed

3

RES-E stands for electricity from renewable energy sources.

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itself to a (future) subsidy to solar electricity producers of about 26.4 billion Euros. According to The New York Times many of the hastily opened solar plants were of dubious quality, poorly designed or located in places were sunshine was inadequate. Because of these consequences, the support for new solar PV projects was frozen in September 2008. This boom-and-bust process has obviously created a lot of confusion with the Spanish government and the solar industry, especially now that the country has been hit particularly hard by the latest financial crisis.

3.4.4

UK

UK has a quantity-based support system. As successor of a tendering system for renewable electricity projects (the Non-Fossil Fuel Obligation: NFFO), the Renewables Obligation (RO) system is in force since April 2002. In this support system, eligible renewable electricity producers receive a Renewable Obligation Certificate for every MWh of electricity they generate. Electricity suppliers are obliged to buy certificates corresponding to a fraction of their total electricity sales. This fraction, starting from 3% in 2002–2003 is gradually increasing to 15.4% by 2015. Non-compliance is penalized and the penalty revenues are channeled back to the renewable electricity producers. The system aims at achieving national renewable energy targets at the lowest cost. It encourages the deployment of cheaper and better-established renewable technologies (Butler and Neuhoff 2008). The system lets the market decide on the most cost-effective mix of renewable technologies to produce a certain fixed quantity of renewable electricity. While some analysts consider this to be a strong point of the system (Frondel et al. 2009; B€ohringer and Rosendahl 2009), others consider this as a weak point (Verbruggen and Lauber 2009). Since 2008, it is in principle allowed under the RO system to differentiate between technologies by adjusting the ratio between certificates and MWh, giving more certificates per MWh to technologies that are deemed to receive extra support (Verbruggen and Lauber 2009). The development of renewable electricity in UK has been somewhat disappointing. The 2009 Renewable Energy Progress report of the EC considers that it is “unlikely” for UK to achieve its 2010 target of electricity from renewable sources (COM 2009a). As explanations, Held et al. (2006) point to a (too) low penalty for noncompliance and to uncertainty on the future price of the certificates. Butler and Neuhoff (2008) analyze the price uncertainty for renewable electricity producers in greater detail and suggest that this uncertainty on future revenues makes obtaining financial support for project development more difficult. In addition, as long as the RO fails to deliver against policy targets, it is subject to frequent government review – adding regulatory uncertainty over the longer term. In Europe there is some fierce debate on the question of the preferred support instrument for renewable energy. The debate is usually centered on feed-in tariffs versus quota systems for the promotion of wind energy. It is not easy to infer the effectiveness and efficiency of support systems from cross-country data. In the first

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place, countries differ with respect to their physical suitability for renewable energy generation (e.g. wind speeds) and they also differ in many other relevant dimensions, such as spatial planning procedures and other administrative barriers (Held et al. 2006). Adjusting for cross-country variation, most studies conclude that feed-in tariffs have historically performed better than quota systems (e.g. Held et al. 2006; Butler and Neuhoff 2008; Verbruggen and Lauber 2009). Somewhat against this dominant stream, Dinica (2006) argues that the support instruments themselves show considerable cross-country variation in their key design variables and that it is therefore not so much the type of instrument that matters for investors, but their design in terms of risk/profitability characteristics. Hence, when poorly designed, feed-in tariffs can bring poor results; well-designed quota systems may be attractive to independent power producers. All authors agree that it is the impact of support policies on risk and return profiles of renewable energy technologies that is crucial for investors. Below we describe assessment tools that can help to better understand the various types of risks that investors are faced with.

3.5

Finance-Based Risk Assessment Tools

Renewable energy technologies thus face a variety of risks such as; technological risks, the volatility of input and output prices, and the uncertainty emanating from regulation. To properly assess these risks, the literature – and partially also practitioners – have turned to methodologies rooted in financial theory to capture all dimensions of the risks associated with renewables and other power-generating technologies. On the one hand, there has been much attention paid to portfolio selection theory, which takes into account the benefits from diversification (Awerbuch and Berger 2003). On the other hand, real options theory has come to the forefront as being the prime method to capture the underlying dynamics of investment into generating capacity (Dixit and Pindyck 1994). Real options theory is a framework taking into account that decisions can be timed flexibly and thus if there is sufficiently large uncertainty, it might actually be economically beneficial to postpone irreversible decisions such as investments involving large sunk costs as those in the electricity sector and wait to make a better-informed decision at a future point in time. Early work in the area of environmental preservation is by Arrow and Fisher (1974) and Henry (1974). Other seminal studies include McDonald and Siegel (1986) and Majd and Pindyck (1987). Dixit and Pindyck (1994) provide a comprehensive introductory text with many applications. Real options have been used quite widely in electricity planning to investigate – inter alia – the impacts of market uncertainties (e.g. Fleten et al. 2007), policy uncertainty (e.g. Szolgayova´ et al. 2008; Fuss et al. 2010; IEA 2007) and technological uncertainty (e.g. Kumbarog˘lu et al. 2004; Murto 2007). While such real options models are well suited for optimization of investment timing and operational

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Fig. 3.2 Risk and costs of generating portfolios Source: Awerbuch (2006), p 699

decisions at the plant level, larger investors rather want to reduce risks by diversification. Portfolio selection, on the other hand, dates back to Markowitz (1952) and rests on the notion that a risk-averse investor will trade off some amount of expected profit for more security: by combining assets that are less than perfectly or negatively correlated, the decision-maker can hedge against the risk of losing excessive amounts of profits. This concept has been applied to investments into real assets in the power sector by a number of studies. Bazilian and Roques (2008) offer an excellent overview of the existing literature and a collection of the latest developments in this field. Figure 3.2 below illustrates the main concept underlying the theory: by adding renewables to a portfolio otherwise composed of fossil-fuel-based technologies (1), the risk of the whole portfolio can be reduced at the expense of accepting slightly higher generating costs (2). Reshuffling the portfolio to yield the previous level of risk demonstrates the magnitude of potential cost savings this entails. These analyses are mostly focused on the static, standard mean-variance framework, however, while Fortin et al. (2008) and Fuss et al. (2010) also test other risk metrics such as the Conditional Value-at-Risk and other objective functions. Few studies also consider dynamics (e.g. Szolgayova´ et al. 2009 and van Zon and Fuss 2008); this work finds significant scope not only for diversification over technologies, but also over time. A combination of real options modeling and portfolio optimization as such had first been implemented by Fortin et al. (2008). Table 3.1 below gives an overview of the different applications of the two methods to electricity planning, ordered by the categories of uncertainty identified to be important above. Regulatory uncertainty is mostly modeled as a price on CO2 (e.g. Reedman et al. 2006; Reinelt and Keith 2007; IEA 2007), but the impact of uncertainty would be similar if subsidies to renewables or feed-in tariffs, for example, would be examined. Szolgayova´ et al. (2008) also investigate the more specific case of having ceilings on CO2 prices in order to protect firms from price spikes. They find this to

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Table 3.1 Real options and portfolio selection theory models for investment in renewable power under uncertainty Uncertainty Energy studies Model type Findings/conclusions for source renewables investment Uncertain timing of CO2 tax Regulatory Reedman et al. Real options: models deters investment in uncertainty (2006) probability that CO2 tax renewables will be levied within a certain period of time IEA (2007), Fuss Real options: jump process Potential jumps raise option et al. (2008, for CO2 price value of investment and 2009), and leads to postponement of Zhou et al. adopting CCS/renewables (2010) Reinelt and Keith Real options: different Social cost of carbon (2007) probabilities that CO2 abatement increases with regulatory uncertainty prices of different magnitudes will be implemented on different dates Price ceilings detrimental to Szolgayova´ et al. Real options: stochastic renewable/CCS (2008) permit prices, but also investment, especially if tests for price ceilings it is lower than the trigger price Fortin et al. Portfolio: stochastic CO2 If the level of CO2 prices is (2008) and high enough, then prices, different scenarios Fuss et al. volatility encourages (2010) inclusion of renewables. Biomass is an exception due to the negative emissions property Technological Balcer and Real options: cost-reducing Uncertainty leads to uncertainty Lippman innovation potential as postponement of (1984) discrete time semiinvestment Markov process More uncertainty leads to Farzin et al. Real options: production delay in technology (1998) efficiency improvement adoption. If technical modeled as a jump change is slow, this effect process, uncertainty about is less because waiting for the speed of technical the arrival of the next change and the magnitude innovation is less of improvement valuable Murto (2007) and Real options: cost-reducing Investment is postponed technical change follows when the step size Fuss and Poisson process increases and the Szolgayova´ (2010) frequency decreases. With a higher rate of expected technical change, waiting becomes more valuable (continued)

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Table 3.1 (continued) Uncertainty Energy studies Model type Findings/conclusions for source renewables investment van Zon and Fuss Portfolio: vintage portfolio Decrease in technological (2008) model with risk aversion, uncertainty leads to stochastic fuel prices and postponement of improvement in capitalinvestment as investors and fuel-coefficients wait for improvements to materialize that are now more certain to occur Postponement of investment, Price volatility Laurikka (2006) Real options: stochastic but results depend and Laurikka electricity and CO2 crucially on price levels prices. Add option value and Koljonen and growth rates (e.g. to switch between (2006) fuels or outputs or to alter operation scale) to NPV Awerbuch and Portfolio: uncertain fuel, Current EU portfolio subBerger (2003) operation and optimal/inefficient. Risk maintenance and could be reduced by construction costs including renewables Awerbuch (2006) Portfolio: fossil fuel price Fossil fuel price risk makes risk inclusion of renewables into generating portfolio attractive Roques et al. Portfolio: uncertain fuel, Market does not provide (2008) electricity and carbon sufficient incentives to prices install a socially-optimal fuel mix; correlations between price processes influence results significantly

be suboptimal, especially if the ceiling falls short of the trigger price of carbonsaving investments. Biomass-fired generation capacity combined with CCS changes the portfolio in favor of renewables mainly through its negative emission property (e.g. Fuss et al. 2010). Technological uncertainty is mostly modeled through a stochastic decrease in cost (Balcer and Lippman 1984) or increase in efficiency (Farzin et al. 1998). Murto (2007) and Fuss and Szolgayova´ (2010) use a Poisson process to model the arrival of cost-reducing innovations and find that an increase in the step size or a decrease in the frequency of innovation arrivals leads to postponement of investment, as the value of waiting increases. Finally, price volatility is the topic of most applications both in real options and portfolio selection studies of investment into renewables and carbon-saving technologies. Table 3.1 offers some examples in real options (e.g. Laurikka and Koljonen 2006) and in portfolio selection theory (e.g. Awerbuch 2006; Roques et al. 2008). In general, price risk leads to a postponement of investment in the former

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case and to more diversification and inclusion of more expensive renewables in the case of portfolio applications.

3.6

Conclusions

Renewables are at the forefront of European policies directed at decarbonizing the energy sector. Achieving a share of 20% renewables by 2020 turns out to be a challenge. However, while renewables do not suffer from the usual risk factors affecting energy generation such as fuel price volatility or carbon price fluctuations, some of them are less mature, have a variable load, and their technological development remains largely uncertain. Locking the energy system into specific technologies prematurely – without being sure that the championed candidates are optimal in the long run – is a risk that needs to be avoided. The typically long-lived character of investments in the energy sector further aggravates that problem. Financial theory has to offer a set of tools to look at such questions and this chapter considers insights from both real options theory and portfolio selection that the former helps to understand the valuation of flexibility in the face of the abovementioned uncertainties in a risk-neutral framework. Portfolio selection theory can also take into account risk aversion and enables a top-down view of energy investments by considering the benefits from diversification. The EU has ambitious targets for the generation of renewable electricity but no harmonized support system. The individual member states use a large number of different support instruments in different combinations. The literature has paid relatively much attention to the comparison of price-based and quantity-based support instruments. The literature suggests that price-based instruments (feed-in tariffs) seem to offer somewhat more certainty to the investor than quantity-based instruments. Because, the actual design of the support instruments is not only so important (and according to Dinica (2006) perhaps even more important than the type) but also differs across countries, we briefly discuss the support of renewable electricity generation in three large European countries: Germany, Spain and the UK, where the former two fall into the price-based and the latter into the quantitybased category. Based on the comparison between these three countries we may tentatively conclude that feed-in tariff support for some technologies has worked relatively well (especially for wind), but that feed-in tariff support for PV solar has stimulated investment but has not yet led to PV becoming cost-competitive. As yet it remains an expensive gamble, championing certain technologies over others on vaguely justified grounds. It is difficult for administrators to predict the supply elasticity of feed-in tariffs, as exemplified by the solar boom in Spain in 2008. Such a boom (and bust) is very negative for the long-term confidence of investors in the market and for the acceptance of the support program by the general public. The RO system in the UK has not yet been sufficiently successful. It suffers from price uncertainty (compounded uncertainty over the electricity price, certificate price,

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and recycled penalties) and frequent government reviews may reduce confidence in the long-term sustainability of the system. Linking the literature review (see table and accompanying discussion in previous section) to the examples summarized above, allows us to draw some conclusions beyond these findings. Even though there is evidence that some policy instruments have fared better than others in promoting the adoption of renewable energy technologies (e.g. feed-in tariffs), applications of methods based on finance and most notably real options theory show that the crucial parameters, which matter are the level of support to renewables or the level of the penalty on fossil fuel use and the uncertainty surrounding the expectation. Even if a relatively promising instrument is chosen, uncertainty about its persistence, for instance, can deter investment in renewables rather than promoting their inclusion in the generating mix. Volatility of fossil fuel prices makes the inclusion of renewables into the generating portfolio more attractive due to their zero fuel cost property. This does not concern biomass, of course, which can also suffer from fuel price fluctuations. Electricity price risk generally seems to play a less significant role for smaller energy companies (price takers) even though hydro plants are likely to benefit from price spikes through storage. In the medium to long run and on a more aggregate level, it is conceivable that electricity prices will stabilize at a plateau, as more and more renewables replace fossil-fuel-powered plants. Studies exploring technological uncertainty typically show that investors tend to wait for a significant breakthrough if they can be relatively certain that it will arrive in a certain period of time. Targeting R&D with public funding may thus be more helpful than enforcing early adoption by championing technologies that only initially appear to be more promising at the expense of other technologies at an early stage of maturity.

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Chapter 4

The CO2 Trading Market in Europe: A Financial Perspective George Daskalakis, Gbenga Ibikunle, and Ivan Diaz-Rainey

Abstract The trading of carbon dioxide (CO2) emission allowances, or permits, has been established in recent years as one of the primary mechanisms for tackling global warming and climate change. The European Union (EU) has taken an important initiative in this direction by establishing in 2003 the first ever mandatory cap-and-trade system for CO2 permits: the EU Emissions Trading Scheme (EU ETS). The purpose of this paper is to initially provide a brief introduction to the EU ETS and subsequently assess its operation during the years 2005–2010 from a financial market perspective. The insights gained through this analysis are particularly important not only for policy makers and market stakeholders but also for the growing community of the so-called ‘carbon’ investors. Keywords Carbon finance
Emission allowances
Emissions trading
EU ETS

4.1

Introduction

The potentially catastrophic consequences that global warming and climate change may have for human health, the environment and the economy, are amongst the most widely debated contemporary issues (see Stern 2007). The consensus view amongst both scientists and politicians alike is that global warming is significantly aggravated by the anthropogenic contribution to the increasing concentration of the greenhouse gases in the atmosphere. In response to these risks, the United Nations Framework Convention on Climate Change (UNFCCC) in 1992 laid the foundations of what is known today as the Kyoto protocol, a global initiative taken by industrialized countries in order to reduce their greenhouse gas emissions and consequently combat climate change. G. Daskalakis (*) • G. Ibikunle • I. Diaz-Rainey Norwich Business School, University of East Anglia, Norwich NR4 7TJ, UK e-mail: [email protected] A. Dorsman et al. (eds.), Financial Aspects in Energy, DOI 10.1007/978-3-642-19709-3_4, # Springer-Verlag Berlin Heidelberg 2011

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The purpose of the Kyoto protocol was to set specific binding greenhouse gas emission reduction targets under a strict timetable and to provide the necessary tools in order to realize them. Following ratification by Russia in early 2005, the protocol came into force after a long time of indecision and tenuous negotiations. Article 3 of the protocol stipulates that the committed industrialized countries, socalled Annex I countries, agree to limit their greenhouse gas emissions, primarily those associated with CO2, during the period 2008–2012 by at least 5% with respect to the 1990 base-year emissions. These reductions are to be achieved at national level, with the goals of each country been clearly specified, through domestic policies, like for example, emission taxes and trading. Since it is expected however that additional emission reduction units will be required in order to attain the designated targets, the protocol enables three ‘flexible’ mechanisms: International Emissions Trading (IET), Joint Implementation (JI) and Clean Development Mechanism (CDM). IET concerns the trading of emission allowances among the Annex I countries, while JI allows the industrialized countries to fund emission reduction projects in other Annex I countries, utilizing part of the reduction for their own greenhouse gas inventory. CDM is similar to JI with the main difference being that the investment projects are to be funded in non-Annex I countries (for a thorough discussion of the Kyoto protocol and its mechanisms see Babiker et al. 2002; den Elzen and de Moor 2002; Nentjes and Klaasen 2004; Godal and Klaasen 2006, among others). Although all three flexible mechanisms are inter-related, the trading of emission permits is considered by the majority of policy makers and economists as the most powerful strategy for promoting greenhouse gas emission reductions in a costeffective and economically efficient manner (see, e.g., Cropper and Oates 1992). The economic rationale behind this policy, initially proposed in the seminal works of Coase (1960), Dales (1968) and Montgomery (1972), is that market forces can ensure the achievement of certain emission reduction targets dictated by national and/or international binding agreements at the least possible abatement cost. This stems from the fact that emitters facing comparatively lower marginal abatement costs for achieving the required emission reductions have within a cap-and-trade system, the economic incentive to proceed to abatement projects (e.g. technological change investments). The reason is that they can sell any surplus permits to those facing higher marginal abatement costs and thus fund (at least partially) their abatement investments. Put simply, trading of emissions provides the former group of emitters with the means to partially fund their investments for technological change necessary for reducing their emissions, and the latter group with flexibility with respect to when to actually proceed to corresponding investments. Europe took an important initiative in combating climate change by establishing in 2003 the EU ETS as its central strategy for the EU member states to fulfil their Kyoto obligations. Since its initiation in 2005, the scheme has witnessed phenomenal growth. Specifically, according to Kossoy and Ambrosi (2010), approximately 6.3 billion tonnes of CO2 (tCO2) were traded in Europe during 2009 in the form of spot and derivative contracts. This is an impressive figure when compared to the 0.3 billion tCO2 traded during the scheme’s first year of operation (Capoor and

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Ambrosi 2008). In monetary terms this translates to approximately US$119 (€89) billion for 2009, an increase of more than 1,380% since 2005. As a result of this growth, Europe remains the leader in the global carbon trading arena with a market share exceeding 86% during 2009 (Kossoy and Ambrosi 2010). It is also interesting to note that the project-based transactions, i.e., those that concern the trading of permits gained through the CDM and JI mechanisms, during the same year accounted only for around 3% of the total permits traded (Kossoy and Ambrosi 2010). This further indicates that trading of emissions is indeed the preferred strategy for attaining the greenhouse gas emission reductions as compared to the other flexible mechanisms. The size of the EU ETS, the stakes at play and the global trend towards CO2 constrained economies has justifiably attracted the interest of both academics and practitioners. In what follows, we present these exciting developments from a financial market perspective.

4.2

EU ETS: A Primer

The EU has agreed under the Kyoto protocol to reduce in the period 2008–2012 the aggregate anthropogenic greenhouse gas emissions by 8% with respect to the 1990 base-year levels. As already mentioned, the adopted European policy in order to meet this target was the establishment of the EU ETS (Directive 2003/87/EC). The scheme was initially designed to run for two phases: the trial 3-year period 2005–2007 (Phase I) and the second 5-year one, which coincides with Kyoto’s first commitment period, 2008–2012 (Phase II). The EU Commission has, however, already decided to continue the operation of the market for subsequent periods, irrespective of whether a new global environmental agreement will be reached. Specifically, according to Directive 2009/29/EC, by the end of the 8-year period 2013–2020 (Phase III) the European countries should have reduced their greenhouse gas emissions by an additional 12% further than their obligations under the Kyoto protocol.1 Under the so-called ‘burden sharing agreement’ (Council Decision 2002/358/ CE) Europe’s emission reduction target was reallocated within its member states in order to allow emissions growth in less developed EU countries and to set more demanding targets for others. For each period of the EU ETS, each member state develops a National Allocation Plan (NAP) that is submitted for approval to the EU Commission. Its goal is to set the period’s emission reduction objective and ‘create’ the total quantity of tradable European emission allowances (EUAs) that will be allocated to the installations that fall under the provisions of the EU ETS directive. With respect to the allocation of the permits to the firm level, it was decided that in 1

These goals are part of the so-called ‘Climate-energy legislative package’ adopted by the EU Commission on April 2009 (see: 8434/09 (Presse 77), ‘Council adopts climate-energy legislative package’, European Commission, Brussels, 2009).

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Phase I (Phase II) at least 95% (90%) of the total number of EUAs will be allocated for free, with the remainder to be auctioned or saved for new entrants into the scheme. For Phase III, EU member states are obliged to auction an increasing proportion of permits, starting from 20% of their total stock of EUAs in 2013 and increasing it annually in order to reach 70% by 2020. The ultimate goal is for all EUAs to be auctioned to the firm level by 2027 (Directive 2009/29/EC). Each EUA gives the holder the right to emit one tone of CO2 into the atmosphere. Thus, a cap is placed on the total quantity of CO2 emissions that every relevant installation can emit each year. During Phase I, the focus was on CO2 emissions associated with fuel combustion. Thus, the scheme covered more than 11,000 installations with generating capacity of 20 megawatts (MW) or higher, that spanned a wide range of sectors; from electricity generators, mineral oil refineries, coke ovens, ferrous metals, glass, ceramic products and cement manufacturers to glass and pulp producers. It is interesting to note that these installations are responsible for 40% of the EU’s total CO2 emissions in the first two phases of the EU ETS (Capoor and Ambrosi 2008). However, electricity generators are the main CO2 emitters and hence the most significant market players. For the subsequent periods of the EU ETS, it is at the discretion of each member state to extend to more greenhouse gases and sectors. For example, the most notable development in this direction was the decision in 2008 to include the aviation sector from 2012 onwards in the EU ETS (Directive 2008/101/EC). Emission allowances are instruments that exist only as electronic records in registries that each member state has established. Thus, although the permits are treated by market participants and regulatory bodies as commodities, physical settlement of relevant derivative contracts can be considered less risky than say gas or petrol since emission allowances involve only a ‘book’ entry in a national account (i.e., the registry). Specifically, the Commodity Exchange Act issued by the Commodity Futures Trading Commission and the Banking Act Implementation Regulation (Article 13-2) explains in an Interpretive Letter (No. 1039, Sept. 13, 2005) by the Office of the Comptroller of the Currency that: ‘An emission allowance is an authorization or license that gives affected entities the right to emit certain pollutants. It is not solely a license to pollute, however. Emission allowances may be bought or sold by any individual or entity that establishes an account at the relevant governmental authority. For those entities that trade emission allowances or purchase allowances with the intent to ‘retire’ them (typically environmental groups), emission allowances are not used as administrative licenses, but rather are more akin to intangible contract rights. Thus, a hedge fund that purchases an emission allowance for investment acquires an intangible contract right that may be transferred or sold to other entities. . . . There are no transportation, environmental, storage or insurance risks associated with possession of emission allowances’. The purpose of the registry is to track each country’s EUA transfers between those who are engaged in emissions trading and is linked to all other EU registries. Thus, the firms that want to include the trading of emission permits into their risk management should set up an account with a registry. All member states registries

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are connected to the Community Independent Transaction Log (CITL) which records all EUA transfers both at national and European level. Each year by the end of April, the relevant installations should deliver to the emissions monitoring authority of their country an externally verified report stating the exact volume (metric tonnes) of CO2 emitted during the previous year. At that time, they should also surrender for deletion a number of EUAs equal to the actual tonnes of CO2 emitted. Failure to comply, results in a penalty of €40 per missing EUA for Phase I and €100 for Phase II, respectively. In Phase III, the penalty will be increased, as compared to Phase II, in accordance with the European index of consumer prices (Directive 2009/29/EC). However, paying the penalty does not waive the obligation to deliver the missing allowances during the next compliance year. This ensures that the penalty does not impose a maximum cap on EUA prices which are solely determined by the market forces of supply and demand. The permits are allocated annually to the emission intensive firms by the end of February. Thus, there is a 2 month period until the relevant installations should submit the externally verified emission reports. Indirectly this implies that the emission intensive firms can ‘borrow’ future EUAs in order to use them for past year compliance. Borrowing though is only permitted within a certain phase of the scheme. The affected installations may also ‘bank’ past year EUA surplus for future year compliance. The majority of the EU member states however, decided to prohibit the banking of EUAs from 2007 to 2008 due to concerns that excessive use of this mechanism might jeopardize the achievement of the Kyoto targets. This follows from the fact that EUAs issued during Phase I could not be used for attaining the first Kyoto commitment period caps.2 The ‘linking directive’ (Directive 2004/101/EC) allows the use of JI and CDM credits for compliance, that is, Emission Reduction Units (ERUs) and Certified Emission Reduction Units (CERs) respectively. These mechanisms are limited to a supplementary role to the EU ETS since they can only cover a small proportion, up to 10%, of each member state’s obligations (see IP/06/1650). In Phase III however, this is expected to increase (Kossoy and Ambrosi 2010). The way that this process takes place is that each member state surrenders for deletion one EUA for each CER or ERU that it plans to use for compliance. Finally, in order to increase liquidity in the market, the EU ETS directive allows non-emitting firms or individual investors to engage in EUA trading for say, speculation or diversification purposes. The only prerequisite is for the interested investors to establish an account in the registry of an EU member state. 2

The European countries were free to decide whether or not to allow emission allowance banking between Phase I and Phase II of the EU ETS. With the exception of France and Poland, all other member states decided against this possibility. Even in these two cases however, banking was strictly limited since it could only be implemented after the approval of the EU Commission. Furthermore, there was a maximum limit on the number of EUAs that could actually be banked, equal to the difference between the initially allocated allowances and the effective emissions of the installation. More importantly, any EUAs purchased in the EU ETS markets during the preliminary period of the scheme could not be banked. For Phase II onwards though, inter-phase banking is permitted (see MEMO/06/452).

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As expected, this feature of the scheme has attracted an increasing number of investors. For example, a relatively recent report by Fusaro (2007) notes that in 2007 there were over 60 specialized carbon funds, with three multi-billion funds in that group (RNK Capital, Climate Change Capital and Natsource), and three fund-of-funds (Kenmar, RMF and Parker Global Strategies).

4.3 4.3.1

Emissions Trading in the EU ETS Exchange Platforms and Traded Products

Market participants in the EU ETS can trade in emission allowance spot, futures and options on futures. In both phases of the scheme however, the bulk of the transactions is in the form of futures. Specifically, according to Kossoy and Ambrosi (2010), during 2009 approximately 73% of the carbon transactions were in futures, 22% in spot permits and the remaining 5% in options. This is particularly interesting especially if one considers that the trading in the spot and options market increased in 2009 as compared to the previous year by 450 and 70%, respectively. A plausible explanation for this ‘trading behavior’ is discussed by Daskalakis et al. (2009). In particular, the authors argued that since emission allowances are required only once per year for compliance, there is no advantage in holding spot EUAs as compared to holding a corresponding position in futures. More importantly, a long spot position requires an immediate investment, while a long futures one requires only the capital necessary for covering the margin requirements, that is, a substantially smaller investment relatively to the former case. On average, approximately 70% of the carbon transactions during Phase I of the EU ETS were performed over-the-counter (OTC) (Kossoy and Ambrosi 2010). The remaining were realized through six trading platforms: the European Climate Exchange (ECX), Powernext, Nord Pool, the European Energy Exchange (EEX), Energy Exchange Austria (EXAA) and Climex Alliance. Powernext, Nord Pool, EEX and EXAA are the French, Nordic, German and Austrian energy exchanges, respectively. More than 50% of the exchanged-based futures transactions in Phase I were realized through the ECX, followed by Nord Pool, approximately 30%, and EEX, about 20%. Spot permits were primarily traded in Powernext, with a market share of more than 80%, and Nord Pool, which accounted for about 15% of the total spot trades. In the remaining platforms, the spot trading was particularly thin with most of the business days exhibiting virtually zero trading volume. In Phase II, the recent financial crisis raised concerns among market participants with respect to the potential for counterparty default when engaging in OTC transactions. As a result, exchange-based carbon trades started increasing relatively to the OTC ones. Specifically, according to data presented by Kossoy and Ambrosi (2010), by January 2010 the ratio of OTC and exchange-based trades was unity. Furthermore, with respect to the exchange platforms, two notable developments

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occurred in Phase II. First, on December 2007 NYSE Euronext purchased the environmental business lines of Powernext, which consisted of Powernext Carbon and Powernext Weather, and launched in Paris a new market in collaboration with Caisse des De´poˆts under the name BlueNext. Second, a new US based emission allowance trading platform was created in 2008 by 13 financial institutions, including the Chicago Mercantile Exchange (CME), Credit Suisse, Goldman Sachs, JP Morgan and Morgan Stanley among others, under the name Green Exchange Venture. As far as the market shares in Phase II are concerned, ECX not only remains the leader in the European carbon market, but also has increased its market share to more than 90%. ECX is followed by BlueNext, which accounts for approximately 6% of the carbon trades, with the remaining platforms having market shares of less than 1% each. Thus, the focus in the subsequent sections is on ECX and BlueNext.

4.3.1.1

European Climate Exchange

The ECX (http://www.ecx.eu), located in London, is a member of the Climate Exchange Plc group of companies, including also the Chicago Climate Exchange (CCX) and the Chicago Climate Futures Exchange (CCFX), and manages the development and marketing of several carbon derivative instruments listed and traded in the Intercontinental Exchange platform (NYSE ICE). Specifically, investors in the ECX can trade in three different types of derivatives that have as underlying either EUAs or CERs (i.e., the permits obtained through the CDM mechanism of the Kyoto protocol): futures, daily futures and option futures. The trading in physically delivered EUA futures was initiated in April 2005. The contracts are listed on a quarterly expiry cycle (March, June, September and December) up to December 2012, while currently futures with annual (December) deliveries for 2013 and 2014 are also traded. The underlying of these contracts is 1,000 spot EUAs. The trading is continuous, initiates at 7:00 a.m. and ends at 5:00 p.m. UK local time from Monday to Friday. The futures mature on the last Monday of the traded month and are physically settled 3 days after expiry. It should be noted that the EUA futures, and especially those with December maturities, account for most of the liquidity in the market and represent the majority of the carbon transactions. In March 2008, ECX introduced CER futures. These are similar instruments to the EUA futures with the main difference being that the underlying in this case is CERs. A year later, ECX launched the daily EUA/CER futures. The specification of these contracts is again similar to that of the EUA/CER futures described above. The difference is however that, as the name suggests, the physical delivery of the underlying is made the day following the transaction. Finally, ECX initiated in October 2006 (May 2008) the trading of Europeanstyle call and put options written on EUA (CER) futures with December maturities. The contract size is one EUA (or CER) future, while exercising the option translates into a corresponding position in the underlying futures contract. For example, when

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a long position in the December 2011 EUA/CER option future is exercised, it is turned into a long position in the EUA/CER December 2011 future. 4.3.1.2

BlueNext

As already mentioned, BlueNext (http://www.bluenext.fr), located in Paris, is the result of the collaboration between NYSE Euronext and Caisse des De´poˆts. In essence, this collaboration involved the acquisition of Powernext’s environmental business lines in December 2007, during which time this new platform initiated its operations. Powernext launched the trading of spot EUAs in June 2005. These contracts concerned the physical delivery of one EUA the day following the transaction. The spot contracts traded in BlueNext since February 2008 again involve the delivery of one EUA. However, both the settlement of the positions and the delivery of the underlying are now performed in real time. According to BlueNext, it takes on average just a mere 15 minutes for the delivery of the permits. The trading is continuous and is performed Monday to Friday from 8:00 a.m. to 6:00 p.m. Paris local time. In April (June) 2008 BlueNext initiated the trading of EUA (CER) futures. These are physically delivered annual contracts with December maturities from 2008 up to 2012. The contract size is 1,000 EUAs (CERs) and the futures are settled in the last business day of November. Finally, in August 2008, BlueNext also initiated the trading of spot CERs.

4.3.2

Financial Regulation of the Carbon Markets

In relation to the carbon markets it is important to distinguish between environmental regulation and policy on the one hand and financial regulation on the other. The former is concerned with market design, while the latter with the functioning and integrity of the market once it has been established. Currently the financial regulation of both financial derivatives and energy markets is attracting considerable attention.3 There are two main reasons for this: First, the recent financial crisis and the role that derivatives like credit default swaps (CDS) played in it, has meant that policy makers are undertaking wholesale reviews of the regulation and operation of financial derivatives markets.4 The focus of these reviews is principally on the lack of transparency and the related risks associated with the OTC transactions. Second, there has been a great deal of concern and debate that the run-up in commodity prices in general, and of oil prices in specific, in the latter half of the 3 There is a debate on whether carbon markets are part of the energy markets with convincing arguments from both sides. From a regulation perspective however this is considered to be the case. 4 See: COM (2009) 332 final, ‘Ensuring efficient, safe and sound derivatives markets’, European Commission, Brussels, (2009).

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decade were caused by speculation.5 For example, oil prices started the century at around $25 per barrel and gradually increased to a peak of $147 in July 2008 only to collapse in the subsequent 6 months to around $40. The implications of this price rally reverberated widely since inflation was driven higher contributing in turn to the monetary policy tightening during 2004–2006 that, arguably, acted as a trigger to the bursting of the credit bubble. This episode highlights the potential for energy markets risks to spill-over into both energy security and macroeconomic risks and explains the increasing mobility of the financial regulators. As already discussed, the preponderance of carbon trading occurs in the City of London via the ECX platform. This places the UK’s Financial Services Authority (FSA) as the financial regulator with the greatest oversight of the carbon markets. The Financial Services and Markets Act of 2000 (FSMA) gives the FSA five statutory objectives: (1) market confidence, (2) public awareness, (3) financial stability, (4) consumer protection, and (5) the reduction of financial crime. Based on both the FSMA and the Markets in Financial Instruments Directive (MiFID), the FSA regulatory boundaries cover the emission derivatives (but not their underlying) through a risk-based regulatory approach that includes also the close and continuous supervision of the ECX and all major market participants (see, e.g., Doyle et al. 2007; Hill et al. 2008; Hanks 2010). In addition to the regulatory oversight, the FSA has also established the Commodity Standing Group (COMSG) where stakeholders can discuss market and legislative developments. The FSA has identified a range of risks related to commodity markets in general and carbon markets in particular. These include (1) market foundation risk, (2) market abuse risk, (3) market infancy risk, (4) information risk, and (5) liquidity risk (see Doyle et al. 2007; Hill et al. 2008). Most of these risk factors however, relate to the underlying markets that fall outside the FSA regulatory boundaries but have the potential to spill-over into the emission derivatives markets (Hill et al. 2008). The FSA observes that the carbon market has operated, on the whole, in an orderly manner (see Hill et al. 2008). However, again it makes it clear that the FSA is not responsible for the environmental effectiveness of the market, since its responsibilities lie solely on whether the market operates in an orderly manner (see Hanks 2010). Nonetheless, two particular issues have arisen. The first was the price collapse of the EUAs that occurred in April 2006. This highlighted not only the ‘market foundation risk’ (from the overly generous caps) but also emphasized the potential ‘market confidence risks’ of disorderly release of information from both the administrators of the EU ETS and the politicians that drive the market design for the future phases of the market. The second issue relates to financial crime through the so called ‘Missing Trader Intra-Community’ or ‘Carousel’ fraud. This involves charging VAT on transactions but not passing it on to authorities and has been observed in various contexts. One of the latest incarnations of this fraud involved EUAs, costing the EU member states around €5 billion. This also 5

See: ECFIN/ARES 205086, ‘Report on oil price developments and transparency issues (Note for the attention of the Economic Policy Committee, DG Economic and Financial Affairs)’, European Commission, Brussels, (2010).

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contributed to large increases in EUA spot trading volumes during 2008–2009. However, changes in VAT rules have now been made in order to prevent this from happening again (see, for more details, Kossoy and Ambrosi 2010). Currently, a bewildering array of policy initiatives and reviews has the potential to affect the financial regulation and operation of the carbon markets. From the EU there are currently reviews of the MiFID, the Market Abuse Directive (MAD) as well as the Directorate-General (GD) for energy consultation on energy and carbon markets. Moreover, there are ongoing developments related to the ‘third (energy liberalization) package’ such as the creation of the European Agency for the Cooperation of Energy Regulators (ACER). International initiatives include work by the International Organization of Securities Commissions (IOSCO) Commodities Task Force. It would be foolish to second-guess where these will lead but what does seem fairly sure is that both the EU and US proposed legislation/ directives that will increase transparency in the OTC derivatives markets and subject major market participants to increased regulation, including minimum capital requirements. For example, the EU Commission envisages greater regulatory oversight, transparency and reduced counterparty risk occurring via ‘(i) promoting further standardization, (ii) using central data repositories, (iii) moving to CCP [central counter party] clearing, and (iv) moving trading to more public trading venues’.6 The net effect of these changes would be to move larger proportions of trading from OTC to exchange-based markets. The impact that this will have on carbon markets in turn depends on the extent that OTC transactions dominate. With 50% of the carbon trades being currently undertaken OTC however (Kossoy and Ambrosi 2010) it should be expected that the impact of these developments will be substantial.

4.4 4.4.1

Lessons Learned from the EU ETS Operation in Phase I Intertemporal Trading

The size and importance of the emission permit markets in general and of the EU ETS in specific have attracted over the last decade a considerable amount of academic papers that investigate the design and optimum structure of a cap-andtrade system both from an economics and a policy perspective (see, e.g., Joskow et al. 1998; Schmalensee et al. 1998; Stavins 1998; Svendsen and Vesterdal 2003). What has been made clear from these studies is that the required economic efficiency and therefore the success of a cap-and-trade system, like the EU ETS, is closely associated with the flexibility that the emission intensive firms are given with respect to their decision on when and how to abate emissions (e.g., Rubin 1996; Kling and Rubin 1997; Schennach 2000; Schleich et al. 2006). 6

See: COM (2009) 332 final, ‘Ensuring efficient, safe and sound derivatives markets’, European Commission, Brussels, (2009).

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Specifically, the fact that through emissions trading the required emission reductions are achieved at the least possible abatement cost is a consequence of the flexibility that the relevant installations have in such a setting to move the permits across sources of pollution (e.g., Rubin 1996). It is thought however that this flexibility is further enhanced if emitters are also given the right to move the permits across time periods, that is, if the permit system allows for the intertemporal trading, or equivalently the banking (or borrowing), of emission allowances (see, e.g., Kling and Rubin 1997; Schennach 2000). Contrary to the consensus view in the literature however, the EU member states decided, as already discussed, to prohibit the intertemporal trading of the permits between the two first phases of the EU ETS. An interesting question arising thus is how did this policy affect the operation of the EU ETS from a financial market perspective? Two main consequences of the inter-phase banking prohibition can be identified. The first concerns the part played in the market crash that occurred in March/April 2006 which wiped out over half of the EU ETS market value. The second is with respect to the pricing of inter-phase futures, i.e., those that initiate in one phase of the EU ETS and expire in the next one, which in turn had a substantial impact on the risk management practices of the emission intensive firms and the overall efficiency of the market. As depicted in Fig. 4.1, spot EUA prices in Powernext dropped abruptly from a range between €20 and €30 to only €10 over a period of only a few days. Soon

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Fig. 4.1 Spot and intra-phase futures prices in Powernext and ECX. Note: The figure displays the prices of the spot EUAs in Powernext in the period 24/06/2005–28/12/2007. The prices of the most liquid intra-phase carbon futures traded in the ECX during the preliminary phase of the EU ETS, i.e., the Dec-06 and Dec-07 contracts are also presented

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after, the spot permits were trading for months at a value of only a few cents. A similar behavior is also observed in the prices of intra-phase carbon futures, i.e., those that initiate and expire within the same phase of the EU ETS, presented in the same figure.7 More importantly, this discontinuous drop in prices induced, as expected, particularly high levels of historical volatility (>95%), as approximated by the standard deviation of emission allowance spot and intra-phase futures logarithmic returns (see, e.g., Paolella and Taschini 2008; Daskalakis et al. 2009). What was however the reason behind this crash? The driving force of this dramatic fall was the publication of the first external verified emission reports regarding the actual emissions of the participating firms in the EU ETS during the previous compliance year (see, e.g., Parsons et al. 2009). These reports indicated that the EU member states had provided their emissions intensive firms with very generous caps and hence, that the market was not as short as was thought to be. However, the fact that banking of EUAs between the two first phases of the EU ETS was not allowed meant that any surplus permits could not be carried forward and would soon become worthless. As a result, it is safe to assume that the emission intensive firms were trying to reach the end of Phase I of the EU ETS holding a number of permits just equal to the amount that they would require for attaining environmental compliance. In turn, this resulted in a pressure on the supply side of the market and hence in a drop in permits’ prices. Thus, it can be argued that had the banking of the permits been allowed, then the emission intensive firms would have had an incentive to save any surplus permits for use in the ‘stricter’ Phase II of the EU ETS (Capoor and Ambrosi 2008), instead of shorting them in the carbon markets and thus crashing their prices. Consequently, it can be inferred that the discontinuous drop in the EUA prices resulted from the combined effect of the generous caps set out by the EU member states and the interphase banking prohibition. With respect to the pricing of the inter-phase futures, Fig. 4.2 presents the prices of the two most liquid contracts traded during Phase I in the ECX. Emission allowance spot prices from Powernext are also presented for comparison purposes. It is clearly visible that in the case of the inter-phase futures, the effect of the market crash was not as severe as it was for both the spot and intra-phase futures prices. More interestingly, in the period following the crash, the prices of the inter-phase futures remained at high levels indicating that they were not affected by the combined effect discussed previously. In an attempt to explain this behavior, Daskalakis et al. (2009) argued that since the permits could not be transferred from 2007 to 2008, the underlying of the inter-phase futures was in reality not traded during Phase I of the EU ETS. In other words, the spot EUAs underlying these contracts were a different asset from the spot permits that were trading up to the end of 2007. Figure 4.2 reveals also that even in the period preceding the market 7 This is to be expected however since the prices of the intra-phase futures are directly linked to spot prices through the cost-of-carry relationship with zero storage costs and convenience yield. In other words, intra-period carbon futures prices are simply discounted expected future spot prices (see Daskalakis et al. 2009).

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Fig. 4.2 Inter-phase carbon futures prices in ECX. Note: The figure displays the prices of the most liquid inter-phase carbon futures traded in the ECX during the preliminary phase of the EU ETS, i.e., the Dec-08 and Dec-09 contracts. The period covered is 24/06/2005–28/12/2007. Spot prices from the Powernext are also presented for comparison purposes

crash, the prices of the inter-phase futures did not follow closely the emission allowance spot prices. This is in contrast to the case of the intra-phase futures and suggests a differentiation in the pricing mechanism between these two categories of contracts. Daskalakis et al. (2009) discussed in detail this issue and argued that since storage costs for the inter-phase futures are still zero, the differentiation arises due to the presence of a significant ‘convenience yield’ in the inter-phase futures prices. Specifically, the authors argued that since the emission allowance allocations for Phase II of the EU ETS were not known up to the end of 2007 and the permits could not be transferred between the two first periods of the scheme, there was a realistic risk for those holding the short inter-phase futures positions to fail environmental compliance in Phase II. Thus, this yield represented an incentive for investors to take short inter-phase futures positions, or equivalently, a compensation for assuming the risk of not attaining the required emission reduction targets in Phase II and thus paying the strict penalties set. Thus, the ban on the intertemporal trading of EUAs from 2007 to 2008 had also the unprecedented result that derivatives with in essence the same underlying to have different pricing mechanisms depending on their maturity. This certainly had a substantial impact on the trading of these instruments, especially if one considers that in Phase I the trading was mainly performed OTC, meaning that it was imperative for market participants to be able to easily and accurately price these instruments. Naturally, this complication meant additional complexities for the risk management practices of the emission intensive firms and additional costs for

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market participants in the form of a positive convenience yield (Daskalakis et al. 2009). This might also explain both the relatively low liquidity of the inter-phase carbon futures as compared to the intra-phase ones and the market inefficiency reported by Daskalakis and Markellos (2008).

4.4.2

Initial Allocation

In an emissions constrained economy, the price of permits represents a production cost for the affected installations and hence, in accordance to classical economic theory, this cost should be passed on to the consumers. As already mentioned, the main sector affected by the initiation of the EU ETS is the electricity one. Thus, following the establishment of the scheme an increase in the price of power was anticipated (e.g., Smale et al. 2006; Linares et al. 2006; Kara et al. 2008). However, as already discussed, the EU ETS in Phase I was not short in EUAs, due to the generous caps provided by the EU member states to their emission intensive sectors, and the initial allocation of the permits was made free of charge.8 In essence thus, this implies that in Phase I electricity prices should have not been increased as a result of the EU ETS. What happened in reality is, however, somewhat different. Specifically, various researchers identified an increase in electricity prices under the pretence of the substantial carbon costs (e.g., Keats and Neuhoff 2005; Sijm et al. 2006). For example, in the case of the UK, Fezzi and Bunn (2007) reported that a 1% shock in carbon prices translated in Phase I to a 0.42% shock in electricity prices. Put simply, the free initial allocation of EUAs in the EU ETS provided arbitrage opportunities for the power producers to exploit that resulted to the so-called windfall, (i.e., unexpected) profits.9 Moreover, as argued in Daskalakis and Markellos (2009) further windfall profits were also potentially attainable due to the free initial allocation of the EUAs in the electricity derivatives markets. Thus, this policy had on the one hand a substantial impact on electricity prices and hence consumers and more importantly, on the other hand deterred the emission intensive firms to proceed to investments in emission abatement projects (e.g. technological change).

8

Again the free initial allocation of emission allowances in the firm level was against the consensus view in the literature. Specifically, the initial allocation can take the form of either free allocation, based on the historical emission patterns of the relevant sectors (the so-called ‘grandfathering’), or through auctions, or through a combination of both (see Boemare and Quirion 2002; B€ohringer and Lange 2005; Vesterdal and Svendsen 2004 among others). Researchers however point out that auctions should be preferred since only then there would be a clear price signal for the permits that could in turn foster price transparency in the market (Grubb and Neuhoff 2006). 9 Although it can be argued that these profits were far from unexpected for electricity producers.

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Conclusions

In our view, Phase I of the EU ETS was a great success, despite all the shortcomings discussed earlier, since it served its purpose. Specifically, as already mentioned, the period 2005–2008 was meant to be a trial period, that is, its purpose was to initiate the trading of emission allowances in Europe prior to Kyoto’s first commitment period so that the relevant installations can gain on the one hand the necessary know how with respect to emissions trading and policy makers on the other hand to obtain an understanding on how to optimally design the scheme for 2008–2012, i.e., when the Kyoto obligations are to be attained. Based on the first phase experience thus, policy makers proceeded to several adjustments with respect to the EU ETS design. For example, as already discussed, they set stricter caps for Phase II, allowed the intertemporal trading of emission allowances between different phases of the scheme, started auctioning the permits to the firm level and included the aviation sector in the scheme (see Directives 2009/29/EC and 2008/101/EC, respectively). From a financial market perspective, the first two revisions address the issue of high market volatility, the third one eliminates any windfall profits for market participants while, the inclusion of the aviation sector increases market liquidity. Nonetheless, as in any other commodity market, liquidity and therefore market efficiency is driven by the speculators in the market. Thus, policy makers should concentrate on the financial regulation underlying the carbon markets in order to promote market confidence and financial stability. To this end, there are a number of issues that still need to be addressed. First, there appears to be no reason why regulation of derivatives should, and the underlying should not, fall within the remit of financial regulation. Both should be subject to a consistent approach where regulatory oversight is not defined by some arbitrary legislative boundary as is currently the case. Rather, boundaries should be defined by a comprehensive risk based assessment that takes into account the sources of risks and product differences (i.e. the different risks implicit in the underlying and their derivatives). Thus, it would be appropriate to have one regulatory body responsible for both underlying and derivatives markets. Whether this should be the financial regulator (for instance the FSA for the UK) or the energy regulator with a financial regulation capability (e.g., the Office of the Gas and Electricity Markets/OFGEM for the UK) requires further investigation. Furthermore, as the earlier discussed example of the oil inflation that induced the monetary policy tightening of 2004–2006 highlights, there is a need to look beyond the traditional risks associated with financial regulation and explore potential energy security and macroeconomic risks related to the functioning of energy markets. Whether this task should fall to overworked financial regulators remains a moot point. This issue requires further investigation however since it represents a potential area where unforeseen risks may arise. For instance, could speculative manipulation of the carbon market lead to a spike in electricity costs with spill-over effects to macroeconomic performance? How would the EU Commission respond in these circumstances without ultimately undermining the carbon market? An

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often cited critique of financial regulation is that it is a patchwork of legislation addressing past crises rather than a forward looking endeavour (Allen 2009). Moreover, how responsibilities between national and supranational bodies break down requires further consideration so as to ensure that an unduly high regulatory burden is not placed on carbon and other energy markets. It will be a challenge to achieve this coherent approach given the array of relevant EU and international initiatives discussed earlier. Finally, though it is highly uncertain what impact these various initiatives will ultimately have on carbon markets one change seems very likely; the new regulatory regime will mean more trading of derivatives (and perhaps the underlying) will occur on organized exchanges. This, all other things being equal, will improve exchange-based liquidity, but also reduce OTC liquidity. These changes may have negative implications for trading costs, the extent of which will not be known until the policy developments are clearer.

References Allen F (2009) Lessons from the crisis. Presentation at the Economics Department, European University Institute, Florence, Italy Babiker MH, Jacoby HD, Reilly JM, Reiner DM (2002) The evolution of a climate regime: Kyoto to Marrakesh and beyond. Environ Sci Policy 5:195–206 Boemare C, Quirion P (2002) Implementing greenhouse gas trading in Europe: lessons from economic literature and international experiences. Ecol Econ 43:213–230 B€ ohringer C, Lange A (2005) On the design of optimal grandfathering schemes for emission allowances. Eur Econ Rev 49:2041–2055 Capoor K, Ambrosi P (2008) State and trends of the carbon market 2008. World Bank Research Report, Washington, DC Coase R (1960) The problem of social cost. J Law Econ 3:1–44 Council Decision 2002/358/EC Official Journal of the European Union 130:1–3, 15/05/2002 Cropper ML, Oates WE (1992) Environmental economics: a survey. J Econ Lit 30:675–740 Dales J (1968) Pollution property and prices: an essay in policy-making and economics. University of Toronto Press, Toronto Daskalakis G, Markellos RN (2008) Are the European carbon markets efficient? Rev Futures Markets 17:103–128 Daskalakis G, Markellos RN (2009) Are electricity risk premia affected by emission allowance prices? Evidence from the EEX, Nord Pool and Powernext. Energy Policy 37:2594–2604 Daskalakis G, Psychoyios D, Markellos RN (2009) Modeling CO2 emission allowance prices and derivatives: evidence from the European trading scheme. J Bank Finance 33:1230–1241 den Elzen MGJ, de Moor APG (2002) Analyzing the Kyoto Protocol under the Marrakesh Accords: economic efficiency and environmental effectiveness. Ecol Econ 43:141–158 Directive 2003/87/EC Official Journal of the European Union, 275:32, 25/10/2003 Directive 2004/101/EC Official Journal of the European Union, 338:18–23, 13/11/2004 Directive 2008/101/EC Official Journal of the European Union, 8:3–21, 13/01/2009 Directive 2009/29/EC Official Journal of the European Union, 140:63–87, 05/06/2009 Doyle E, Hill J, Jack I (2007) Growth in commodity investment: risks and challenges for commodity market participants. FSA Markets Infrastructure Department, Financial Services Authority, London EU Commission (2006a) IP/06/1650 Emissions trading: Commission decides on first set of national allocation plans for the 2008–2012 trading period, Brussels

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EU Commission (2006b) MEMO/06/452 Questions and answers on emissions trading and national allocation plans for 2008 to 2012, Brussels Fezzi C, Bunn D (2007) Structural interactions of European carbon trading and energy prices. J Energy Markets 2:53–69 Fusaro PC (2007) Energy and environmental hedge funds. Commodities Now, September, 1–2 Godal O, Klaasen G (2006) Carbon trading across sources and periods constrained by the Marrakesh Accords. J Environ Econ Manage 51:308–322 Grubb M, Neuhoff K (2006) Allocation and competitiveness in the EU emissions trading scheme: policy overview. Clim Policy 6:7–30 Hanks S (2010) UK and EU regulation of energy derivatives and emission allowance derivatives. Presentation at the Environmental and Energy Finance Group (EEFG) Seminar Series, Norwich Business School, University of East Anglia, UK Hill J, Jennings T, Vanezi E (2008) The emissions trading market: risks and challenges. FSA Commodities Group, Financial Services Authority, London Joskow PL, Schmalensee R, Bailey EM (1998) The market for sulfur dioxide emissions. Am Econ Rev 88:669–685 Kara M, Syri S, Lehtil€a A, Helynen S, Kekkonen V, Ruska M, Forsstr€om J (2008) The impacts of EU CO2 emissions trading on electricity markets and electricity consumers in Finland. Energy Econ 30:193–211 Keats K, Neuhoff K (2005) Allocation of carbon emissions certificates in the power sector: how generators profit from grandfathered rights. Clim Policy 5:61–78 Kling C, Rubin J (1997) Bankable permits for the control of environmental pollution. J Publ Econ 64:101–115 Kossoy A, Ambrosi P (2010) State and trends of the carbon market 2010. World Bank Research Report, Washington, DC Linares P, Santos FJ, Ventosa M, Lapiedra L (2006) Impacts of the European emission trading directive and permit assignment methods on the Spanish electricity sector. Energy J 27:79–98 Montgomery W (1972) Markets in licenses and efficient pollution control programs. J Econ Theory 5:395–418 Nentjes A, Klaasen G (2004) On the quality of compliance mechanisms in the Kyoto Protocol. Energy Policy 32:531–544 Paolella MS, Taschini L (2008) An econometric analysis of emission trading allowances. J Bank Finance 32:2022–2032 Parsons JE, Ellerman AD, Feilhauer S (2009) Designing a US market for CO2. J Appl Corp Finance 21:79–86 Rubin JD (1996) A model of intertemporal emissions trading, banking, and borrowing. J Environ Econ Manage 31:269–286 Schennach SM (2000) The economics of pollution permit banking in the context of Title IV of the 1990 Clean Air Amendments. J Environ Econ Manage 40:189–210 Schleich J, Ehrhart KM, Hoppe C, Seifert S (2006) Banning banking in EU emissions trading? Energy Policy 34:112–120 Schmalensee R, Joskow PL, Ellerman AD, Montero JP, Bailey EM (1998) An interim evaluation of sulfur dioxide emissions trading. J Econ Perspect 12:53–68 Sijm J, Neuhoff K, Chen Y (2006) CO2 cost pass-through and windfall profits in the power sector. Clim Policy 6:47–70 Smale R, Hartley M, Hepburn C, Ward J, Grubb M (2006) The impacts of CO2 emissions trading on firm profits and market prices. Clim Policy 6:29–49 Stavins RN (1998) What can we learn from the grand policy experiment? Lessons from SO2 allowance trading. J Econ Perspect 12:69–88 Stern N (2007) The economics of climate change: the Stern review. Cambridge University Press, Cambridge Svendsen GT, Vesterdal M (2003) How to design greenhouse gas trading in the EU? Energy Policy 31:1531–1539 Vesterdal M, Svendsen GT (2004) How should greenhouse gas permits be allocated in the EU? Energy Policy 32:961–968

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Part II

Prices

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Chapter 5

Market Perfection in a Changing Energy Environment Andre´ Dorsman, Kees van Montfort, and Paul Pottuijt

Abstract During the last decade of the twentieth century energy markets changed rapidly. National orientated electricity networks were more and more linked to each other. A large step was the coupling of the spot markets of Belgium, France and The Netherlands in 2006. The integration of markets is a continuing process with realization in 2010 of a market coupling between Central Western European region (CWE, consisting of Belgium, Germany, France, Luxemburg and Netherlands) and the Nordic region. In 2011 the United Kingdom will also be part of an enlarged area where market coupling is applied, expected to be followed by further extensions of the region with Southern- and/or Eastern European markets. This chapter deals with the imperfections of the electricity spot markets. We will focus on the (capacity of) interconnectors between national grids in Europe. The relevant question is: are connectors a limiting factor in the priceforming process on electricity day ahead markets. Keywords Electricity market
Explicit auction
Interconnectors
Perfect markets

auction




Implicit

A. Dorsman (*) VU University Amsterdam, Amsterdam, The Netherlands e-mail: [email protected] K. van Montfort VU University Amsterdam, Amsterdam, The Netherlands Nyenrode Business Universiteit, Breukelen, The Netherlands P. Pottuijt GEN Nederland, Utrecht, The Netherlands A. Dorsman et al. (eds.), Financial Aspects in Energy, DOI 10.1007/978-3-642-19709-3_5, # Springer-Verlag Berlin Heidelberg 2011

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Introduction

In an efficient market, prices absorb new relevant information directly and correctly and in a perfect market demand and supply can come to the market without any hurdles, such as constraints hindering supply (transfer capacity limitations), transparency issues, and the implications of “outages” and unequally distributed information. But markets are neither efficient nor perfect. However, a reduction of imperfections in number or magnitude can attribute to a decrease of inefficiencies in the market in number or magnitude. During the last decade of the twentieth century energy markets changed rapidly. Traditionally, nationally orientated nonliberalized electricity networks were liberalized and more and more linked to each other. Integration of markets means reduction of barriers. Electricity is a physical good. Before the liberalization of the markets the electricity networks, the grids, were nationally organized and the limited number of interconnectors was mainly used as an emergency facility for extreme situations. An interconnector is the electricity link between two grids. This relates to the fact that the demand and supply on the grid have to be equal. The TSO (Transmission System Operator) is responsible to have the demand and supply in balance. In case this balance threats were broken, and the concerning TSO did not have sufficient measures to prevent balancing issues, interconnectors were used to adjust the demand or the supply. In such situation of emergency the TSO of a grid (country) could ask for assistance from other TSOs by using interconnectors for transporting electricity from one grid to another. The role of the interconnectors has been changed. In addition to their security roles, nowadays they are also a part of the different energy trading schemes in the liberalized European energy market. Market participants can buy capacity of the interconnectors. The TSOs have to ensure that this does not negatively influence too much their duty to keep the grid in balance. On the other hand, by using the interconnectors not only as a buffer for extreme situations, but also as an integrated part of the network of grids, market imperfection is reduced. Moreover, it deduces the capacities of the TSOs to keep their systems in balance and fine-tuning, if necessary. TSOs are reducing the limiting factor of the interconnectors by (1) creating new links (interconnectors) between the grids (see for example, Andeweg et al. 2009) and (2) increasing the efficient usage of the existing links between the grids (e.g. replacing explicit auctioning schemata by implicit auctioning schemata. See the next section for this issue). In case the capacity of an interconnector is not fully used, the interconnector is not an imperfection and the electricity prices of the two grids will not differ substantially. However, when the capacity of the interconnector will be fully used it is understandable that the prices of the two grids can deviate. Although the linking of grids is a very important issue for practitioners, we are not aware of publications in the (academic) literature. This study, therefore, fills a gap between theory and practice.

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This chapter deals with the imperfections of the electricity spot markets caused by the limited capacity of the interconnectors. In the past, natural organized electricity networks were only linked with interconnectors with limited capacity. Recently, the capacity of the interconnectors increased and the limitations of a free flow between the electricity networks diminished, but did not disappear yet. Following this introduction, Sect. 5.2 contains a description of the market of interconnectors. Section 5.3 of this chapter contains a description of the data and Sect. 5.4 presents the empirical results of our research. The final section, Sect. 5.5, summarizes and concludes.

5.2

Interconnectors

As has already been said, in the past the capacity of interconnectors was limited. Therefore, prices on the grids can differ. Reducing the limiting factor implies the reduction of an imperfection and may lead to a more efficient price forming of electricity. Market participants could buy capacity of an interconnector by an explicit auction. In the case of an explicit option the TSO offers the capacity and market participants can buy the offered capacity. The buyers had the right, but not the obligation to use the bought capacity. In fact, they are buying options. The maturity of these options can differ. On the explicit market options with different maturity are offered, for example, monthly options or yearly options.

5.2.1

Explicit Auction

When a market participant wants to use his option right, he has to inform the TSO one day earlier. Daily, the TSOs determine and publish the available capacity of the interconnectors on the day ahead. A disadvantage of the explicit auction is that individual market participants are buying options on the capacity of the interconnectors. The TSO has merely written the option and has only influence on the moment of exercising the option rights via nomination deadlines. The buyer will use his option right at hand and at the moment that it is most valuable for him. This moment may be dissimilar with the most valuable moment for the market. For example, a power company in The Netherlands has clients in Germany. The power company has bought on the explicit market options on the connector between The Netherlands and Germany. Although at a certain moment the electricity price in The Netherlands is higher than in Germany, it can be in the interest of the power company to use its options rights on the capacity of the interconnector to service his clients in Germany. In this case the power company uses the interconnector capacity in the opposite of the price signal. This is of his own interest but certainly not in the interest of social economic welfare increase, since the concerning usage

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of the interconnection capacity limits possibilities for energy flows from a low price area to a high price area.

5.2.2

Implicit Market

An alternative to the above-mentioned example, in which an explicit auctioning mechanism produces suboptimal outcomes, is the implicit market. On the implicit market the TSOs do not offer the capacity to individual market participants, but put it at the disposal of linking international day-ahead energy markets. This means that no individual participant’s options are created as in the explicit auction. The TSO offers interconnector capacity to the trading zones participating in an implicit market coupling scheme (and not to individual market participants). An implicit market coupling scheme basically consists of the following steps: • Participating TSOs in the implicit market coupling scheme determine the available interconnector capacity between the participating trading zones in the implicit market coupling scheme. • The TSOs publish on a daily basis the available capacity of the interconnector the next day (day ahead). As such that marker participants (traders, producers, etc.) can determine the energy flows that could be possible between the trading zones. • Based on available interconnection capacities between trading regions in an explicit market coupling and based on other relevant trading factors/ expectations (such as weather), the market parties bring their bids and offers to the Power Exchanges. • Based on Power Exchange order books and available interconnector capacities a market coupling algorithm calculates the optimal matching of orders at the Power Exchanges and it also calculates how the available interconnector capacity has to be used to reach this optimal situation. The goal function of the concerning algorithm is optimal social economic welfare for the entire region of the implicit market coupling scheme. Given that the outcome of an implicit market coupling comprises the local prices of the involved trading zones, the corresponding matches offers of participants at the Power Exchanges and the flows over the interconnectors. One of the outcomes of the implicit market coupling algorithm is that flows from one trading zone to another always follow the price signal. This is an important advantage compared to the example for the explicit auction, in which it was demonstrated that electricity flows could be scheduled against the price signal, leading to lower social economic welfare then could be possible in the concerning trading region. Under implicit market coupling, the TSO in the low price area buys electricity at the local Power Exchange and sells it to the TSO in the high price area. This TSO sells its bought electricity at the Power Exchange in the high price area.

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The involved TSOs do not bear a price risk, because the TSO of the other country has the obligation to take over the electricity and sell it on the home market. In case the outcome of the market coupling is that prices are the same on both markets, the involved TSOs on one border together buy/sell the flows calculated by the market coupling algorithm at their local Power Exchange. Moreover, there is no price risk in this case. For both cases the TSOs together do not have a trading position in the electricity market. For the purpose of implicit auctioning, they just clear the required positions at local Power Exchanges and facilitate the calculated flows between trading regions. Suppose: the price on market A is lower than that on market B. The demand on market A will increase and the supply on market B will increase as well. The result of the implicit auction is that the price on market A will increase and on market B will decrease. This process of price convergence goes on till the prices on both markets are the same or to the moment the capacity of the interconnectors has fully used. We show this effect in Fig. 5.1a–c. In Fig. 5.1a we have two isolated markets; namely, A and B. There are no export and import capacities. The lack of such capacities is an imperfection. Market coupling means a reduction of this imperfection. If the reduction of this imperfection is small, the price gap between A and B will reduce, but not disappear (Fig. 5.1b). If the reduction of the barrier between the two countries is larger, Fig 5.1c, the price gap between A and B becomes smaller. As long as there is a (limiting) barrier between the two countries, a price gap between the two countries will exist. In case there is no limiting capacity (i.e. no imperfection) at the border, the prices in country A and country B will always be equal under an implicit market coupling scheme. Normally, the electricity demand shows a development during daytime. The demand will be higher during peak hours than during off-peak hours. The supply will be less volatile, resulting in higher prices during peak hours than during nonpeak hours. If in a certain hour the demand is high, it is highly probable that the capacity of the interconnector is fully used, resulting in a price difference between the two countries. Additionally, when the demand is low, it is less probable that the interconnector is a limiting factor. In other words, during peak hours the interconnector can be fully used and a price difference between A and B is possible, while during off-peak hours the prices in the countries A and B will be more equal. In Sect. 5.4 we will look at the capacities of the interconnectors. Until November 2006 there were no implicit auctions. With the start of the coupling of the markets of Belgium, France and The Netherlands implicit auction have been introduced in Europe. However, that does not mean that explicit auctions disappeared. In The Netherlands monthly and yearly capacity of the interconnectors are still sold by explicit auction. Only on the daily market (dayahead market) implicit auction is used. The TSOs determine the free capacity for the day-ahead implicit auctioning, among others, based on nominations by buyers of options on the explicit auctions that have to inform the TSO on day D-1, how they want to use their obtained explicit auction rights for the yearly and monthly capacity on day D.

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Fig. 5.1 Price development in isolated markets A and B (a) without export and import capacities, (b) with small export and import capacities, and (c) with larger export and import capacities

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The limited capacities of the interconnectors are a main imperfection. Many new links have been created and capacities increased on existing links to reduce this imperfection. One of these new links is the cable (NorNed) between Norwegian and the Dutch grids (May 6, 2008). In Norway, hydropower-generated electricity is easier to store and, thus, linking the Norwegian and the Dutch grids will have an equalizing influence on the price of electricity in The Netherlands. However, the flow will not only go from Norway to the Netherlands, but also the other way around. In the Netherlands generating electricity is mainly done by coal and gas fired plants. These plants are industrial CHPs (Combined Heat Power), which are often required to run during the night because it is economically inefficient to fully switch off the plant (in case of large coal plants) and because of the demand of heat. These methods of producing electricity in the Netherlands are not only (relatively) expensive, but also lead to a high price difference between day time (peak) when demand is high and night time (offpeak) when demand is low, which leads to a relatively overproduction. It is therefore possible that during off-peak the flow goes from the Netherlands to Norway. By doing this, the limited capacity of hydropower can be saved such as during night times and hence its flexible nature can be more efficiently used when it is needed at peak moments on day-time. Not only capacity can be an imperfection, but also transparency. The European Network of Transmission System operators (ETSO (2008) produced a report, titled Legal survey on transparency. The report gives an overview of the transparency of the TSOs in most of the European countries and contains information on system loads, network investment and planning, capacity calculation, capacity forecast, network operation, capacity auction, generation and balancing. The general conclusion of this report is that the transparency of TSOs is not bad, but can be improved. An important remark in the report is that week-ahead forecasts (on system load) are in most cases considered irrelevant for the market. The electricity market is a physical market and such a market can be confronted with outages. Outages can be a problem for market participants and cause market imperfections. Outages can be either planned, such as for regular (scheduled) maintenance, or unplanned in the case they occur due to unplanned/unexpected circumstances. Examples of an unplanned outage are failure of production facility which forces the facility to be taken out for maintenance/reparation of the issue. These types of unplanned outages are also referred to as forced outages. We assume that forced outages will have more influence on the market than planned ones. However, the number of forced outages is much smaller than planned outages. Therefore, we will concentrate our study on planned outages that are related to the interconnectors. Planned outages have the advantage that it is known upfront when the outage will start and more or less how long it will take place. The supplier plans it and it is important that the market will be informed in time. It is understandable that outages due to maintenance will take place in offpeak periods. The price on electricity markets now shows a seasonal effect. During wintertime and (especially in the USA) during summertime the electricity price will

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be higher than in other periods of the year. Therefore, we assume that the planned outages are not equally distributed over the year.

5.3

Data

The website http://www.etsovista.org contains data regarding network capacity, congestion management and outages related to interconnectors for 26 European countries. The main disadvantage is that the databases start on May 11, 2008 (network flows) or April 25, 2008 (outages). Given that the observed period is too short to show a tendency in the development, we are only able to give an overview of the status quo. The website of ETSOvista, among others, produces information on Available Transfer Capacities (ATCs) for day-ahead markets. These data are the capacity of the interconnectors subtracted with the nominated options from the explicit markets. There are 12 European countries with implicit auctions. The data of Norway are divided into North Norway, Middle Norway and South Norway and the data of Denmark are segregated as Denmark East and Denmark West. However, most data of the implicit auctions are not available. Data of the implicit auction can be found for Belgium (France and The Netherlands), Czech Republic (Slovakia), France (Belgium and The Netherlands), The Netherlands (Belgium and France), Portugal (Spain), Slovakia (Czech Republic) and Spain (Portugal). Note that there is no information available for the largest country in the midst of Europe, which is Germany. As mentioned above, Norway does not have one national grid, but three grids. These grids are also linked with interconnection lines. Interconnectors are links between the grids of two different counties, while interconnection lines are links between grids within one country. The reason to have three different grids in Norway is a physical one. The country is relatively long and small, moreover it is not flat. Having more than one grid makes it easier to manage the electricity network. Germany has also three grids. However, in this case the interconnection lines are not the limiting factors and Germany is therefore considered as one trading region for the coming CWE (Central Western European) implicit market coupling between Germany, France, Belgium, The Netherlands and Luxembourg. From this perspective it seems that Germany has one national grid, but in operational practice the grid is divided into more than one owner. In other words, the German internal connection lines are no barriers in Germany and there is no market imperfection for CWE Market Coupling. Market coupling wants to reach the same situation for Europe, or at least tries to reduce the market imperfections. The end goal of CWE MC (Central Western European Market Coupling) is to realize a so-called flow-based market coupling (FB MC). Under such market coupling all relevant branches in a grid (also country internal ones) are taken into account on interacting basis for market coupling calculations. Since FB MC can not be introduced from the start of CWE MC, the CWE MC will start as ATC MC.

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Although there is no information about the implicit auction on the Scandinavian countries available on the website of ETSOvista, we can find on the website of Nord Pool data of Elspot, the day-ahead market of Nord Pool.1 However, during the period observed the Bid Area configuration in Nord Pool Spot’s Implicit Auction DA (Day-ahead) Spot Market is based on dynamic areas (i.e. interchangeable over time by TSOs) and in the period June 1, 2009 till June 1, 2010 there have been four area configuration changes, which also means that many of the “interconnectors” linkages between areas are different for each setup. Additionally, we received from Elspot the System Price, which is the underlying reference price for the Nordic electricity derivatives. It is reflecting the equilibrium between all buy and sell bids in the Nordic Spot Market Bid Areas when not considering capacity constraints, i.e. it is what one could call the “unconstrained” Nordic equilibrium price that shows the level the market would have cleared at in case the transport capacity in the grid system had been unlimited. This information was received from the department Power Data Services of Nord Pool. As already said, most data of the implicit auctions are not available on the website http://www.etsovista.org. However, the website of Nord Pool, www. nordpoolspot.com, contains information about capacity and volume of the interconnectors and internal connection lines of the North European countries.

5.4

Empirical Results

In this section we will look at the implicit market data and the outage data. However, we will start by giving a first impression of the net transfer capacities of four large European countries, i.e. Germany, France, the UK and Spain (see Table 5.1). The net transfers from and to Germany are large. The import minus the export is 4,210 (¼11,500  7,290) MW per hour (i.e. positive). The net transfers from and to France are also large. The import minus the export is 3,070 (¼ (9,280  12,350) MW per hour (i.e. negative). The net transfers from and to the United Kingdom, and from and to Spain are relatively small. The imports minus the exports are 0 (¼2,000  2,000) and 100 (¼1,700  1,600) MW per hour respectively. Table 5.2 presents information on the capacity of interconnectors (Belgium/ France; Belgium/Netherlands; Czech Republic/Slovakia; Portugal/Spain) per hour of the day during the period June 1, 2009, till June 1, 2010: the fraction of days with fully used capacity of the interconnectors. Blanks correspond to 0%. 1

The authors are grateful to Mr. Rickard Nilsson, manager Power Data Services, Nord Pool Spot, for his extensive advise and support received for writing sections concerning Nord Pool Spot markets.

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Table 5.1 Net transfer capacity (average over 1 h; period April 2008 – March 2010; expressed in terms of MW) (with Germ Germany, FR France; UK United Kingdom, Sp Spain, CH Switzerland, DK Denmark, NL The Netherlands, CZ Czech Republic/Slovakia, BE Belgium, It Italy, Port Portugal) From To Germ Ger. xxx Fr 2,300 UK Sp CH 4,000 DK 1,500 NL 2,550 CZ 1,150 BE It Port Total 11,500

Fr UK 2,420 xxx 2,000 2,000 xxx 600 1,900

Sp

CH DK NL CZ BE It. 870 950 2,450 600 700 3,200 3,100 1,050 xxx

Total 7,290 12,350 2,000 1,000 1,600 Port.

xxx xxx xxx xxx

1,200 1,160 1,000 9,280 2,000 1,700

xxx xxx xxx xxx

Table 5.2 The percentages that the capacities of the interconnectors are fully used on a specific hour of the day (B Belgium, F France, N The Netherlands, C Czech Republic, S Slovakia, P Portugal, S Spain) Hours B¼>F F¼>B B¼>N N¼>B C¼>S S¼>C P¼>S S¼>P 0–1 23 4 11 4 12 1–2 26 5 12 5 10 2–3 22 5 11 3 19 3–4 20 4 9 5 18 4–5 16 5 9 4 20 5–6 21 6 9 3 15 6–7 17 5 10 5 8 7–8 27 8 10 7 2 8–9 30 5 10 5 3 9–10 38 6 10 7 8 10–11 47 6 10 6 6 11–12 43 6 10 3 6 12–13 46 4 9 3 15 13–14 44 4 11 4 15 14–15 46 5 10 3 27 15–16 35 4 10 4 27 16–17 37 4 10 2 27 17–18 20 4 10 3 25 18–19 35 5 10 3 24 19–20 40 4 10 4 13 20–21 44 5 10 3 13 21–22 40 6 10 5 10 22–23 38 7 10 4 9 23–24 38 5 11 5 15

5 Market Perfection in a Changing Energy Environment Table 5.3 Outages: planned versus forced

Forced Planned Total

Frequency 18 353 371

81

Percentage 4.9 95.1 100

The interconnector between Belgium and France is the same between France and Belgium. The flow goes from one side to another or the other way around. The interconnectors between France and Belgium (F¼>B), Czech Republic and Slovakia (C¼>S) and “vice versa” (S¼>C) are never fully used. That means that these interconnectors are no barriers, however, which is not true for the other interconnectors. Especially the interconnector between Belgium and France is fully used many times during both peak hours and off-peak hours. The Bid Area configuration in Nord Pool Spot’s Implicit Auction DA Spot Market is based on dynamic areas (i.e. interchangeable over time by TSOs). In the previous 2 years there have been four area configuration changes, which also mean that many of the “interconnectors” applied and linkages between areas are different for each setup. Apart from this, in the past 15 years the frequency of the System Price being equal to all Nordic Area Prices on a yearly (calendar) basis has varied between close to 60% and 1 year below 10% and with an average of around 30–35%.2 We also analyzed a dataset with the records of planned and forced outages in several European countries over the period April 25, 2008 – April 24, 2010. In Table 5.3 we give for all the 26 countries an overview of the outages, divided between forced and planned outages. We found 371 outages, most of which 353 (95%) were planned. Outages can differ in duration and time. Table 5.4 reports the duration of the outages. The first column indicates the duration of the outages expressed in terms of days. For instance, value 3 indicates a duration between 2.5 and 3.5 days. Table 5.4 shows that the durations of most of the outages (52.8%) are shorter than one and a half day. Only 5.1% of the outages (19 observations) had duration of more than 21 weeks. In Appendix we divided the observations into planned and forced outages. Most of the forced outages (16 of 18) were solved during one and a half day, one forced outage between 1.5 and 2.5 days and one observation more than 3 weeks. The durations of the planned outages are longer than the forced outages. Figure 5.2 gives the planned outages (in days) distributed over the several months of the year. The outages are mostly planned and take place in the fall (September, October and November). During the winter months, which are December, January and February, the outages are minimal. This is in line with the idea that the decision makers realize the planned outages in the period of the year when the demand is limited. 2

Source: the department Power Data Services of Nord Pool Spot, Bromma, Norway).

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Table 5.4 The duration of the outages (in terms of days)

Duration 0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 13.0 14.0 16.0 17.0 18.0 19.0 20.0 21.00 More than 3 weeks Total

Frequency 151 45 15 18 48 12 18 3 3 5 5 6 4 2 2 1 7 2 4 1 19 371

Percent 40.7 12.1 4.0 4.9 12.9 3.2 4.9 0.8 0.8 1.3 1.3 1.6 1.1 0.5 0.5 0.3 1.9 0.5 1.1 0.3 5.1 100.0

300

Number of outages

250 200 150 100 50 0 0

2

4

6 8 Months of the year

10

Fig. 5.2 The number of outages (in days) distributed over the months of the year

12

5 Market Perfection in a Changing Energy Environment

5.5

83

Summary and Conclusions

The electricity markets are changing rapidly, from national orientated markets to a global market. The interconnectors between the grids may become limiting elements. If so, then it is a market imperfection. Market imperfections can cause deviations from an efficient price development. In Europe the number of interconnectors has increased and also capacities on existing interconnectors have increased. These increases in interconnector capacities contribute to a removal of price differences between trading zones. TSOs sell the capacity of interconnectors partly by implicit auctions. If the capacity is not fully used there is no reason for a price difference between the grids. On the other hand, if the capacity of the interconnector is fully used – in other words the interconnector is a limiting factor – the prices of the grids can deviate. In this chapter we looked into the European interconnectors where the capacity is partly sold by implicit auction. For some connectors we did not find a moment that the interconnectors had been fully used. So, these interconnectors (Czech Republic ¼> Slovakia; Slovakia ¼> Czech Republic; and France ¼> Belgium) are not limiting factors and do not cause market imperfection. In the other cases (Belgium ¼> France; Belgium ¼> The Netherlands; The Netherlands ¼> Belgium; Portugal ¼> Spain; and Spain ¼> Portugal) the capacity is sometimes fully used and it is possible that the electricity prices of the interconnected grids differ. It is remarkable when the capacity is fully used by these interconnectors that the moments are not concentrated on the peak hours, but also during off-peak hours. We assumed that during moments when electricity demand is high (the peak hours), the probability that the capacity of an interconnector was fully used is higher than during off-peak hours. The observed period is however very limited. We, therefore, cannot make strong statements. Another issue in this chapter is the outages. We looked at the outages over a period of 2 whole years, April 25, 2008 till April 24, 2010. The outages are mostly very limited in time; the duration is often smaller than 1.5 days (52.8%). Most of the outages are planned and concentrated in the fall. Decision makers avoid outages in winter time and thus it seems that outages do not cause market imperfection. Our study was limited with the data. The website of ETSOvista started in the spring of 2008 with data of network flows and outages. Enlargement of the dataset shall attribute to a better knowledge of the interconnectors as a limiting factor in the price forming process of electricity.

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Appendix: Outages: Planned/Forced Outages and Durations Natures Duration 0 1.0 2.0 3.0 4.0 5.0 6.0 7.0 8.0 9.0 10.0 11.0 13.0 14.0 16.0 17.0 18.0 19.0 20.0 21.0 >21.0 Total

Forced 16 1 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 1 18

Planned 135 44 15 18 48 12 18 3 3 5 5 6 4 2 2 1 7 2 4 1 18 353

Total 151 45 15 18 48 12 18 3 3 5 5 6 4 2 2 1 7 2 4 1 19 371

References Andeweg H, Dorsman AB, van Montfort K (2009) Electricity traffic over the barriers of networks: the case of Germany and the Netherlands. Front Financ Econ 6(2):120–139 ETSO (2008) Legal survey on transparency. Research report

Chapter 6

The Price Forming Process in Energy Markets Don Bredin and Cal Muckley

Abstract In this chapter we examine the price formation process in European energy markets during the period 2005–2009. In order to assess the development of these markets, we identify potential theoretical relations related in the price formation process, using a set of factors including energy prices and European Union allowance prices as well as controlling for important influences such as economic growth. In terms of our methodology, we adopt both static and recursive versions of the Johansen (J Econ Dyn Control 12:231–254, 1988) multivariate cointegration likelihood ratio test, as well as a variation on this test in order to control for time varying volatility effects, to estimate these potential theoretical relations. The findings are indicative of a new pricing regime emerging since January 2008 which empirically interlinks the coal, gas and oil markets with European Union allowance futures contracts. It would appear that European Union allowance contract prices play an integral role in the price formation process in European energy markets. Keywords Energy prices
EUA competitiveness
EUA prices

6.1

Introduction

In this chapter we examine the price formation process in European energy markets during the period 2005–2009. The price formation process has altered markedly in recent decades, spurred on by the growth in world energy prices, the insecurity of the provision of energy and the implications of climate change for these energy markets (Helm 2007). Against this background, with a view to enhancing competitiveness, European energy markets, although not yet fully integrated, have developed to exhibit strong bilateral connections between the national energy markets. D. Bredin • C. Muckley (*) School of Business, University College Dublin, Blackrock, Dublin, Ireland e-mail: [email protected]; [email protected] A. Dorsman et al. (eds.), Financial Aspects in Energy, DOI 10.1007/978-3-642-19709-3_6, # Springer-Verlag Berlin Heidelberg 2011

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In addition, a quintessential feature of the development of these energy markets since 2005 is the emergence of the European Union’s Emissions Trading Scheme (ETS), which provides a price for carbon emissions. In order to assess the development of these markets, we identify potential theoretical long-run relations related to the price formation process, in a set of factors including energy prices, European Union allowance prices as well as important influences such as economic growth and weather conditions. With regard to our methodology, we adopt both static and recursive versions of the Johansen multivariate cointegration likelihood ratio test, as well as a variation on this test in order to control for time varying volatility effects, to estimate these potential theoretical relations and document their evolution over time. In this chapter, we also adopt a number of identifying restrictions to further refine our model. In addition, we carry out sensitivity tests which take account of time varying volatility and the structural breaks in the data. Our analysis of price formation in the European energy markets draws on recent studies examining the empirical relationship between the EU allowance (EUA) prices and its fundamentals. An important theoretical review of the material is included in Springer (2003), while Christiansen et al. (2005), Redmond and Convery (2006), Mansanet-Bataller et al. (2007), Alberola et al. (2008a, b) and Bredin and Muckley (2011) identify the key drivers of EUA prices as economic growth, energy prices and weather conditions. As has been highlighted by a number of theoretical studies, energy prices are highly influential determinants of CO2 prices1 (see Burniaux (2000), Ciorba et al. (2001), Sijm et al. (2000) and van der Mensbrugghe (1998)). Specifically, a rise in oil prices is, ceteris paribus, indicative of a strengthening of demand for oil and hence a corresponding strengthening of demand for European Union allowances. Naturally, the price of CO2 may also be expected to influence the energy prices. In particular, a rise in the price of CO2 (however determined) will, ceteris paribus, diminish the demand for fossil fuels. Nonetheless, we expect, in net terms, to see a positive relation between EUA prices and oil prices whereby the influence of oil prices on EUA prices exceeds the impact of EUA prices on oil prices. Studies that have included energy variables include Redmond and Convery (2006), MansanetBataller et al. (2007), Alberola et al. (2008a) and Bredin and Muckley (2010). In this study, our proxy for energy prices is the brent crude futures oil price and we would expect a positive relationship between oil price movements and the EUA price. In order to take account of the abatement options for large installations and the impact of relative fuel prices and consistent with Alberola et al. (2008a) we also include two specific spread terms, clean dark and spark spreads. The clean dark (spark) spread represents the difference between the price of electricity and the price of coal (gas) used to generate that electricity, corrected for the energy output of the coal (gas) plant. Hence, both coal and gas prices are also implicitly included in our analysis. A negative relation between the EUA price and clean spark spreads (CSS) is expected to arise as greater profitability from generating electricity from natural gas, ceteris

1

See the Appendix for a description of CO2 prices i.e. EUA prices.

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paribus, would result in switching to natural gas fueled electricity generation and hence a short run abatement with respect to CO2 emissions. EUA prices are likely to decline following the fall in demand. Similarly, the opposite relation is expected to hold between the EUAs and clean dark spreads (CDS). Along with energy prices, weather conditions are considered a theoretically important variable in determining the price of carbon. Studies that have incorporated weather conditions in explaining movements in the price of carbon include Redmond and Convery (2006), Mansanet-Bataller et al. (2007) and Alberola et al. (2008a) and Bredin and Muckley (2010). In addition, while Considine (2000) and Davis et al. (2002) document the significant impact of temperature on the intensity of carbon emissions in the United States, Ciorba et al. (2001) highlight temperature as being one the most influential factors in determining the CO2 price. As weather effects may influence the price of carbon, it is evident that they may also, albeit indirectly, influence energy prices. In all cases the authors take account of temperature extremes and the likely effects with some evidence to suggest the importance empirically of these variables. Redmond and Convery (2006) find no evidence of a statistically significant weather effect, while Alberola et al. (2008a) do find evidence but only for certain sub-samples of Phase 1 of the European Union’s ETS. Christiansen et al. (2005) has highlighted the role of economic growth as an important determinant of the EUA price, with higher economic growth leading to a rise in the EUA price. As a result, it is clear that while economic growth is expected to exert a direct positive impact on energy prices, it is also expected to influence energy prices indirectly through the EUA price. We include two proxy explanatory variables, industrial production and equity price movements. While industrial production would be a standard measure of economic growth, a potential difficulty here is that it is only available at a monthly frequency. A solution which we adopt here is to interpolate the data using a piecewise cubic spline methodology. A euro zone equity (futures) index is also considered as a measure of economic conditions. The motivation for including this variable is that it offers an up-to-date indicator of expectations on both financial and economic conditions at the required daily frequency. Further, given the financial nature of the underlying asset, we consider including such a proxy informative. Given the relative paucity of data available and consistent with the previous literature, our analysis will adopt daily data. The full sample of data covers the period 1st July 2005 to 14th December 2009. The expiration on our futures contracts is December 2008 and December 2009. Unlike the vast majority of the previous studies, our focus will be on futures rather than spot contracts. The justification for examining futures is due to the greater volumes being traded on these contracts in regard to European Union Allowances (see Mansanet-Bataller and Pardo 2008).2 These instruments were not exposed to the dramatic structural 2

Mansanet-Bataller and Pardo (2008) report cumulative volumes traded in the different European Carbon markets since the start of the trade in each market until January 2008. The volumes traded in spot is 4%, futures 76% and over the counter (OTC) 20%.

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breaks that have been previously highlighted in the literature and so results in an additional advantage of adopting the futures based analysis. The specific contribution of this chapter to the empirical literature on modeling the energy markets in Europe is threefold. Our study is the first known study to present findings concerning the long-run relationship between the European energy markets and EU carbon allowances while controlling for economic growth and weather conditions using a battery of statistical cointegration testing procedures.3 Cointegration is a powerful econometric approach which can indicate whether a stable relationship exists and whether the behaviour of the variables binding this relationship are consistent with economic theory. Secondly, besides taking account of the potential cointegrating relations, we also address the empirical finding of time varying volatility in the European energy markets, the EU carbon allowances, economic growth and weather conditions and extend the cointegration tests by including time varying volatility. Finally, given the relatively small sample of data and the considerable uncertainty, in particular during the 2005–2007 period, we examine the extent of the evolving long-run relationships adopting a recursive cointegration approach. The remainder of this chapter is structured as follows, Sect. 6.2 discusses the European energy markets, climate change and the price of carbon. Section 6.3 describes the methodologies being adopted, while Sect. 6.4 presents the data and empirical results. Finally, concluding remarks are presented in Sect. 6.5.

6.2

European Energy Markets

On the whole, the European energy markets are characterised by pronounced segmentation along national lines as well as a heavy reliance on the importation of fossil fuels. In fact, the significant consumption of fossil fuels: coal, oil and especially natural gas, as well as the European Union’s reliance on the importation of these fuels is expected to grow markedly by 2020 (Kavalov and Peteves 2007). As a result of new energy conversion technologies the coal, oil and natural gas markets are becoming increasingly interdependent; ultimately it is anticipated that these fossil fuels will comprise an effective single market for hydrocarbons.4 As per the extant system of segmented national energy markets, interlinked by a battery of bilateral arrangements, this prospective European market for hydrocarbons will be 3 In this chapter we extend the contribution of Bredin and Muckley (2010) by taking price formation in the European energy markets as our focus. In particular, in this chapter we present new findings with regard to the energy equations in the cointegration relation, thus shedding light on the interactions between the energy and carbon credit prices while controlling for economic growth and weather effects. In addition, we present extensive robustness tests concerning our findings. Finally, in this chapter we provide a discussion related to the European energy markets, carbon credit prices and climate change as well as descriptions of the econometric methodologies adopted. 4 Organic compounds containing only carbon and hydrogen.

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beset by security of supply, competitiveness and climate change challenges. Indeed, an integrated European energy market is necessary to adequately address these fundamentally important international challenges to provide sustainable, competitive and secure energy within the European Union (Helm 2007). In this section, we discuss the nature of the aforesaid fossil fuels, the policy in the EU with regard to climate change and, in particular, we briefly discuss the recent innovation of EU allowances.

6.2.1

Coal

Coal is a sedimentary rock. As it is readily combustible, it is extracted from the ground to be exploited as a fossil fuel. According to Kavalov and Peteves (2007), in the EU-25 member states in 2004, in excess of 30% of the total power generated is sourced in coal. Albeit, this arithmetic average measurement is continuously declining and it varies considerably across member states: from Poland where more than 90% of power is generated by coal to France where coal is relied upon to generate less than 5% of its total energy output. During recent decades in Europe, both hard coal (anthracite coal) and lignite coal (a soft brown coal of relatively recent origin) have been successfully extracted, although today there is virtually no hard coal remaining that it is economically viable to extract – ongoing European hard coal extraction avails of significant financial subsidies. In contrast, Kavalov and Peteves (2007) indicate that lignite coal is an economically viable source of coal in Europe, that said, reserves of lignite coal to productivity ratios are quite low (e.g. there remains an estimated 33 years of reserves in Germany and 54 years of reserves in Greece). Nonetheless, in 2003, approximately 65% of the EU-25 member states coal consumption was sourced indigenously, revealing a long-term strategic vulnerability with regard to the provision of coal. Notwithstanding the concurrent decline in the importance of coal in Europe, coal enjoys two main advantages over oil and natural gas from a European perspective. First, the availability of coal has a wide, and relatively reliable, geopolitical distribution (Australia, China, India, Russia, South Africa and the USA) and secondly it exhibits a higher global reserves to production ratio (albeit a rapidly declining ratio from 277 to 155 years between 2000 and 2005 alongside unanticipated strong growth in global productivity). These advantages mitigate for legitimate concerns about the security, reliability and affordability of economically viable coal deposits in the European Union. In addition, there are new environmentally motivated technologies for coal utilisation or so-called Clean Coal Technologies (CO2 capture, transport and storage). Nevertheless, the centrally important disadvantage of coal remains that it is the most carbon-intensive fossil fuel, hence its future depends heavily on prospective green house gas reduction policies. Furthermore, it is well known that coal fired plants require higher investment costs than, for example, natural gas fired plants.

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In this chapter, the coal prices adopted are CIF (cost, insurance and freight) ARA (Amsterdam–Rotterdam–Antwerp) month ahead forward contracts, denominated in € per MWh. Our focus is therefore on imported hard coal used to generate electricity and heat (other applications include agriculture, cement, residential and metallurgy). This avoids subsidised indigenously mined hard coal prices which are two to three times higher than the imported hard coal prices (Kavalov and Peteves (2007). In fact, in this chapter we do not examine these market determined prices directly but rather we examine a clean dark spread, CDSt which is, as per convention, the discrepancy between the price of electricity and the price of coal:
 1 þ pCO2  FECoal CDSt ¼ pElecbase  pCoal  rCoal

(6.1)

The clean dark spread at time t, CDSt, is defined as equal to the price of electricity Powernext Futures Month Ahead Peak in € per MWh, pElecbase together with certain adjustments for the price of coal, pCoal. Specifically, the price of coal pCoal is the CIF ARA Month Ahead in € per MWh and rCoal is the net thermal efficiency of a conventional coal fired plant (40%). In addition, the price of carbon pCO2 is sourced at Bluenext and denominated in euro. Finally FECoal is the CO2 emission factor of a conventional coal-fired plant in tCO2/MWh. Further details are available in the Appendix.

6.2.2

Oil

Fuel oil is a liquid or liquifiable petroleum product that is used to generate heat or power. It is the world’s primary source of energy and oil demand globally. In the future, global demand for oil is expected to grow by approximately 1% per year. As a result, the European Commission indicates its expectation of high oil prices which are likely to prevail in the medium to long term. This further motivates the ongoing movement towards a low-carbon and high energy efficient European economy. Specifically, in the EU-27, oil is of first order importance for the generation of electricity (International Energy Association Energy Statistics 2007). The EU is a net importer of crude oil, mainly from the Middle East, the Russian Federation and Norway (Eurostat 2008), thus implying a certain strategic vulnerability with regard to the provision of oil to Europe. EU members are required to maintain stocks of petroleum products at least equal to 90 days of the anticipated internal consumption (average daily consumption of the previous calendar year). In this chapter, Intercontinental Futures Exchange (ICE) brent crude oil futures contracts, denominated in Euro are examined. Further details are available in the Appendix.

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6.2.3

91

Natural Gas

Natural gas is defined as a mixture of hydrocarbon gases which arise from petroleum deposits, principally methane together with varying quantities of ethane, propane and butane. Natural gas is an increasingly important global source of energy. The ongoing integration of electricity and natural gas markets in the EU25, alongside the relatively low carbon emissions associated with natural gas, favours prospects for natural gas relative to prospects for coal, as the preferred fossil fuel, in Europe (Egging and Gabriel 2006; Honore 2006). However, the security and diversity of supply routes of natural gas from Gazprom in Russia are uncertain.5 Moreover, it is evident that Russia, with regard to its natural gas resources, has pursued a rent seeking economic rationale, thus maximising the economic rent from its carbon resources (Spanjer 2007). The Russian Federation is, by some considerable distance, the primary source of natural gas in Europe.6 That said, the reliance of the EU-27 on Norway, Nigeria and Qatar for sources of natural gas have strategically increased between 1994 and 2004. Furthermore, running contrary to the prospects of natural gas to take the role of the fossil fuel of choice in the EU-25, there is a likelihood of emerging counter-productive concentrations of power in the electricity and gas markets (e.g. monopolies and/or oligopolies may emerge where electricity and natural gas providers merge), arising from the continued integration of these markets. Nevertheless, in summary, there is a clear requirement for Europe to continue to diversify away from dependence on Russian natural gas as well as to improve Europe’s resilience to shocks by better inter connecting Europe’s physical energy networks. Concerning our analyses, in this chapter, as with the price of coal, we do not examine the price of natural gas directly but rather we examine a clean spark spread, CSSt which is, as per convention, the discrepancy between the price of electricity and the price of natural gas:
 1 þ pCO2  FEGas CSSt ¼ pElecbase  pGas  rGas

(6.2)

The clean spark spread at time t, CSSt, is defined as equal to the price of electricity Powernext Futures Month Ahead Peak in € per MWh, pElecbase together with certain adjustments for the price of gas, pGas. Specifically, the price of gas pGas is the natural gas Zeebrugge Month Ahead, in € per MWh and rGas is the net thermal efficiency of a conventional gas fired plant (55%). In addition, the price of carbon pCO2 is sourced at Bluenext and denominated in €. Finally FEGas is the CO2 emission factor of a conventional gas-fired plant in tCO2/MWh. Further details are available in the Appendix. 5

The Russian government and Gazprom may be considered as a single entity. The reliance of the EU-25 on Russia for natural gas imports remains high in 2004 at 32%, however, in 1994 48% of EU-25 natural gas imports originated in Russia, see Egging and Gabriel (2006). 6

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Climate Change

On the whole, climate change is a global public ‘bad’ as opposed to a public ‘good’. As a result, the solution to the dilemma of climate change is solely available at the international level where the prospect of moral hazard (i.e. the free-rider phenomenon) can be monitored and minimised (Helm 2007). Otherwise, any given country would naturally be incentivated to continue to increase their carbon emissions while benefiting environmentally from a reduction of carbon emissions internationally (Barrett 2003, 2005). Tol (2009) reviews the literature regarding the economic impacts of climate change which are large, complex and uncertain. Initially, it is anticipated that the effects of climate change will improve economic welfare (these are sunk benefits) although the effects are expected to be predominantly negative by the end of the century. By way of, inter alia, the EU’s Emissions Trading Scheme, the EU has pursued a sophisticated unilateral action alongside advocacy to curtail carbon emissions. While the EU has had some success in adopting targets with regard to its carbon emissions and in persuading Russia to ratify the Kyoto Protocol (the EU supported Russia’s World Trade Organisation application), it has thus far failed to convince the United States to ratify the Kyoto Protocol. In fact, the Copenhagen summit in December 2009 has failed to pave the way to new concerted intercontinental action on climate change comprising a legally binding agreement. Nonetheless, the 16th Conference of the Parties to the UN Framework Convention on Climate Change (UNFCCC) in the Mexican resort of Cancu`n in December 2010 provides considerable potential with regard to possible concerted legally binding intercontinental commitments to action in the context of climate change.

6.2.5

European Union Allowances

In January 2005 the European Union (EU) Emissions Trading Scheme (ETS) was introduced formally. The scheme has been instigated as part of the EU agreement to cut worldwide emissions of carbon dioxide (CO2) within the Kyoto Protocol. Under the Kyoto agreement, the EU has committed to reduce greenhouse gas (GHG) emissions by 8% (relative to 1990 levels) by 2008–2012. The scheme issues a restricted amount of emission allowances to firms on an annual basis. At the end of the year firms must hold the required amount of emission permits to meet their emissions of CO2 over the previous year. The ETS allows firms to trade the amount of emission permits that they hold and as a result has applied a market value to this externality. In the EU ETS context the first phase of trading was 2005–2007 and the second one, which coincides with the first compliance period of the Kyoto Protocol, is 2008–2012. The third European trading phase will commence in 2013. Noncompliance with the commitments will result in a penalty of 40 (100) euros per tonne of CO2 produced without allowances for the first (second) commitment period. The aim of the ETS is that this cost will encourage firms to reduce their

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emissions. Paolella and Taschini (2008) highlight that the ultimate aim of this scheme (as well as the US CAAA-Title IV scheme) must be to create an environment where there is scarcity of allowances which will lead to an upward trend in prices. As a result we might expect to see mean reversion around an upward trend. However, there has been a considerable amount of uncertainty associated with the price of CO2 emissions over its short life to date. Concomitant to the recent dramatic fall in allowance prices (spot falling from 30 euro in the summer 2008 to 15 euro in the summer of 2010) has been growing calls for intervention by the European Commission into the market. Those calling for intervention see the low prices as incentivising higher rather than lower carbon based technology.7 Any intervention is likely to seriously distort the market and may impede investment in low carbon technology in the future. As noted by Lowrey (2006), a centrally important element of the EU ETS is the establishment of a market determined price for EU allowances.

6.3

Methodology

We examine the development of cointegration relations in a system containing daily closing prices on clean dark and spark energy spreads, EU allowance futures contracts, Eurex Dow Jones EURO STOXX futures contracts, absolute deviations from mean temperatures and production as well as futures contracts on oil fossil fuel prices. All series are in logs except temperature deviations. In the environmental finance literature (see e.g. Bredin and Muckley (2010)) the key drivers of EUA prices comprise economic growth, energy prices and weather conditions, which can be posited as EUAt ¼ a0 þ a2 pt þ a1 yt þ a3 Tt

(6.3)

where EUAt, yt, pt, and Tt stand for EUA futures price, income, energy prices and finally temperature. In this chapter, our statistical testing procedures include conventional versions of the Engle and Granger (1987) and Johansen (1988) cointegration tests alongside a modified Johansen (1988) cointegration test which is an adaptation of the methodology provided by Gannon (1996). The Engle and Granger (1987), Johansen (1988) and Gannon (1996) methodologies are detailed in the literature and so we provide only a brief description of these statistical tests. The methodology is applied to examine the overall behaviour of the system and its evolution with respect to the criterion of cointegration. We perform static analysis including hypotheses tests focused on the significance of the EU allowance 7

Mark Lewis, director of global carbon research at Deutsche Bank, proposed (6 February 2009) to establish a reserve price for EU emissions allowances (EUAs) to avoid a price collapse in the third phase of the EU ETS, which starts in 2013 (see e.g. http://www.EurActiv.com).

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futures contracts in the estimated cointegrating vectors. In addition, to gain an insight into the evolution of the system, we recursively estimate the outlined tests for cointegration. In particular, with regard to our recursive methodology, we perform the tests over the initial 250 observations and subsequently repeat the testing procedure over an extended window of data, where the window is extended by a single observation prior to each incremental estimate of the test statistics. The Engle–Granger (1987) methodology requires that the variables are found to be integrated of order 1, I(1) and the estimated long-run relationship is described in (6.4). If the variables, xi,t where i ¼ 1. . .k, are actually cointegrated, then the ordinary least squares regression yields a super consistent estimator of the cointegrating parameters, b0. . .bk. This possibility is investigated by means of (6.5) to establish if the deviations from long-run equilibrium are stationary. MacKinnon (1991) provides appropriate critical values. yt ¼ b0 þ b1 x1;t þ


þ bk xk;t þ et D^ et ¼ a1 e^t1 þ

n X

aiþ1 D^ et1 þ E

(6.4) (6.5)

i¼1

Unfortunately, the Engle–Granger (1987) technique does exhibit several important defects. In particular, it is sensitive, in finite samples, to the choice of variable for normalisation. Even in the simple two variable setting, a potential drawback of the Engle–Granger approach is that there could be a simultaneous equations bias if the causality between the variables runs in both directions. The problem is clearly compounded using three or more variables given that any of the variables can be selected as a left hand side variable. In addition, the methodology precludes the possibility of estimating multiple cointegrating vectors. Finally, another defect of the Engle–Granger (1987) procedure is that it is a two-step procedure, this imparts invidious implications for the efficiency of the testing procedure. Fortunately, the Johansen (1988) procedure is a maximum likelihood estimator which circumvents the requirement for a two-step estimator. The Johansen approach allows all variables to be endogenous and, as a result, can estimate and test for multiple cointegrating relations. The Johansen (1988) cointegration testing framework involves the maximum likelihood estimation of the vector error correction model (henceforth VECM), as outlined in (6.6–6.8). Specifically, the test for cointegration involves the performance of likelihood ratio statistical hypotheses tests regarding the rank of the longrun information matrix, p. These statistical tests provide an estimate of the number of characteristic roots that are insignificantly different to unity. Dxt ¼ pxt1 þ

k1 X i¼1

pi Dxt1 þ et

(6.6)

6 The Price Forming Process in Energy Markets

p¼

k X

95

pi  I

(6.7)

i¼1

pi ¼ 

k X

pj ; ði ¼ 1; :::; k  1Þ

(6.8)

iþ1

In order to ascertain the rank of the long-run information matrix, p, a set of socalled trace statistics, ltrace(r), is estimated. ltrace ðrÞ ¼ T

n X

lnð1  ^li Þ

(6.9)

i¼rþ1

In this formulation, T refers to the number of available observations. The symbol, ^li , denotes the estimated value of the ith characteristic root, or equivalently an eigenvalue in the long-run information matrix. The ltrace(r) statistic assesses the null hypothesis that the number of cointegrating vectors is less than or equal to r against a general alternative hypothesis. Typically, results are generated for each possible value of r. Osterwald-Lenum (1992) provides critical values. However, the Johansen (1988) maximum likelihood style methodology assumes homoskedasticity in the disturbances, et, hence it neglects the possibility of gains in statistical power stemming from explicitly accounting for heteroskedasticity (see Alexakis and Apergis (1996), Gannon (1996) and Pan et al. (1999)). As a result of the possibility of a gain in statistical power we estimate a modified Johansen (1988) testing procedure with a view to mitigating for the deleterious implications of heteroskedasticity effects on the estimation of the rank of the long run information matrix in a specified VECM. Specifically, we adopt a modified test for common roots in which we account for heteroskedasticity effects in the correlating combinations of residuals. Methodological details of the modified methodology are presented in Gannon (1996), Pan et al. (1999) and Bredin and pffiffiffiffiMuckley (2010). In brief, an estimate of each eigenvalue, li, is available as ri  li . The coefficient ri is derived in a straightforward manner following from a decomposition of the VECM and an estimation of the eigenvalues controlling for heteroskedasticity.

6.4 6.4.1

Data and Empirical Results Data

Our data includes daily closing prices on clean dark and spark energy spreads, EU allowance futures contracts, Eurex Dow Jones EURO STOXX futures contracts, absolute deviations from mean temperatures and production as well as futures

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Oil Prices

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30 20

50

10 0

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0

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200

Eurostat Index

Euro per MWh

Clean Dark and Spark Spreads

100 0

−100

CDS CSS 2007

110

90 80

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2010

Absolute Temperature Deviations

Equity Prices 10 Temp. Dev.

Euro Stoxx 50

2010

100

6000 4000 2000 0

2007 Production

2007

2010

5 0

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2010

Fig. 6.1 EUAs, oil, energy spreads, production, equity and temp. deviations

contracts on oil fossil fuel prices. The data sample covers the period 1st July 2005 to 14th December 2009.8 All the examined data is plotted in Fig. 6.1, with data construction and sources detailed in the Appendix. Our motivation for choosing futures contracts rather than spot contracts is based on both economic and empirical grounds. Firstly, we would like to overcome the implication of the no banking rule between Phase 1 and 2. The use of futures contracts allows for a more medium to long-term perspective and also avoids the structural adjustment in relation to the move from Phase 1 to 2. This point has also been highlighted in Chevallier (2009) as a motivation for adopting a future based assessment. The price paths for spot (Phase 1) and December 2007, 2008 and 2009 futures contracts are plotted in Fig. 6.2. The spot contract and the December 2007 contract have a similar behaviour over our sample and clearly identify the difficulty of adopting these contracts as a result of the no banking rule between phases. Intuitively we would not expect the 2008 and 2009 contracts to be overly influenced by the no banking rule and this is evident from Fig. 6.2. Empirically, the volumes traded on futures contracts are considerably larger than on spot contracts.9 For example, Mansanet-Bataller and Pardo (2008) report the total traded volume for futures contracts being 77%, while 4% for spot. In addition it is important to note that our analysis does not adopt a formal EU ETS Phase 1 and/or Phase 2 sample. Instead we adopt carbon futures that have an expected delivery in Phase 2 and examine the potential long-run relationships over a Phase 1 and 2 sample. We also examine some sensitivity tests for a Phase 2 only sample. 8

The sample of data commences on the 1st July 2005 with the first available observation of the December 2008 EUA futures price on the European Union Climate Exchange. The sample of data is discontinued 14th December 2009 prior to the expiration of the December 2009 EUA futures contract. Further details are available in the Appendix. 9 The growth in futures volumes compared to spot is driven not only by compliance participants, but also commercial banks, carbon funds and speculative investors (see Labatt and White 2007).

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35 30

Euro

25 20 15 10

EUA Spot Dec09 Sett Dec08 Sett Dec07 Sett

5 0

2006

2007

2008

Fig. 6.2 EU allowance spot and futures prices

Table 6.1 Summary statistics Exc. Series Mean Variance Skewness kurtosis ARCH

PP unit root

LS unit root

EUA 0.06 8.58 0.92* 11.53* 43.98* 2.61 [30.05*] 3.80 [14.51*] CDS 0.05 56.09 2.14* 22.01* 0.50 3.30* [32.04*] 3.39 [16.28*] CSS 0.02 65.49 3.48* 68.83* 20.38* 3.85* [37.33*] 3.90 [19.92*] Equity 0.01 2.66 0.03 8.31* 237.73* 0.95 [35.31*] 2.58 [16.08*] Oil 0.00 4.90 1.43* 18.55* 13.86* 1.75 [37.48*] 2.29 [16.05*] Prod. 0.01 0.01 2.29* 30.10* 13.13* 1.01 [13.24*] 3.90 [5.86*] Temp. 2.25 2.81 0.99* 0.77* 574.04* 15.19* [53.88*] 11.37* [23.49*] To facilitate logarithmic calculations a constant of value 30 is added to the Clean Spark Spread. The Clean Spark Spread is denoted CSS. Prod. and Temp. correspond to production and temperature respectively. In column 5 the Lagrange Multiplier (LM) test results are reported for fifth order ARCH effects. In columns 6 and 7, the Phillips and Perron (1988)(PP) unit root test statistics and Lee and Strazicich (2004)(LS) unit root test statistics are reported. The test statistics for each of the series in logarithmic differences are reported in square brackets, while the test statistics with respect to levels are adjacent. A * indicates statistical significance at the 5% level

Table 6.1 presents the summary statistics for the full sample of data. The last two columns report the results from the Phillips and Perron (1988) and Lee and Strazicich (2004) unit root tests. Lee and Strazicich (2004) provide a lagrange multiplier unit root test that endogenously determines a structural break in intercept and trend. Given the market uncertainty, the Lee–Strazicich (2004) test is considered as a further sensitivity test on the Phillips–Perron (1988) unit root test. The Lee–Strazicich (2004) unit root test indicates that each series contains a unit root in levels and is stationary in first differences, except in the instances of production and temperature. In the small number of cases where there is an inconsistency the Lee–Strazicich (2004) unit root test results are adopted. The summary statistics indicate that the clean dark spreads (CDS) and the clean spark spreads (CSS) exhibit the greatest level of variance by a large order of

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magnitude. Given the recent findings, in particular Paolella and Taschini (2008) and Benz and Tr€uck (2009), we also test for the level of autoregressive conditional heteroskedasticity (ARCH) using a lagrange multiplier (LM) test. According to the LM test the CDS differences appear homoscedastic, during all sample periods examined. According to the same statistical test the differenced CSS, oil, equity, production, temperatures and the EUAs series exhibit pronounced heteroskedasticity. In addition, the summary statistics indicate that the return distributions for the majority of the series examined are characterized by higher peakedness and thick tails relative to a normal distribution. Taken together, these summary statistics reflect the possibility of cointegration relations governing the system of variables examined. However, as has been discussed earlier in the chapter, the heteroskedasticity that is apparent in our data may compromise the capacity of the classic Johansen (1988) cointegration test.

6.4.2

Empirical Results

The Engle and Granger (1987), the Johansen (1988) multivariate likelihood ratio cointegration approach and the Gannon (1996) modified cointegration tests are used to assess whether there are common forces driving the long-run movements of the full set of variables examined. The Engle–Granger approach is adopted purely as a preliminary investigation of the potential long-run relationships. Table 6.2 presents Engle–Granger (1987) style results, with the t-statistics calculated using Newey and West (1987) adjusted standard errors. Specifically, it contains linear regression coefficients (all variables are logged, with the exception of temperature) corresponding to the full sample. The Dickey–Fuller test statistic (last column) is not statistically significant and indicates the lack of cointegration. The point coefficients give a preliminary indication as to the likely empirical relationships between EUA prices and the key variables of determination. The coefficients on CSS, equity and oil all indicate statistically significant and theoretically consistent relationships. The negative relationship between production and the EUA prices is not consistent with theory. The negative sign on production may be adversely affected by the dramatic decline in output during the latter part of the sample. Sensitivity analysis indicates that this in fact is the case, with a positive sign Table 6.2 Engle–Granger cointegration equations CDS CSS Equity Oil Production Temperature DF t-stat 0.07 0.17* 0.45* 0.81* 0.77* 0.01 EUA (1.71) (3.09) (6.12) (13.94) (5.59) (1.65) 3.34 The results are Newey and West (1987) linear regression coefficients and coefficient t-statistics in brackets. The Newey and West (1987) t-statistics (far right hand side column) are reported regarding the null hypothesis of a unit root in the residual from the hypothesised cointegration equations. The critical values are sourced in MacKinnon (1991). A * indicate statistical significance at the 5% level

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Table 6.3 Johansen cointegration equations Panel A: Normalized cointegration vectors CDS CSS Equity Oil Production Constant 0.64* 2.54* 3.39* 0.45 18.17* 62.50* EUA (3.44) (8.10) (6.17) (1.21) (6.47) (6.91) Normalised cointegration equation, with corresponding t-statistics in brackets is reported. The cointegration equation is normalised on the EUA variable in each sample period. A * indicates statistical significance at the 5% level

(and statistically significant) on production for a sample of data prior to the economic downturn. CDS and CSS represent the profitability for electricity generators depending on whether coal or gas is the principle input. Theory would indicate a negative (positive) relationship between EUAs and CSSs (CDSs). A negative relationship is found between EUAs and CSSs is expected to arise as greater profitability from generating electricity from natural gas, ceteris paribus, would result in switching to natural gas fueled electricity generation and hence a short run abatement with respect to CO2 emissions. EUA prices are likely to decline following the fall in demand. The theoretically consistent positive relationship is also found between CDS and EUAs, although not statistically significant. Oil prices are statistically significant with a coefficient close to unity. Finally, the temperature variable capturing unanticipated innovations in temperature (measured in absolute terms) is not statistically significant. Table 6.3 presents the normalised distinct cointegration equations and related hypotheses testing results, with respect to the Johansen (1988) estimation of the vector error correction model specification. The model specification (deterministic components and lag length) is inferred with respect to the Schwarz information criterion.10 The normalized cointegrating equations are presented alongside the t-statistics on the coefficients. We do find evidence of cointegration and the signs on the coefficients on oil and production are consistent with theory. While equity, CSS and CDS are statistically significant, the signs are not consistent with theory. As a result of the prevalence of ARCH effects in the data, a modified cointegration test with GARCH effects is performed. Table 6.4 presents the results.11 The test statistics are estimated from the procedure described by Equations 6.6 to 6.9. The r ¼ 1 test results are based on variates constructed from the weights for the maximum canonical correlation, whereas the second highest canonical correlation is used for r ¼ 2, and so forth. Our results indicate evidence of cointegration, a single cointegrating vector, and are consistent with the Johansen approach results reported in Table 6.3.

10

These results are not presented here although they are available from the authors upon request. Further robustness tests have examined the sensitivity of seasonality (day of the week and monthly) on our results. The seasonally adjusted results are quantitatively consistent with those reported here and are available upon request.

11

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Table 6.4 Modified multivariate test for cointegration Critical values OLS coeff. GARCH coeff. t-Statistic 10% 5% 1% r¼1 0.19 0.11 4.90* 3.81 4.10 4.65 r¼2 0.17 0.13 4.32* 3.45 3.75 4.29 The table reports coefficients for r ¼ 1, 2 which are the estimated square roots of the eigenvalues, while accounting for t-distributed GARCH effects, of the Johansen long-run information matrix. These coefficients are also estimated using OLS in conjunction with the Newey and West (1987) standard error estimator. See MacKinnon (1991) for critical values. A * indicates statistical significance at the 5% level

Recursive Coefficient Point Estimates

3 CDS CSS Equity Oil Production Temperature

2.5 Production

2 1.5 1

Oil

0.5 0 CDS

−0.5 Equity

−1 −1.5

2007

2008

2009

2010

Fig. 6.3 Recursively estimated Engle–Granger test coefficients

6.4.2.1

Robustness Tests

In Fig. 6.3, we present recursively estimated coefficients pertaining to the Engle–Granger (1987) cointegration equation. The initial coefficients are estimated during the period 1st July 2005 through to the 1st July 2006 and the subsequent coefficient estimates are obtained by extending the period of estimation by an incremental observation for each subsequent estimation until the 14th December 2009. The findings reveal that the effects of the clean dark and spark spreads are relatively small and that the theoretically consistent direction of these effects, a marginally positive effect of the clean dark spread and a marginally negative effect of the clean spark spread, only emerge during the whole period under examination. In contrast, the effect of the oil prices on the European Union allowances is relatively substantial and positive for the preponderance of the period, at least since 2007. The control explanatory variables, the equity index futures contract and the production measurement, show substantial effects throughout the full period examined and the emergent negative effect of production and the positive effect of equity are evident only since 2009. The control explanatory variable, temperature, has an approximately negligible effect on the European Union allowances throughout the whole period under examination. In light of the likelihood of evolving dynamics within the full system of data examined we turn to the recursive cointegration analyses, in relation to the

Newey−West T−statistic for the null of a Unit Root

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110 100

Rescaled Critical Values

90 80 70 60

NW T−stat 1

50 40 30 20 2007

2008

2009

2010

Fig. 6.4 Engle–Granger cointegration test

Maximum Likelihood Lambda Trace Statitics

120

110

100

90

80 TraceX1 TraceX2

70

60

2007

2008

2009

2010

Fig. 6.5 Johansen maximum likelihood cointegration test

Engle–Granger approach, the Johansen approach and finally the modified cointegration test accounting for heteroskedasticity. Figures 6.2–6.4 presents the results for Engle–Granger, Johansen and the modified cointegration approach. As can be seen from Fig. 6.4, the Engle–Granger (1987) recursive test indicates a lack of cointegration throughout and is clearly consistent with the results from Table 6.2. The Johansen (1988) recursive analysis is plotted in Fig. 6.5 and indicates, notwithstanding a brief period in early 2006, a lack of significant distinct cointegration vectors throughout the sample, until a marked strengthening of this result from 2008. The implication is that our finding of cointegration is heavily influenced by long-run relationships emerging in Phase 2 of the EU ETS. Finally, turning to the recursive results provided by the robust cointegration methodology (using a Newey and West 1987, adjustment) in Fig. 6.6, the results again suggest a cointegration relationship developing over Phase 2 only. Given the results from the recursive analysis we have re-examined the cointegration relationships for a Phase 2 sample only. The results for both the normalized Engle–Granger and Johansen cointegrating relationships are reported in

Newey−West T−statistic for the null of a Unit Root

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140

120

100

80

60

NW T−stat1 NW T−stat2

40 2007

2008

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2010

Fig. 6.6 Modified cointegration test Table 6.5 Engle–Granger cointegration equations: phase 2 CDS CSS Equity Oil Production Temperature DF t-stat 0.39* 0.43* 0.22* 0.87* 0.47* 0.01 3.65 EUA (5.39) (4.29) (1.99) (11.85) (2.41) (1.23) The results are Newey and West (1987) linear regression coefficients and coefficient t-statistics in brackets. The Newey and West (1987) t-statistics (far right hand side column) are reported regarding the null hypothesis of a unit root in the residual from the hypothesised cointegration equations. The critical values are sourced in MacKinnon (1991). A * indicate statistical significance at the 5% level

Tables 6.5 and 6.6 respectively. Theoretically consistent results are found for all variables when using the Engle–Granger approach, although production continues to have a negative sign. Of particular note is the correct signs on both of the energy spread terms, CDS and CSS. The Johansen results are reported in Table 6.6. The results for the cointegrating relationship using the Johansen approach, panel A, are theoretically consistent for the case of oil and the two spread terms. The influence of the economic downturn appears to be occurring via the equity term, rather than production as was the case using the Engle–Granger methodology. To further examine the extent of the cointegrating relationship, we now report a number of hypothesis tests in Panel B (hypotheses tests (ii), (iii) and (iv)). The results clearly provide further support of a cointegrating relationship emerging in Phase 2 of the EU ETS. In panel B of the table we present those hypotheses testing results directly related to the European Energy markets for both our full sample and Phase 2. The hypotheses that there are at most rðr ¼ 0:::4Þ distinct cointegrating vectors are examined, with the critical values obtained from Osterwald-Lenum (1992). As can be seen from hypothesis test (i) in Panel B, the Trace test results indicate that a long-run relationship exists.12 The hypotheses tests (ii), (iii) and (iv) correspond to null 12

Only the Trace test statistic and associated P-value for the null hypothesis of no cointegration against a general alternative are reported. The set of unpresented Trace test statistics fail to reject their corresponding null hypotheses.

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Table 6.6 Johansen cointegration equations and hypothesis tests: phase 2 Panel A: Normalized cointegration vectors CDS CSS Equity Oil Production Constant 1.18* 0.83* 0.91* 1.02* 2.23* 5.26 EUA (5.62) (2.55) (3.26) (4.91) (1.38) (0.89) Panel B: Hypothesis testing EUA equation (iv) (iii) (ii) (i) 11.94* 9.75* 0.23 159.36* (0.00) (0.00) (0.63) (0.00) Phase 2 CDS equation (iv) (iii) (ii) (i) 23.96* 21.21* 2.73 159.36* (0.00) (0.00) (0.09) (0.00) Phase 2 CSS equation (iv) (iii) (ii) (i) 4.89 4.42* 0.23 159.36* (0.09) (0.03) (0.63) (0.00) Phase 2 Oil equation (iv) (iii) (ii) (i) 13.15* 10.82* 5.65* 159.36* (0.00) (0.01) (0.02) (0.00) Phase 2 Panel A presents a distinct normalised cointegration equation, with corresponding t-statistics in brackets. The cointegration equation is normalised on the EUA variable in each case. Panel B contains hypotheses testing results, with the corresponding p-values in brackets. The model specifications (deterministic components and lag length) are inferred with respect to the multivariate version of the Schwarz Bayesian information criterion. These results are not presented here. The likelihood ratio Trace test statistic (i) indicates that there is at least a single cointegrating equation (CE) in each of the sample periods examined. The remaining hypotheses tests (ii), (iii) and (iv) assess the null hypotheses of a zero loading coefficient on the disequilibrium error in the corresponding equation, a zero cointegration vector weight, corresponding to the reference equation, in the distinct cointegration equation and a joint hypothesis test to assess these latter two null hypotheses, respectively. A * indicates statistical significance at the 5% level

hypotheses of a zero loading coefficient on the disequilibrium error in the corresponding equation, a zero coefficient on the corresponding variable in the cointegrating equation and a joint null hypothesis with respect to these latter hypotheses, respectively. The results are robust to alterations of the deterministic components in the vector error correction model. Concerning the clean dark spread equation, it is evident that the disequilibrium error is becoming increasingly important during Phase 2 and that the clean dark spread plays a significant role in the long run relation which has emerged. In addition, during the full sample period the disequilibrium error significantly influences the clean dark spread. Turning to the clean spark spread, similar results are revealed. Specifically, during the full sample period, there is significant evidence of the disequilibrium error influencing the clean spark spread, albeit not during Phase 2 in isolation. However, during the Phase 2, it is clear that the clean spark spread nonetheless performs an important role in the cointegration relation. In Phase 2, although the individual hypothesis that the EUA futures contract does not respond to the disequilibrium is not rejected, it is evident that

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the EUA futures contract plays a significant role in the long run relation that has emerged in the system and that the joint hypothesis of a zero loading on the disequilibrium and the cointegration equation is clearly rejected. Finally, looking at the oil futures equation, in Phase 2, there is a significant effect from the disequilibrium error on the oil futures prices and the oil futures variable performs an important role in the cointegration relation. Taken together, there is considerable evidence of an emerging long-run relation interlinking the European energy markets as well as the European Union allowance prices, during the 2005–2009 period.

6.5

Conclusion

In this chapter, we have examined the price formation process in European energy markets. In particular, we have investigated relations between the daily closing prices on the European clean and dark energy spreads the oil market as well as the European carbon market during the period 2005–2009. By way of control variables we have also included, in our study, proxy explanatory variables for economic activity and the weather. Specifically, we have included the Eurex Dow Jones EURO STOXX futures contracts, productivity statistics and the absolute deviations from mean temperatures within our econometric specification. The findings presented in this chapter are indicative of a new pricing regime emerging since January 2008 which empirically interlinks the coal, gas and oil markets with European Union allowance futures contracts. Today, it would appear that European Union allowance contract prices play an integral role in the price formation process in European energy markets. More broadly, the results highlight the natural interconnectedness of these markets in an increasingly integrated market place and the latent potential, and progress attained, in terms of enhancing European competitiveness. Finally, we recommend that the enhancement of European competitiveness may be accomplished by completing the physical internal energy market as well as facilitating longer-term price stability both in terms of the cost of energy as well as the cost of European Union allowance contracts.

Appendix: Data Description Series

Energy spreads

Description Clean dark and spark energy spreads, denominated in Euro per MWh, comprise the discrepancies between the price of electricity at peak hours and the price of coal and the price of natural gas, respectively, required to generate that electricity. These spreads are adjusted for the energy output of the coal/natural-gas fueled plants. They are calculated by Caisse des Depots Climate Task Force for Tendances Carbone, and are observed at a daily frequency from July 1, 2005 through to December 14, 2009 Source: http://www.caissedesdepots.fr (continued)

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Appendix (continued) Series Description European Union Allowance daily futures contract prices, denominated in Euro, observed from July 1, 2005 to December 14, 2009 with expiration in December 2008 and December 2009. The expiration is switched to December 2009 in the third week of December 2008. The unit of trading is one lot of 1,000 CO2 EU Allowances. Each EU Allowance being an entitlement to emit one tonne of carbon dioxide equivalent gas Source: European Climate Exchange EUAs The Dow Jones EURO STOXX 50 is denominated in Euro. It’s a stock index of futures contracts on 50 Eurozone stocks designed by STOXX Ltd. The data are observed during the period July 1 2005 to December 14 2009, at a daily frequency. The contracts switch on the first day of each expiry month to the subsequent expiry month futures contract Equity Source: Thomson-Reuters, Datastream ICE (Intercontinental Futures Exchange) brent crude oil futures contracts, denominated in Euro are United Kingdom daily contract prices observed from July 1, 2005 to March 2, 2009 with expiration December 2005, December 2006, December 2007, December 2008 and December 2009. The expiration is altered in the third week of December annually Oil Source: Thomson Reuters The Eurostat industrial production index has a of base 100 in 2000 and is seasonally adjusted. Observations are recorded between July 1, 2005 and December 14, 2009. Daily observations are estimated via interpolation by adopting a piecewise cubic spline methodology, provided by Matlab Production Source: http://ec.europa.eu/eurostat Temperature deviations (absolute) from monthly average temperatures (13-year average) for he Tendances Carbone European temperature index. The data are observed during the period July 1, 2005 to December 14, 2009. The Tendances Carbone European temperature index is equal to the average of national temperature indices sourced with Powernext. These national temperature indices are computed using weights determined by intra-country regional populations. The European index is weighted by the share of NAP in the constituent countries: France, Germany, Spain and the United Kingdom Temperature Source: Tendances Carbone

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.

Chapter 7

The Electricity Market, Day-Ahead Market and Futures Market Goknur Umutlu, Andre´ Dorsman, and Erdinc Telatar

Abstract This chapter firstly provides an overview of the day-ahead and futures electricity markets of APX-ENDEX1 that is one of Europe’s most experienced energy exchanges, operating spot and futures markets for electricity and natural gas in the Netherlands, the United Kingdom and Belgium.2 An empirical analysis on the relationship between spot and futures electricity market of APX-ENDEX is then covered. We handle the most liquid year, which is 2008, of traded electricity futures contracts and we find that the market is in normal backwardation. Our regression analysis extents the Fama (J Monet Econ 1984;14:319–338) regressions and rejects the efficiency hypothesis. Our results indicate that the futures prices are not unbiased predictors of the future spot prices. Remarkably, the difference

1

APX-ENDEX refers Amsterdam Power Exchange – European Energy Derivatives Exchange. In September 2010, NYSE Euronext, the biggest operator of U.S. stock exchanges, formed a joint venture with APX Inc. to expand its trading volume in electricity, renewable energy and carbon dioxide allowances. The name of the new company is NYSE Blue. 2

The authors are grateful to Mr. M. Rijke, director of Energy Data Company, Mr. D. Jong, Belgian Power Exchange (BELPEX), and Mrs. E. Sarr, European Power Exchange, EPEXspot for their advice and support for the data. We are also thankful for the detailed comments of Mr. M. Nijpels, Product Manager of APX BV, Amsterdam and Mr. P. Pottuijt, Senior Energy Consultant in the Dutch and Central Western European (CWE) energy market. G. Umutlu (*) Department of Business Administration, Hacettepe University, Ankara, Turkey e-mail: [email protected] A. Dorsman VU University Amsterdam, Amsterdam, The Netherlands e-mail: [email protected] E. Telatar Department of Economics, Hacettepe University, 06800 Ankara, Turkey e-mail: [email protected] A. Dorsman et al. (eds.), Financial Aspects in Energy, DOI 10.1007/978-3-642-19709-3_7, # Springer-Verlag Berlin Heidelberg 2011

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between the spot and futures prices is associated with the risk premium and the change in spot prices, supports the arbitrage and speculation opportunities in the market. Keywords Arbitrage
Backwardation
Contango
Day-ahead market
Efficiency
Electricity market
Futures prices
Risk premium
Speculation

Abbreviations APX BE CFD EEX EU GMT KW MW MWh NL NYMEX OTC PV Program TenneT TSO UK

7.1

ENDEX Amsterdam Power Exchange – European Energy Derivatives Exchange Belgium Contracts for difference European Energy Exchange European Union Greenwich mean time Kilowatt Megawatt Megawatt hour Netherlands New York Mercantile Exchange Over the counter Responsibility (Dutch: Programma verantwoordelijkheid) The Dutch transmission system operator Transmission system operator United Kingdom

Introduction

Over the last two decades, rapid restructuring and liberalization in the electricity markets accelerated the long-term objective of a single European energy market. Deregulated electricity markets are no longer controlled by national monopolies but they are now essentially determined according to the economic rule of supply and demand in a competitive framework. Restructuring removed price controls in the market and openly encouraged market entry to all market players regardless of their size. A deregulated electricity market consists of at least two parts; a spot market and a futures market. Due to the fact that electricity is a commodity, the spot market is a day-ahead market, which means that the trades on day t þ 1 are fixed on day t.

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For the European and American electric power industry, the futures market provides a good risk management tool reducing the operational risks caused by the high fluctuation of electricity prices in the spot market (Sioshansi and Altman 1998). The futures and forward markets may also serve as a profitability indicator for investments in the power systems, and thereby contribute to a balanced development of demand and supply. In order to use these markets efficiently, it is essential for the power industry to gain knowledge about the information hidden in the long-term prices, in particular the relationship between the spot and futures prices of electricity. Although there are a number of day-ahead markets in Europe, only a few futures markets on electricity exist. The Netherlands is one of the exceptions with both markets that offers high liquid spot and futures market data for electricity and natural gas in the Netherlands, the United Kingdom and Belgium. APXENDEX has a pioneering role for the goal of a single European energy market as compared with Nord Pool and the other Iberian competitors in the electricity arena. It is interesting to see the relationship between the day-ahead market and the futures market in APX-ENDEX, particularly after the market coupling of the day-ahead markets of Belgium, France and the Netherlands in November 2006. With the introduction of market coupling mechanism, the Dutch, Belgian and French spot power markets are linked.3 Dorsman et al. (2010) has noted that a market-coupling event creates both risk reduction and price declines in the highest price countries, the Netherlands and France. After the moment of coupling the volatility of base, peak and off-peak electricity prices in the Netherlands and France declines. The electricity prices of the interconnected grids differ as long as the capacity is fully used between the EU countries. Transparency and the other limiting barriers also cause inefficiencies in the market. A fuller understanding of the pricing relationship between spot and futures markets will enable the benefits of interconnection to be assessed on a step towards the fuller integration of the EU electricity market. The market participants willing to minimize their risks regard the futures market prices to predict those of future spot. In an efficient market, the futures price is the best predictor of the future spot prices, and the risk premium is zero. However most of the studies in the commodity market confirm that the futures prices are not unbiased predictors of future spot prices because of the time varying risk premiums. According to the statistics and econometric research of Herraiz and Monroy (2009), since the middle of nineteenth century many commodity futures markets are not efficient and arbitrage opportunities may exist. In an institutional power exchange where consumers and generators are allowed to work in spot and futures markets, one could take advantage of the predictable prices and design strategies to earn riskless profits (Arciniegas et al. 2003). 3 The concept is now planned to include Germany, Luxembourg and Norway. In addition, APXENDEX is also developing on the BritNed electricity cable, linking the Netherlands and the United Kingdom and will start to operate in 2011. This linkage proven to be successful will bring new liquidity to the UK electricity market.

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Research in the efficiency of electricity futures markets has begun only recently (Yang et al. 2009). Non-storability of electricity, seasonality and grid-bound transportation hampers arbitrage between different markets and particularly in times of congestion causes different prices depending on the delivery area (Pietz 2009). A review of literature shows that most studies so far have focused on comparing day-ahead and real time prices of the system operators due to the available real-time data. Borenstein et al. (2001) finds that the two benchmark electricity prices in California – the Power Exchange’s day-ahead price and the Independent System Operator’s real-time price – differed substantially after the markets opened, but then appeared to be converging at the beginning of 2000. Starting in May 2000, however, price levels and price differences increased dramatically after the California crisis. Other models (for instance: Bessembinder and Lemmon 2002; Botterud et al. 2002; Lucia and Torro 2008) comparing the spot and futures prices are limited with the risk premium calculations and do not make it possible for us to detect exact efficiency in the market. The risk premium is highly volatile and regularly changes in sign. Bierbrauer et al. (2007) gives a summary on the established models for electricity spot prices. They test these models on data from the EEX and identify three models best fitting the data. Their results indicate positive risk premium for the short-term and mid-term and negative risk premium for the long-term contracts. Due to this existence of the risk premiums, the market is exposed to unbiasedness or inefficiency. However there is no consensus about the commodity risk premium models in the literature because of forecasting errors about detecting the premiums.4 Gorton and Rouwenhorst (2006) shows that the realized payoff to a futures position is the risk premium plus any unexpected deviation of the future spot price from the expected future spot price. The unexpected deviations from the expected future spot price are unpredictable and the deviations should average out zero over time unless the investor has an ability to correctly time the market. Instead of calculating the risk premiums with these unknown expected spot prices, most studies in the commodity markets prefer to apply the Fama (1970) weak form market efficiency regression test because of its simplicity.5 We extend and contribute to the known literature by testing another regression model of Fama (1984), which is applied in the foreign exchange market. This model has not been tested in the electricity market yet. It counts the effects of the difference between spot and futures prices observed in the market called “basis” on the changes in both the spot prices and the risk premium. The model is more accurate and comprehensive for determining whether the electricity market is efficient or not. According to this model, in order to say that the market is efficient, the basis should not contain any information about either the risk premium or the changes in spot prices.

4

The detailed discussion about the risk premium models is presented in Sect. 7.3. See, Moosa and Al-Loughani (1995) and Crowder and Hamed (1993) for weak form market efficiency tests and speculation or arbitrage possibilities in commodity futures.

5

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By using the mostly traded futures contracts of the APX-ENDEX for 2008, our analysis adopted from Fama (1984) rejects the efficiency hypothesis and figures out the negative risk premium that indicates futures prices are lower than those of spot. Both the risk premium and change in spot prices is affected positively from the basis that could lead us to think that arbitrage and speculation can be possible in the electricity market. In the second section of this chapter, after a brief definition for the electricity market, the APX-ENDEX spot and futures market is introduced. The relationship between spot and futures markets is explained theoretically in the third section. Section 7.4 covers the data and methodology and Sect. 7.5 presents the empirical results. Finally, Sect. 7.6 concludes and provides some comments for further research.

7.2

Electricity Markets

Electricity markets are composed of three parts that is shown in the following Fig. 7.1: electricity exchanges (spot and futures market), over-the-counter (OTC ) market and the balancing market. Traditionally the participants can trade electricity bilaterally on OTC market where the bulk of transactions is still being settled. In order to balance power generation at any time during real-time operations, system operators use the balancing or real-time market, where participants can bid the prices they require (offer) to increase (decrease) their generation, or decrease (increase) their consumption. In the Netherlands TenneT, the Dutch transmission system operator (TSO) is responsible for the balancing market. As an alternative to OTC market, organized markets known as electricity or power exchanges have been established in some countries. A remarkable trading activity is observed for contracts with delivery within the following day at the spot market. The spot market is also called as day-ahead market and it is based on bids for purchase and sale of hourly contracts and block contracts that cover the 24 h of the next day. Electricity is traded a day in advance in power exchanges, and an

electricity market

electricity exchange

balancing market

spot market

futures market

Fig. 7.1 Electricity markets representation Source: http://www.ifor.math.ethz.ch/about_us/press/MitteilungenOct04.pdf

O.T.C.– market

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operating schedule is developed by the system operator. Because of the unavoidable demand-supply mismatch between the settling of contracts on the day-ahead market and actual physical delivery the day after, exchanges sometimes offer an intra-day market, also referred as hour-ahead or adjustment market. The market for other forward contracts is denoted as futures market. European exchanges provide bidding-based trading contracts for power delivery during a specific hour of the next day. The usual trading system in the EU market is a daily double-side auction for every hour to match transactions at a single price and a fixed point in time. Additionally, the market participants can offer or ask the same quantity of power for a period of consecutive hours called as block bids. Here, the market clearing price is the price level at the intersection of the aggregated demand and supply curves and it maximizes the trade volume. The last calculated market clearing price is referred as reference price and it may be used as an alternative. Some exchanges provide an alternative trading for the auction system called continuous trading that differs from auctions in the following ways. Firstly, participants have access to the order book. Furthermore, if possible, each incoming bid is immediately checked and matched according to price/time priority. Finally, the contract price is not the same for all transactions, as it is determined only in accordance to the concerned bids or the order book at the time of the bid matching (Brand et al. 2002). Electricity forward contracts represent the obligation to buy or sell a fixed amount of electricity at a pre-specified contract price, known as the forward price, at certain time in the future (called maturity or expiration time). In other words, electricity forwards are custom-tailored supply contracts between a buyer and a seller, where the buyer is obliged to take power and the seller is required to supply. The payoff of a forward contract is promising to deliver one unit of electricity at price F at a future time and T is ST  F where ST is the electricity spot price at time T. Although the payoff appears to be the same as for any financial forwards, electricity forwards differ from other financial and commodity forward contracts in that the underlying electricity is a different commodity at different times. The settlement price ST is usually calculated based on the average price of electricity over the delivery period at the maturity time T. First traded on the NYMEX in March 1996, electricity futures contracts have the same payoff structure as electricity forwards. However, electricity futures contracts, like other financial futures contracts, are highly standardized in contract specifications, trading locations, transaction requirements, and settlement procedures. The most notable difference between the specifications of electricity futures and those of forwards is the quantity of power to be delivered. The delivery quantity specified in electricity futures contracts is often significantly smaller than that in forward contracts. For example, a Mid-Columbia electricity futures traded on the NYMEX specifies a delivery quantity of 432 MWh of firm electricity, delivered to the Mid-Columbia hub at a rate of 1 MWh, 16 on-peak hours per day during delivery month, while a corresponding forward contract has a delivery rate of 25 MWh for the same delivery periods in a month.

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As compared to electricity forwards, the advantages of electricity futures lie in market consensus, price transparency, trading liquidity, and reduced transaction and monitoring costs while the limitations stem from the various basis risks associated with the rigidity in futures specification and the limited transaction quantities specified in the contracts (Deng and Oren 2006).

7.2.1

Overview of the APX-ENDEX Electricity Markets

7.2.1.1

Day-Ahead Market

APX-ENDEX is one of Europe’s most experienced energy exchanges and operates at both spot so called day-ahead and futures markets for electricity in the Netherlands, the United Kingdom and Belgium.6 The day-ahead market (spot market) of APX-Endex is larger – in terms of traded contracts – than the futures market. Table 7.1 exhibits the activity timeline of the spot market. The spot market (day-ahead market) is based on the two-side auction model. Market members submit their orders electronically until 11:00 prior to the day of operation, after which supply and demand is compared and the market price is calculated for each hour of the following day. Times are subject to changes as soon as the market closing time alters, or if the matching process is postponed. But the thumb rule is between 11:45 and 12:00, the APX Index is published on the website. On the basis of the submitted bids, demand and supply are compared on a daily basis. Classification is done and results in a price for every hour for delivery the next day. Based on these results, the APX Index is determined on a daily basis. To serve market players, APX-ENDEX publishes a volume weighted and a time average index for base load (all hours), peak load (8:00–20:00 GMT þ01:00) and off-peak load (20:00–8:00 GMT þ01:00). The APX Index can be used as a reference price for spot electricity. As well as hourly contracts, flexible block contracts can also be traded. Members of the APX day-ahead market can trade hourly instruments, which are traded for each hour of the delivery day. Individual hourly instruments are traded in Euro/MWh with a precision of two decimals. This is denoted as spot limit orders. In addition to single hours, members can trade a freely definable set of consecutive hourly instruments, being subject to a fill-or-kill principle. This is referred as spot block orders. Spot block orders apply to a consecutive number of single hours, where execution is subject to the fulfillment of a maximum payment condition (buy) or a minimum income condition (sell). Minimum price for all types of orders is 0.01 €, whereas APX-ENDEX may announce a maximum price from time to time. Hourly instruments (single or consecutive) are traded in lots of 0.1 MW 6

The information and tables in Sect. 2.2.1 are obtained from the following website of APX-ENDEX: http://www.apxendex.com/

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(100 kW) or a multiple thereof.7 The minimum price of day-ahead market is 0.01 €/MWh and the maximum 3,000 €/MWh. The hourly instruments are subject to physical delivery of electricity of a constant output on the electricity grid of the Dutch Hub. Therefore, members are required to enter into and maintain a PV with TenneT and to make nominations to TenneT under the PV contract.8 Alternatively, members can designate a third party – being recognized by TenneT as a PV – to make nominations on their behalf.

7.2.1.2

Futures Market

The APX-ENDEX futures markets run on an Internet-linked trading system based on mature and proven technology provided by Trayport. The trading system is widely accepted by the energy community and is known for its user-friendliness while also being easy to implement. Liquidity providers, who guarantee a constant supply of bid and ask prices within certain spread limits, support the exchange. On 29 April 2009, APX-ENDEX introduced the power peak load (8–20). Since then, the 16 h peak load (7–23) contracts can only be registered for the OTC Clearing Service. APX-ENDEX continues to publish reference prices for the 16 h until 31 December 2013. On that date, all of today’s listed contracts for the 16 h peak load (7–23) will be expired. For OTC Clearing Service purposes, new month and quarter contracts in the 16 h peak load definitions and delivery periods up to 31 December 2013 will remain to be introduced and priced. Table 7.2 below provides more detailed information about the period covered, opening and closing times for base load contracts for the Netherlands (NL), Belgium (BE) and the United Kingdom (UK) that operates in APX-ENDEX market. Members of the APX-ENDEX futures markets enjoy the benefits of netting possibilities and do not have to worry about counterparty risk, as all futures traded on the exchange are automatically cleared by the clearing house, European Table 7.1 Activity timeline of the spot market Time activity Time: GMT þ01:00 Day prior to day of Until 11:00 receive bids from Participants operation 11:00 market closure Immediately after matching and until 11:45 individual matching results available Daily settlement at 16:00 12:00 APX-ENDEX submits spot schedules (E-programs) to TSO Between 11:45–12:00 the APX Index is published on the website Once a week Financial clearing 7

In lots of 0.1 MW means, in pieces of 0.1 MW. In this vein: 0.1, 02 MW, etc. The Electricity Act stipulates that all connected parties must arrange their own programme responsibility (PV). The System Code states that they can assign this responsibility to any legal entity recognized by TenneT and for so far they are recognized as program responsible party. 8

From 00:00 A.M. on the first day of the calendar until 24:00 day of the calendar

5 Calendars ahead

From 00:00 A.M. on the first day of the calendar until 24:00 day of the calendar

3 Calendars ahead

From 23:00 GMT on the Sunday immediately preceding the first day of the contract until 23:00 GMT on the last day of the contract

From 23:00 GMT on the Sunday immediately preceding the first day of the contract until 23:00 GMT on the last day of the contract

From 23:00 GMT on the Sunday immediately preceding the first day of the contract until 23:00 GMT on the last day of the contract

4 Quarters ahead

4 Seasons ahead

on the last

on the last

3 Months ahead

ENDEX power UK base load

P.M.

From 00:00 A.M. on the first day of the quarter until 24:00 day of the quarter

4 Quarters ahead

on the last

on the last

on the last

P.M.

P.M.

From 00:00 A.M. on the first day of the month until 24:00 day of the month

3 Months ahead

ENDEX power BE base load

P.M.

From 00:00 A.M. on the first day of the quarter until 24:00 day of the quarter

6 Quarters ahead

on the last

P.M.

P.M.

Period covered

ENDEX power NL base load 6 Months ahead From 00:00 A.M. on the first day of the month until 24:00 day of the month

Table 7.2 ENDEX power futures Contract

16:30 GMT, 3 business days prior to the first day of the contract; cascades into 1 quarter and 3 month contracts

16:30 GMT, 3 business days prior to the first day of the contract; cascades into 3 month contracts

16:30 GMT, 2 business days prior to the first day of the contract; cascades into 28, 35 or 42 day contracts

17:30 on expiration day; cascades into 3 Months and 3 Quarters

17:30 on expiration day; cascades into 3 Months

17:30 on expiration day; moves into physical delivery

17:30 on expiration day; cascades into 3 months and 3 quarters

17:30 on expiration day; cascades into 3 Months

17:30 on expiration day; moves into physical delivery

Closes for trading

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Commodity Clearing (ECC), and the clearing members. Moreover, members can also clear their bilateral or OTC traded futures via the OTC clearing service. At expiry date, all net positions will be physically delivered. ECC will nominate on a daily basis the net position to the respective grid operators. A counterparty that requests to take its position into physical delivery needs to have all the arrangements in place with the respective grid operator or must have entered into a third-party agreement that will act as an agent on behalf of the counterparty. A counterparty that does not want to be involved in physical delivery can sign a close-out agreement with the clearing house. In this agreement, the counterparty assures that it will close all open positions before expiry date.

7.3

The Relationship Between Spot and Futures Prices

In literature it is particularly examined whether futures prices are unbiased predictors of spot prices. The early studies in the commodity markets focus on the cost of carry model in which futures price is represented as: Ft ¼ St eðrþudÞðTtÞ

(7.1)

where Ft is the futures price at time t, St is the spot price at time t, r is the risk free interest rate, u is the storage cost, d is the convenience yield, T is the expiration date of the futures contract and T  t is the time to expiry of the futures contract.9 In practice the cost of carry model has difficulties due to the unobservable nature of storage costs and convenience yield which can be defined as the benefit from owning the physical commodity that is not obtained by holding a futures contract. For a non-storable commodity like electricity, the cost of carry model is not appropriate, as one could not really buy more today, store it and consume it tomorrow to take advantage of the information. The risk premium model is the second pricing theory that explains the behavior of spot and futures prices. The price of futures contract are modeled in terms of expected spot price (E(St þ T)): Ft ¼ EðStþT ÞeðriÞ

(7.2)

where i is the risk-adjusted discount rate for the commodity. According to this theory, the futures price is only equal to the expected future spot price when the risk premium is zero. (r  i) equals to the risk premium (p) in the model. Positive risk premium (p > 0) is observable in the market if the commodity return i is greater than risk free rate r (i > r). The risk premium model is named as ex-ante model given that spot prices is expected but not realized as in the case of cost of carry 9

For a proof of the cost-of-carry model using an arbitrage argument, see Hull (1993, Chap. 3).

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Futures Price

Expected Future Spot Price

Contango

Normal Backwardation Maturity

Fig. 7.2 Contango and backwardation in the futures market Source: http://www.investopedia.com/articles/07/contango_backwardation.asp

model which takes the actual or ex-post spot prices in the model (Botterud et al. 2010). (Normal) backwardation is used to exhibit when the expected spot price exceeds the futures price (p > 0). Contango is used to describe the opposite condition when the futures price exceeds the expected future spot price (p < 0). Figure 7.2 above illustrates the contango and backwardation positions. Consider a futures contract that we buy today, due in exactly 1 year. Assume the expected future spot price is $60 (see the blue flat line in Fig. 7.2). In case the today’s futures price is above the spot price (e.g. $90) we have a contango scenario (red line). At the other hand when the today’s futures price is lower than the spot price (e.g. $ 40), we have a normal backwardation (green line). Unless the expected future spot price changes, the contract price must drop in case of contango and increase in case of normal backwardation. Backwardation occurs when the futures prices for short maturities are more expensive than those maturing later (Pilipovic 1998). In this market, generally more risk-averse producers than risk-neutral producers market opt to hedge their products in the futures market. This would probably result in futures prices being lower than the expected future spot price. The opposite relation named contango would occur when the demand side is the most risk-averse and hence cause excess demand (Botterud et al. 2002). For seasonal commodities such as natural gas, electricity or agricultural commodities, futures price are largely governed by seasonal demand or supply resulting a high seasonal premium on futures contracts maturing during periods of high demand or low supply. For instance in 2005–2006 for oil futures, neither backwardation nor contango could be observed, but a humpshaped forward curve is detected due to hedgers and new investors coming into the market to defend themselves from uncertainty. Generally they shift their contract positions to the next contract period called ‘rollover’ which could create positive or negative yield depending on the shape of the forward curves (Borovkova and Geman 2008). When futures prices deviate from the expected future spot prices,

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the sum of expected roll return and expected spot return is different from zero. Roll return explains on average no less than 50% of the variation in observed futures returns. For some commodities, this percentage is even substantially higher (Kat and Oomen 2006). Fama and French (1987) find evidence of backwardation when 21 commodities (agriculture, wood, animal and metal products) are matched as portfolios that exclude oil. In energy markets, Pindyck (2001) probes the futures markets for petroleum products (crude oil, heating oil, and gasoline) and supports for the backwardation theory in these markets. Backwardation mostly occurs when the variance of spot price is high, which increases the convenience yield and reduces the futures price compared to the spot price. Wei and Zhu (2006) analyze the U.S. natural gas market and through comparing spot prices and monthly futures prices for the period 1991–2003, they find a positive convenience yield which depends on the level and variability of the spot price. They also find that the forward price is not an unbiased predictor of future spot prices as there is a significant positive risk premium. Considine and Larson (2001) also find rather strong support for the presence of a positive risk premium in natural gas and crude oil markets by showing that the risk premium rises sharply with price volatility. Milonas and Henker (2001) study the international oil markets and find a positive convenience yield exhibiting strong yearly and monthly seasonality due to supply/demand imbalances and a negative function for the storage level. To sum up, the empirical research carried out on petroleum markets finds evidence to support a positive convenience yield and risk premium. In the electricity market, Bessembinder and Lemmon (2002) presents an influential equilibrium model implying that the forward power price is a downward biased predictor of the future spot price if expected power demand is low and demand risk is moderate. However, the equilibrium forward premium increases when either expected demand or demand variance is high, because of positive skewness in the spot power price distribution. Their preliminary empirical evidence indicates that the premium in forward power prices is highest during the summer months. Longstaff and Wang (2004) obtain consistent results with Bessembinder and Lemmon (2002) model. They find that the day-ahead price on average exceeds the real time price corresponding to a negative risk premium. The difference between forward and spot price changes systematically through the day. Botterud et al.’s (2002) findings show that the futures price on average exceeds the spot price and there is a negative risk premium in Nord Pool area. Shawky et al. (2003) investigate futures with delivery in the region of California-Oregon traded on the NYMEX and find positive risk premium covering the years 1998 and 1999. Data from the Nord Pool are again analyzed by Lucia and Torro (2008). Their dataset extends from the year 1998–2007 and consists of the four closest to delivery weekly futures. The authors find significant positive risk premium. Furio and Meneu (2010) investigate the Spanish electricity market for long-term risk premium, using both the ex-ante and the ex-post model. Covering a sample period between 2003 and 2006, they find that the ex-post risk premium is negative but the ex-ante risk premium is positive. Marckhoff and Wimschulte (2009) analyze CFD

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at the Nord Pool. CFD allow to hedge against price differences among different delivery areas and started to trade at the Nord Pool at the end of 2000. The authors find significant short-term positive risk premium and negative long-term risk premium. Wilkens and Wimschulte (2007) analyze EEX futures between 2002 and 2004 by restricting their study to monthly futures with a maturity of up to 6 months. After estimating ex-ante risk premium based on the model by Lucia and Schwartz (2002), they compare their results with ex-post risk premium. The authors find positive risk premium on the futures market of the EEX from both an ex-ante and an ex-post perspectives. The main problem in the risk premium models mentioned above is that the expected spot prices are not observable. The ex-ante risk premium models always require a specification of a spot price model (Pietz 2009). By reason of forecasting difficulties and different information of agents about ex-ante predictions, most studies in the commodity markets have focused on the Fama (1970) weak form market or speculative market efficiency tests of the form: St ¼ a þ bFti þ et

(7.3)

where St is the observed spot price at time t and Fti is the futures price at time ti. In this approach market efficiency requires that the futures prices should be unbiased predictors of future spot prices. Simple empirical tests of the speculative efficiency hypothesis are based on the joint hypothesis a ¼ 0, b ¼ 1. For example, Crowder and Hamed’s (1993) examination of NYMEX crude oil futures contracts support the simple efficiency hypothesis. A common explanation for the rejection of the simple efficiency hypothesis has been the existence of a risk premium. Using the 3-month futures prices of the West Texas Intermediate (WTI) contracts, Moosa and Al-Loughani (1995) reject the speculative market efficiency hypothesis and find that arbitrage plays an important role because of the time varying risk premium during the Iraqi invasion of Kuwait in August 1990.

7.4

Data and Methodology

Our methodology is adopted from Fama (1984). By enhancing the simple efficiency model, Fama (1984) tests two regression equations in the foreign exchange market: Stþ1  St ¼ a1 þ b1 ðFt  St Þ þ e1;tþ1

(7.4)

Ft  Stþ1 ¼ a2 þ b2 ðFt  St Þ þ e2;tþ1

(7.5)

where (Ft  St) is the basis at time t, St þ 1 is the observed spot price at time t þ 1 and Ft is the futures price at time t, and e1,t þ 1 and e2,t þ 1 are the residual terms. The dependent variable Stþ1  St in (7.4) represents the change in spot prices while the dependent Ft  Stþ1 in (7.5) is the risk premium.

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We do not have to calculate the risk premiums or forecast the spot prices in this model as compared with the above efficiency models discussed in Sect. 7.3. If b1 is significantly different from zero then we assert that the basis (Ft  St), which is the difference between spot and futures prices at time t, contains information about the changes in spot price. Moreover, if b2 is significantly different than zero, the premium (Ft  Stþ1) has variations according to the basis (Ft  St). The basis should not contain any information about either the risk premium or the changes in spot prices for the efficiency. When pricing commodity contracts, the futures price determined in time t could be lower (higher) than the current spot price, if the expected spot prices in time t þ 1 are expected to be lower (higher). If changes in the futures price are independent of the return on the market, the futures price is the expected spot price and the market is efficient (Black 1976). Importantly (7.4), in the model tests the speculation whereas (7.5) tests the arbitrage in the market. If the basis in time t affects the spot prices from time t to t þ 1 according to (7.4), the spot market prices change speculatively. On the other hand, If the basis in time t affect the risk premium according to (7.5), arbitrage is possible in the market since the futures prices is not an unbiased predictor of spot prices. Moosa and Al-Loughani (1995) explains that if the basis were greater than zero in the crude oil market, the futures price would differ from the spot price by an amount equal to the cost of carriage for oil. This creates a riskless profitable situation called arbitrage in the market. Arbitrage occurs through buying cheap spot (futures) and selling expensive futures (spot) in the contango (backwardation) market. If the basis is not equal to the cost of carry, then factors other than arbitrage equal to the risk premium will affect the futures price or expected spot prices in the market speculatively. We analyzed (7.4) and (7.5) to detect the relationship between spot and futures prices of APX-ENDEX electricity market. Day-ahead and futures prices data is obtained from APX-ENDEX. Our dataset consists of: – Spot electricity prices between 2007 and 2009. – End of day settlement prices of mostly traded electricity futures contracts that have yearly, monthly and quarterly time to delivery in the calendar year 2007 (CAL07), calendar year 2008 (CAL08) and calendar year 2009 (CAL09). We restrict our regression analysis to mostly traded base load futures with 1 year time to delivery since we have 30 monthly and 10 quarterly available data within 2007–2008 periods. Specifically, we used the calendar year 2008 (CAL08) as time to delivery because of liquidity considerations. The ENDEX trades volume statistics in Table 7.3 above indicates the number of trades and megawatt hours traded in the futures market is the highest as of 41,239,364 MWh in the year 2008. Table 7.3 ENDEX trades volume statistics Period Number of trades 2007 1,701 2008 2,423 2009 970

MW’s traded 8,623 11,459 4,402

MWh’s traded 27,777,524 41,239,364 15,013,909

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Table 7.4 reports the descriptive statistics of the percentage basis (Ft  St), risk premium (Ft  Stþ1) and change in spot prices (Stþ1  St) for CAL08 contracts. It is seen from Table 7.4 that the basis and the risk premium changes negatively, namely: 15.76% and 15.29% on average respectively. These values in APXENDEX denote that the futures prices are lower than the spot prices in both 2007 and 2008. The negative risk premium found in APX-ENDEX is consistent with the normal backwardation hypothesis. Negative returns are realized for the demand side investors due to the dominance of risk-averse producers who want to hedge their electricity in the market. The futures contract prices determined in 2007 could be lower than the 2007 spot price, if the expected spot prices in time 2008 are expected to be lower according to the contract pricing rules. Spot prices change 3.6% positively in 2008, and this result is attributable to speculative motives in this high demand period. But the expected trends in spot prices alone are not a source of return to an investor in futures. If the futures price is set below the expected future spot price, the futures price will tend to rise over time, providing a return to investors in futures because a futures contract is only a bet on the future spot price (Gorton and Rouwenhorst 2006). The risk premium in 2008 is graphed in Fig. 7.3. The premium does not seem to be close to zero and presents a volatile structure. In other words, the market Table 7.4 Descriptive statistics: basis, risk premium and change in spot Risk premium: (Ft  Stþ1) Change in spot: (Stþ1  St) Basis: (F t  St) Mean 0.157602 0.152996 0.036042 Median 0.169476 0.169243 0.040857 Maximum 0.544004 1.000000 1.469161 Minimum 0.951135 0.948891 1.000000 SD 0.263915 0.273470 0.340866 Skewness 0.151608 0.111318 1.697783 Kurtosis 3.367725 4.215502 7.280979 Jarque-Bera 2.347332 15.77913 308.5188 Probability 0.309231 0.000375 0.000000 Observations 248 248 248 Ft is the futures end of day settlement prices in 2007 for contracts in 2008, and St is the observed spot price at time 2007 and Stþ1 is the observed spot price at time 2008

Fig. 7.3 Risk premium

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participants do not have an unbiased prediction of the future spot prices that can be inefficient consequences for the contract holders.

7.5

Empirical Results About the APX-ENDEX Electricity Market

Tests for (7.4) and (7.5) require that the data series be stationary.10 We checked stationarity by the Augmented Dickey Fuller (ADF) and Phillips-Peron (PP) tests. The stationarity checks are shown in the following Table 7.5. The ADF and PP test results in Table 7.5 show that the basis, risk premium and the change in spot prices variables are significant according to the critical MacKinnon p values and do not have a stationary problem. So, we may use these variables for the Fama regressions. The PP test results are more robust in t statistics in here by adjusting serial correlation of errors. The estimation results of (7.4) and (7.5) are reported in Table 7.6. All a and b coefficients are significantly different from zero at 1% level. Based on these results we conclude that the basis (Ft  St) effects and contains information for both change in the spot prices (St þ 1  St) and the risk premium (Ft  St þ 1). Equation (7.4) signals that the market is open to speculation according to the basis and (7.5) indicates that the arbitrage is possible. Both b1 and b2 are associated positively with the change in spot prices and risk premium at 1% significance level. The findings in Table 7.6 illustrates that a 1% increase in the basis has an expected increase in the spot prices of 0.59 %, while a 1% increase in the basis has an expected increase in the risk premium by 0.40%. In addition the significant a1 and a2 values features the market is depends on the other factors that could change the spot prices and the risk premium. Hence the regression results in Table 7.6 deny efficiency for the calendar year 2008 (CAL08). Moreover, in Table 7.7 Wald test results about the restrictions of a and b coefficients are presented. Table 7.5 Stationarity tests ADF PP Basis 2.764115* 10.30128*** Risk premium 1.920964 9.479170*** Change in spot 33.43907*** 10.70468*** The values reported in the table represent the t statistics for the ADF and the adjusted t statistics for the PP test ***Significance at 1% level; **significance at 5% level; *significance at 10% level

10

Crowder and Hamed (1993) tests the arbitrage equilibruim in the crude oil market with cointegration analysis because of the nonstationary data. According to their analyses, spot rates, futures rates and risk free market rate should cointegrate if the riskless arbitrage opportunities are not possible. The expected return could only equal to the risk free rate if there is no arbitrage. But they did not support the arbitrage efficiency hypothesis.

7 The Electricity Market, Day-Ahead Market and Futures Market Table 7.6 Fama regression results Equation (7.4) a1 5.249371*** [4.633367] Equation (7.5)

a2

5.249371*** [4.633367] t statistics are reported inside the parentheses ***Significance at 1% level

b1 0.594759*** [9.731418]

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F-stat 94.70050

b2 0.405241*** [6.630530]

43.96393

Table 7.7 Wald test of Fama model Equation (7.4) a1 ¼ 0, b1 ¼ 1 64.42835

b1 ¼ 1 43.96393

a1 ¼ 0 21.46809

a2 ¼ 0, b2 ¼ 1 47.39453

B2 ¼ 1 94.70050

A2 ¼ 0 21.46809

Equation (7.5) F-values reported

Upon the significant F-test results for the restrictions about (7.4) and (7.5) indicated in Table 7.7, we reject all the restrictions that support market efficiency. Both jointly and individually tested, the estimated constant is significantly different from zero and the slope coefficient is significantly different from one. The basis changes both the spot prices and the risk premium.

7.6

Conclusion

In this chapter we firstly depict the European electricity market and make much of our interest to the organized electricity exchanges which are very important for the hedging opportunities they create with lots of financial instruments such as forwards, futures, options or swaps etc. Day-ahead and futures electricity market of APX-ENDEX which is the best-known organized power exchanges in Europe is then introduced. Then we discuss the important theoretical models that display the relation between spot and futures prices. Our empirical literature survey about efficiency for electricity futures reveals that the models so far are inadequate to reach a conclusion that whether the market is efficient or not. The examined models cannot go further beyond testing whether futures prices are unbiased predictors of spot prices or not. The positive or negative risk premium (contango or backwardation) calculations differ according to the investigated period and the forecasts for the unknown expected spot prices. We propose the Fama’s (1984) regression model for efficiency tests in the electricity futures market. Rather than just calculating the risk premiums directly and explaining that the market is not efficient because of these risk premiums as in the previous literature, this analysis tests the effects of the difference between spot and futures prices on the risk premiums and changes in spot prices.

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Specifically we tested the efficiency in APX-ENDEX futures market for the 1-year contracts that will be delivered in 2008. We show that the electricity market has negative risk premiums and backwardating in this period since the futures prices are lower than the spot prices. Both risk premiums and spot prices vary with the basis consistent with the pricing rules that is undesirable for the efficiency case. Arbitrage and speculation plays an important role in the market. However we do not have storage opportunities and cannot calculate the opportunity cost of electricity in the market as in crude oil market tested by Moosa and Al-Loughani (1995). Regarding the models tested from hitherto, the risk premium fluctuates as of the unpredictable difference between spot and futures electricity prices. It will be interesting for us to conduct a further research to explain the reason behind the unpredictable difference between spot and futures prices in the electricity market or why and how arbitrage and speculation could exist. As we have shown in Dorsman et al. (2010) market coupling reduces risk and price declines in the highest price countries. Markets with less price volatility are better to forecast. Nevertheless, we have to conclude that after the market coupling, evidence is found that the markets are not efficient. A possible cause for the inefficient findings can be that the number of traded contracts on the futures market is much smaller than on the related day-ahead market. Release of new information may quicker lead to price adjustments in larger markets than in smaller markets. On the spot market trading takes place in hourly contracts. Every day there are 24 different contracts in APX-ENDEX for every hour of the next. On the futures market there are have monthly, quarterly and yearly contracts. The number of different contracts on a certain day is more on the spot market. Also this increases the illiquidity of the futures market when it is compared with the spot market (day-ahead market). The solution to work with illiquid contracts is not easy. Benth et al. (2007) for instance derives the OTC forward curves for illiquid contracts. However, our regression findings signal much more facts than the liquidity or high demand cause for negative risk premiums. If the market expect spot prices to fall (rise) and, correctly reflecting expected future spot prices, the futures curve is therefore downward (upward) sloping. However, this relation can change with rolling strategies of the portfolio manager, who invests the different electricity futures commodities through considering their both liquidity and volatility. The effects of liquidity on arbitrage and speculation may differ from contract to contract that needs to deserve more research in the electricity markets which has not traded on power exchanges frequently yet as we compare the other products such as crude oil.

References Arciniegas I, Barrett C, Marathe A (2003) Assessing the efficiency of US electricity markets. Utilities Policy 11:75–86 Bessembinder H, Lemmon M (2002) Equilibrium pricing and optimal hedging in electricity forward markets. J Finance 57:1347–1382

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Benth FE, Koekebakker S, Ollmar F (2007) Extracting and applying smooth forward curves from average-based commodity contracts with seasonal variation. J Derivatives 15(1):52–66 Bierbrauer M, Menn C, Rachev S, Tr€ uck S (2007) Spot and derivative pricing in the EEX power market. J Bank Finance 31:3462–3485 Black F (1976) The pricing of commodity contracts. J Financ Econ 3:167–179 Borenstein S, Bushnel J, Knittel CR, Wolfram C (2001) Trading inefficiencies in California’s electricity markets. NBER Working Papers 8620, National Bureau of Economic Research, New York Borovkova S, Geman H (2008) Forward curve modeling in commodity markets. In: Geman H (ed) Risk, management in commodity markets. Wiley Finance, Chichester, pp 9–31 Botterud A, Bhattacharyya B, Ilic M (2002). Futures and spot prices, an analysis of the Scandinavian electricity market. Working Paper, MIT, Cambridge Botterud A, Kristiansen T, Ilic M (2010) The relationship between spot and futures prices in the Nord Pool electricity market. Energy Econ 32(5):967–978 Brand H, Thorin E, Weber C, Madlener R, Kaufmann M, Kossmeier S (2002) Market analysis and tool for electricity trading. OSCOGEN Project Deliverable D5.1a, March Considine TJ, Larson DF (2001) Risk premiums on inventory assets: the case of crude oil and natural gas. J Futures Market 21(2):109–126 Crowder WJ, Hamed A (1993) A cointegration test for oil futures market efficiency. J Futures Market 13(8):933–941 Deng SJ, Oren SS (2006) Electricity derivatives and risk management. Energy 31(6–7): 940–953 Dorsman AB, Karan MB, Telatar E, Umutlu G (2010) Market coupling of electricity markets. Seventeenth Annual Conference of the Multinational Finance Society, Spain Fama EF (1970) Efficient capital markets: a review of theory and empirical work. J Finance 25:383–417 Fama EF (1984) Forward and spot exchange rates. J Monetary Econ 14:319–338 Fama FF, French KR (1987) Commodity futures prices: some evidence on forecast power, premiums and the theory of storage. J Bus 60(1):55–73 Furio D, Meneu V (2010) Expectations and forward risk premium in the Spanish deregulated power market. Energy Policy 38(2):784–793 Gorton G, Rouwenhorst KG (2006) Facts and fantasies about commodity futures. Financ Analysts J 62(2):47–68 Herraiz AC, Monroy CR (2009) Analysis of the efficiency of the Iberian power futures market. Energy Policy 37:3566–3579 Hull JC (1993) Options, futures, and other derivative securities, 2nd edn. Prentice Hall, Englewood Cliffs, NJ Kat HM, Oomen RCA (2006) What every investor should know about commodities, part I: univariate return analysis, Cass Business School Research Paper. SSRN: http://ssrn.com/ abstract¼87836 Longstaff FA, Wang AW (2004) Electricity forward prices: a high-frequency empirical analysis. J Finance 59(4):1877–1900 Lucia J, Schwartz E (2002) Electricity prices and power derivatives: evidence from the Nordic power exchange. Rev Deriv Res 5:5–50 Lucia JJ, Torro H (2008) Short-Term electricity futures prices: evidence on the time-varying risk premium. Working Paper, Department of Financial Economics, University of Valencia, Feb. 2008, available at: http://www.ivie.es/downloads/docs/wpasec/wpasec-2008-08.pdf Marckhoff J, Wimschulte J (2009) Locational price spreads and the pricing of contracts for difference: evidence from the Nordic market. Energy Econ 31:257–268 Milonas NT, Henker T (2001) Price spread and convenience yield behavior in the international oil market. Appl Financ Econ 11:23–36 Moosa IA, Al-Loughani NE (1995) The effectiveness of arbitrage and speculation in the crude oil futures market. J Futures Market 15(2):167–186

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Pietz M (2009) Risk premia in the German electricity futures market. Working Paper, Technical University of Munich. Available at SSRN: http://ssrn.com/abstract=1400120 Pilipovic D (1998) Energy risk, 1st edn. McGraw-Hill Professional, New York, NY, p 248. ISBN 0786312319 Pindyck RS (2001) The dynamics of commodity spot and futures markets: a primer. Energy J 22(3):1–29 Shawky H, Marathe A, Barrett C (2003) A first look at the empirical relation between spot and futures electricity prices in the United States. J Futures Mark 23:931–955 Sioshansi FP, Altman A (1998) Wholesale power marketing in restructured electricity markets. Energy Policy 26(14):1099–1104 Wei SZC, Zhu Z (2006) Commodity convenience yield and risk premium determination: the case of the U.S. natural gas market. Energy Econ 28:523–534 Wilkens S, Wimschulte J (2007) The pricing of electricity futures: evidence from the European energy exchange. J Futures Mark 27:387–410 Yang H, Zhang Y, Liu S, Luo X (2009) Empirical research on efficiency of the electricity futures market. Int J Emerg Electr Power Syst 10(2):1–15

Part III

Regulations

.

Chapter 8

The Disintegration of the Concept of Sovereignty and the Energy Sector in the Europe Jennifer Westaway and John Simpson

Abstract The concept of sovereignty in international law addresses the principle that a sovereign state, through its ruler or government has the right to determine and enforce the laws which it believes are appropriate for its own territory, and that it has the further right to protect its interests at an international level, whether those interests be from a trade or security perspective. However, the concept of sovereignty operates within a broader framework of international law, part of which is the rule of law in international affairs. This involves the existence of a comprehensive system of law which provides predictability as to the legal consequences of conduct, and the effective and impartial application of the law. This then relies upon the ‘adoption’ of a form of sociality, which implies that sovereign states will act in a manner which maximises optimal co-operation between regimes and/or governmental structures. The European Union (EU) has sought, by virtue of the notion of legislative networks to dissolve the concept of individual state sovereignty, thus weakening the ability of sovereign states to determine that which is most appropriate to its own territory, and seeking the imposition of policies and laws which arguably reflect common interests, such as the development of the energy sector. However, the recent global financial and economic crises have highlighted that economic co-operation is far more fragile and problematic than previously thought, and this combined with the fact that energy sources are largely located in sovereign states not part of the EU, some of which have a high ranking of political risk, arguably poses a new and real problem. This chapter argues that the concept of sovereignty is central to sustainable energy policy development in the EU. Accordingly there will be an examination of the concept of sovereignty, its relationship with political risk, and this will be followed by an econometric analysis by using country risk oil industry stock market data and related political risk indicators. J. Westaway (*) School of Business Law & Taxation, Curtin University of Technology, Perth, WA, Australia e-mail: [email protected] J. Simpson School of Economics & Finance, Curtin University of Technology, Perth, WA, Australia A. Dorsman et al. (eds.), Financial Aspects in Energy, DOI 10.1007/978-3-642-19709-3_8, # Springer-Verlag Berlin Heidelberg 2011

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The reader should note that this paper is primarily written from a legal perspective, so the language and concepts as used throughout is reflective of this perspective. Furthermore, inclusion of the econometric analysis is illustrative of the notion that the energy sector is highly influenced by the actions of sovereign states and by the political risk attached to those actions. Keywords Economic co-operation
Energy
Political risk
Sovereignty
Stock market

8.1

Introduction

The recent and ongoing turmoil in financial markets has highlighted a significant problem for the European Community (EC), as it has struggled to maintain policy cohesiveness and provide support to the Euro given the pressure on the currency in international markets – sovereign risk. Sovereign risk can be simply defined as the risk of default by a government on its debt obligations. This chapter proposes that, limited to a focus on debt obligations, sovereign risk fails to address the broader issue – that of political risk, which impacts directly upon a government’s willingness to provide a political and economic environment conducive to economic growth. If however, a government lacks sovereign capacity to act in its own interests, then arguably there exist real limitations on a government’s ability to implement measures or engage in economic activity which it may regard as in its own sovereign interest. Given the fiscal and ideological complexities of the EU and the divergence in economic capacity amongst its members, this chapter proposes that there are critical lessons to be learnt with respect to the energy sector, which have their fundamental basis in the concept of sovereignty and its currency as a political and economic norm within the EU. In this first part of this chapter the historical and definitional concept of sovereignty will be discussed. In Part II, the relationship between EU Law and State Law will be discussed. This will be followed by an overview of the energy sector and its regulatory environment. A brief study follows that examines the interaction of energy sector stock market data in the key Western economies of the European Monetary Union (EMU), the UK and the USA and includes the impact on market models of pure political risk ratings in these countries. The chapter will then conclude with an assessment of the risks to the energy sector posed by the dissolution of the concept of sovereignty within the European Union for those countries whose economic wealth largely depends either upon a robust and aggressively marketed energy sector or the ability to contract with non European Union countries for security of energy supplies. This will be done by the inclusion of stock market data addressing political risk within the European Union and other major Western economies (the UK and the USA) and what this represents from the perspective of sustainable and secure energy resources for member states of the EU.

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133

The Concept of Sovereignty

Sovereignty as a concept has been the subject of much academic discussion and in order to understand how the dissolution of the concept within the EU has the potential to impact upon the energy sector. It is first important to look at its foundation as a concept, the various definitions ascribed to it, and its role in international relations. Prior to the Treaty of Westphalia in 1648,1 there existed a feudal system with overlapping jurisdictions of ill-defined political hierarchy, with claims to authority based largely in personal ties and loyalty rather than defined territory. Competition for loyalty was diverse and intense between church and state, king and emperor, feudal lords, princes, counts and dukes. Taxation and military service could be demanded of any one individual from several different authorities within the one territory. Claims to authority were largely based upon a divine right, drawn from spiritual connections, including legitimacy of lineage to the Roman Catholic Church. There existed no separation between secular and spiritual authority, with people the primary object of subjection to asserted authority rather than territory. The emergence of long-distance trade in the middle ages created a need for currency, contracts, precision in measurements, including weight, time, jurisdiction and property. This saw the emergence of a new social order, centred on town dwellers who sought both political allies and contractual depersonalised business relationships, which did not fit within the framework of the existing feudal order. Together with advancements in scientific knowledge, the rise of the merchant class, and the Protestant Reformation, the legitimacy and authority of the Roman Catholic Church was challenged and rule on behalf of the people by institutions that inspired respect and thus had the ability to enforce rules, became the important antecedents to sovereignty. Additionally, changes in practical political balances saw the need for a ‘sovereign state’ able to wage war efficiently and effectively, as well as conduct trade and this led to a form of political organisation which sought to delegitimise parties from this new ‘international’ order if they were not of a like mind. According to Cusimano (2000) this acceptance of a new political order and the notion of sovereignty saw the end of the association of church and state, albeit it is arguable that the association does still remain and the process of disassociation is not 1

The Treaty of Westphalia arose as a consequence of the Thirty Years War of 1618–1648. This war, described as probably the most disastrous war in Europe prior to the twentieth century was essentially a war between Protestant and Catholic Princes. The Protestant Princes opposed the Catholic Hapsburg Emperor and formed alliances with other foreign states. The war, whilst in appearance seemingly based on religious grounds, was driven more by the ambitions of an emergent France and the fading hegemony of an overextended Spain. The Treaty, signed at the conclusion of the War, is recognised as the starting point for the modern state system. It provides, inter alia, European principalities with the right to make foreign alliances and gave these states significant control over internal affairs. It is said that the Treaty was the progenitor of modern international law and represented the introduction of the association of the concept of sovereignty with the autonomy of the ‘state’ (Currie et al. 2007).

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complete. Sovereignty meant that only one political authority would have the power to tax or demand military service, and this authority was not drawn from God or Church but rather from exclusive jurisdiction over territory. Individual identity was now not only based on geography but also subject to clearly defined political authority based upon territorial jurisdiction. According to the Oxford English Dictionary (2009), the first reference to the ‘sovereign state’ appears in Shakespeare’s King John from 1595, where it is written: “I am too high-born to be propertied, To be a secondary at control, Or useful serving-man and instrument, To any sovereign state throughout the world.” Sovereignty is arguably the basic norm, Grundnorm, upon which a society of individual states has its political foundation. (Jackson 1999). Sovereignty as a concept it is therefore a constitutional arrangement identified by territorial jurisdiction claimed by individual states within which state authority can be exercised to the exclusion of all other states. It is a legal institution which authenticates the right of governments of independent states to exercise authority domestically and internationally regarding matters which can be directly claimed politically as the lying to the authority of that individual state. Another definition provided by Cusimano (2000) addresses Brierly in his seminal work The Law of Nations states that there are five basic norms of sovereignty: “self-preservation, independence, equality, respect and intercourse” (1938, p.40) which he claims are distinctly different from the norms of theocratic or imperialistic polity where the norms are more accurately described as being paternalistic, interventionist, and unequal. Cusimano (2000) also sees the core meaning of sovereignty as being the final and absolute political authority belonging to a political community, the underpinning of which is the assumption that a government of an individual state is supreme and independent, as evidenced and defined by the state’s constitution. In this respect, sovereignty has both an internal and external perspective – internally, sovereignty provides the legal basis upon which all those within the state’s territorial jurisdiction are subject to the laws and policies of the state; whilst externally, sovereignty is the fundamental authority relationship between individual states, as defined by international law (Jackson 1999). As was stated in the Island of Palmas2 case: Sovereignty in the relations between states signifies independence. Independence in regard to a portion of the globe is the right to exercise therein, to the exclusion of any other state, the functions of a state. The development of the national organisation of states during the last few centuries, and, as a corollary, the development of international law, have established this principle of the exclusive competence of the state in regard to its own territory in such a way as to make it the point of departure in settling most questions that concern international relations.

There is another notion of sovereignty which originated in Europe and is therefore relevant to the context of this chapter – that of unitary sovereignty.

2

Netherlands v. United States of America 2 RIAA 83; 4 ILR 3 as cited in Blay et al. (2005).

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Jean Bodin3 saw sovereignty as a unified or unitary concept residing absolutely in one place, being perpetual, and unlimited in power, charge and time certain. Bodin’s ‘sovereignty’ was based upon the notion that substantial power would reside in one individual – the monarch. He wrote: “[T]he distinguishing mark of the sovereign is that he cannot in any way be subject to the commands of another, for it is he who makes law for the subject, abrogates law already made, and amends obsolete law.” According to Bodin sovereignty was absolute and unconstrained both externally and internally – the concept of the truly autonomous state – giving the sovereign state the right to make war and peace, which he regarded one of the most important rights of sovereignty as it brought with it the “ruin or salvation of the state.” Bodin’s sovereignty was not however absolute, as all men were subject to the laws of God. Essentially therefore, the author identified that sovereignty is a mix of two concepts – plenary power and autonomy and, subordination of autonomy to a higher code of behavior (Currie et al. 2007). Whilst pure autonomy had its attractions, this concept became to be regarded as unworkable and unfeasible given the need of states within Europe to work together and conduct relations with each other. Thus, there grew an acceptance that states could remain sovereign with respect to territorial jurisdiction, whilst allowing states to negotiate with each other and enter into political and economic alliances. The concept of state sovereignty with exclusive territorial jurisdiction, it is now argued, is somewhat anachronistic and, with respect to the EC, has largely dissolved and has been reconstituted as a new form of global governance and regulation, the full impact of which for the purposes of economic activity, is unknown both conceptually and structurally. This is not to say that sovereignty as a concept is no longer of use, but rather that sovereignty as a concept of a political form is dynamic and should be constantly adjusted to meet the changing needs of not only the EU economy, but also the global economy. As it is argued by Jayasuriya (1999), territorial jurisdiction in relation to economic matters is now largely constrained by the globalisation of social and economic relationships, with greater permeability between the traditional domestic and international boundaries. Whilst globalisation has certainly led to considerable permeability in social and economic relationships, the decisions to engage across borders is essentially still a sovereign one. The terms of engagement whether socially or contractually for the purposes of international trade require the political will of a government, and a willingness of other sovereign states to mutually engage across sovereign borders. As has been seen for many years, sovereignty can be a tool to facilitate interaction or a tool for isolation driven by the sovereign government itself or other sovereign governments seeking to isolate a ‘rogue’ state unprepared to engage on equal terms, such as in the case of North Korea and Zimbabwe, to name but two such states. 3

Jean Bodin (1529/30–1596) was a lawyer, economist and one of the most influential political theorists of the sixteenth century. His seminal work was the Six Books of the Commonwealth, published in 1576, within which he systemised and defined a theory of sovereignty, and some regard him as the ‘father’ of sovereignty. For an interesting discussion of Bodin and his concept of sovereignty, see Beaulac (2003) The social power of Bodin’s ‘sovereignty; and international law.

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The critical issue of sovereignty as exercised in a globalised world takes on an important different perspective when one considers globally significant issues such as energy and finance. The ongoing contagion in financial markets and the complex debates regarding the role of the EU in providing financial assistance to especially its member state Greece, underline the global significance of sovereign decisionmaking. In the case of the EU however, sovereign decision-making is bound up in the legal relationship between member states and the EU.

8.3

The Relationship Between EU Law and State Law

The EU is unique in the world in that it is composed of sovereign nations bound together by a series of treaties into what can be called a supranational entity. The institutional structure of the EU is quadripartite: the EC, being the executive arm of the EU with responsibility of implementing EU policy; the Council of Ministers, being the main policy setting arm of the EU; the European Parliament; and, the European Court of Justice, which functions as the judicial arm of the EU, but with jurisdiction only over European matters. The accession of a state to the European Community (Union) entails its recognition of EU law as constituting valid law within that state, and a further recognition that relevant future decisions by competent Community organs will constitute binding law within that state. There exists a further obligation on state courts to refer matters of interpretation of Community law to the European Court of Justice (ECJ), where a matter of interpretation will have a direct bearing on a decision to be made in those courts. The ECJ claims and indeed exercises authority to invalidate enactments of individual state parliaments if the court is of the opinion that they conflict with EC law (Rabkin 2000). The two-dimensional legal authoritarian structure of the EU – the legal order of the member states and the legal order of the EU – creates the potential for what has been called legal order ‘boundary skirmishes’ (Walker 1998). Member states maintain a claim to ultimate legal authority over all matters of domestic law, while the EU legal authorities claim ultimate legal authority over a broad and somewhat open-ended area of state domestic law which it is claimed corresponds to their own interpretation of the jurisdictional limits of the EU as set out in its constructive treaties. This multilayered legal structure raises various problems, not the least of which are trust, mutual understanding and institutional cooperation. Regulation at a supranational level involving numerous member states is particularly problematic due to the differing political and legal systems of those member states which have been nurtured and have grown within different political cultures (Walker 1998). Further, member states due to this differing political and legal culture have differing social forces and trends, which may or may not be sympathetically aligned with others within the supranational body. Social tensions and unrest, taxation systems,

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social welfare policies, trade performance and employment are just some of the areas where there are clear differences at a political and legal level. A sovereign government, capable of developing and enforcing its own laws and policies over those issues within its territorial jurisdiction, has it is assumed, the social legitimacy to institute those laws. Therefore, such a state will act to articulate the value preferences of its citizens and deliver the material benefits which the government sees as crucial to the success of that state. Related to this issue of social legitimacy is the important concept in international law of ‘state responsibility’ which can be loosely defined as a general set of rules which govern the legal consequences of violations, by states, of their international obligations (Currie et al. 2007). Under this principle, states can held responsible for conduct which is attributable to them, and which causes damage. Whilst this might appear to be a relatively straightforward principle, states are in reality only political-legal abstractions (‘non-persons’) the acts of which are reliant upon others. Hence attributing conduct to a state requires a determination of the rules which define the ‘actors’ whose conduct is representative of that state. The range of such ‘actors’ can be governmental and those entities that are empowered to exercise elements of government authority, such as energy providers and suppliers. States can also have attributed to them conduct of persons (entities) which are not formally affiliated with it on the basis of being a clear representative of that state, a concept known as ‘state responsibility’, a full discussion of which is outside the parameters of this chapter. However, it does go to the heart of sovereignty, as a state in acquiring responsibility under international law, must be conscious of ensuring that those actions attributed to it do not render it liable. Given the complex legal relationship between the EU and its member states, reasoning for maintaining key aspects of sovereignty, if only considered from the perspective of ‘state responsibility’ become clearer and more understandable.

8.4

The Energy Sector

During the last decade, the issue of energy, whether it be the political stability of supplier states, the concentration of available natural resources, or the sustainability of energy sources, has arguably been the issue of most worldwide concern, whether from an environmental, industry or government perspective. Interestingly, for the purposes of this chapter, the EC, despite the introduction of the European Coal and Steel Community and the Euratom Treaty, has not yet formalized a common energy policy. Whether this lack of formalisation stems from a lack of definition as to what constitutes the concept of a European Energy policy, the assignment of competencies to the European government, or a divergence in member states’ goals on such matters as competitiveness, security and sustainability, is yet to be determined. However, this chapter proposes that the heart of debate lies within the concept of sovereignty, and the consequent attitude of member states towards integration of policy and security concerns.

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The first and most significant point is that EC lacks the traditional attributes of power (diplomatic and military) and thus resorts to interdependence as the core of its sovereignty. Market integration, market behavior and market discipline are the key factors which project to the rest of the world that the EC is a unified and sovereign body acting in the interests and with the agreement of member states. The second significant point to make is that the European Treaty does not give the EU, as representative of the EC, any direct powers over energy policy, thus leaving only indirect means of control via market integration and environmental policies which are competencies of the EU via the Treaty. Management of gas and oil resources has been and continues to be within sovereignty (competence) of Member States. Despite the commencement of the EC, Member States have been unwilling to give up their sovereignty in energy matters, as the stakes are regarded as too high from the perspective of national interests in the area of energy dependence and control of resources. This ‘sovereign’ interest in energy largely stems from the significant reliance on national firms (generally public utilities) to take charge of oil and gas supplies and to diversify foreign gas purchases among several supply sources. Central to this is the capacity of these firms, under the policies of national governments, to enter into contracts securing long-term energy supplies and partnerships to develop the necessary infrastructure (Finon and Locatelli 2008). Due to the increasing import dependency of the EU, the growing concentration of energy supplies in a limited number of net-exporting countries/regions in the world and the growing competition among energy consuming states for scarce energy supplies, there is no wonder that the EC wants to manage the growing energy, and specifically gas, dependency of its member states (Scheepers et al. 2007), However, the EU lacks the formal institutional and geopolitical means to do so. The accession of ten new members in 2004 and Romania and Bulgaria in 2007, together with prospective Balkan country entrants, most of which depend on Russia for their gas supplies, has created an ever more pressing need for a joint energy policy, at least from the EC’s perspective. However pressing the perceived need of the EC to speak and negotiate on behalf of member states, major member states, specifically Germany and France, do not perceive any real advantage in ceding additional powers to the EC in relation to energy foreign policy or trade, especially when it involves Russia acting as a geopolitical power with energy. Market regulation by way of market integration is problematic in the EU from two perspectives – the sovereign structural interests of member states and the institutional conditions of decision-making in the EU. As far as the energy sector is concerned, the opening of the market, described as ‘negative integration’ can be pursued by the supranational body of the EU but the regulatory aspects of such an open market are reliant upon explicit political legitimacy to do so being acquired from member states (‘positive integration’) (Scheepers et al. 2007). The consensus required to implement an effective regulatory regime is very high, and given the strongly divergent interests of member states, EU regulation, it is proposed, especially in light of recent euro zone problems, is highly unlikely. The significant economic disparities among Member States and their differing political risk categorisations, which are central to sovereignty and sovereign risk, do not lend

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themselves to a willingness of member states to soften their position with respect to ceding additional powers to the EU, especially in the crucial area of energy. That is not to say that the EC is powerless. The formal powers that are already vested in the EC indicate that there is a willingness to move towards a ‘europeanisation’ of regulation. The competition power of the EC is one of the strongest and clearest examples of how far-reaching the powers of the EC can be vis-a`-vis Member States. Eberlein and Grande (2005) notes that the competition powers of the EC reach deep into the regulatory affairs of various economic sectors, including the electricity industry. The use of European directives, which defines minimum requirements in relation to a particular sector, are designed to allow national authorities to choose between various options or mechanisms to meet a particular objective. This then provides maneuverability within a minimum standard framework for sovereign governments to set in place a national regulatory regime which whilst meeting these minimum standards allows for differentiation of regulation from other Member States. However, as discussed by Knill and Lehmkuhl (2002) the political translation between Member States of the scope and meaning, European Directives can be so divergent as to appear almost irreconcilable given the perceived motivation behind the desire to regulate at a ‘European’ level. However, as Eberlein and Grande (2005) point out, Member States have been and remain resistant to giving up political control, especially in the area of economic regulation since “. . .it involves politically highly sensitive economic sectors, ‘close to’ the state, in which the nation-state has traditionally taken on a special responsibility towards its citizens.” According to the European Court of Justice,4 energy is a commodity and as such its price should be determined by supply and demand but as indicated by a Green Paper issued by the Commission of the European Communities (2006), predictability and security of supply as well as physical security of energy infrastructure is critical. It is suggested that, regulation allows for the market to be transparent, predictable, secure and capable of meeting major supply disruptions, both short and longer term, whether globally or from a European perspective. The Green Paper clearly identifies that each Member State has the right to choose its own energy mix and these choices inevitably have an impact on the energy security of its neighbours and the European Community as a whole, including in such matters as competitiveness and the environment. The Green Paper suggests that there should be a clear framework for national decisions on energy mix, covering not only oil and gas supplies, but nuclear energy and renewable energy sources such as wind, biomass and biofuels. Importantly, the Paper acknowledges that energy prices are volatile, that increasingly the EU will become import dependent, and that security of supplies is critical. Finally, the Paper identifies that an energy partnership with Russia must be pursued.

4

Case C-7/68, Commission v. Italy [1968] ECR 1–633, 642.

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It is arguable hat there are two major problems which are dividing Europeans – the choice of energy sources and the regulation of markets. The EC has three energy targets for 2020 – a 20% reduction in CO2 emissions, a 20% improvement in energy efficiency, and 20% renewable energies – all of which are subject to a fundamental problem – the profound differences in energy systems required or desir