Delivering Energy Law and Policy in the EU and the US: A Reader 9780748696802

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Delivering Energy Law and Policy in the EU and the US

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DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US A Reader

Edited by Raphael J. Heffron and Gavin F. M. Little

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Edinburgh University Press is one of the leading university presses in the UK. We publish academic books and journals in our selected subject areas across the humanities and social sciences, combining cutting-edge scholarship with high editorial and production values to produce academic works of lasting importance. For more information visit our website: www.edinburghuniversitypress.com © editorial matter and organisation Raphael J. Heffron and Gavin F. M. Little, 2016 © the chapters their several authors, 2016 Edinburgh University Press Ltd The Tun – Holyrood Road 12 (2f) Jackson’s Entry Edinburgh EH8 8PJ Typeset in 10/12 Adobe Sabon by IDSUK (DataConnection) Ltd, and printed and bound in Great Britain by CPI Group UK (Ltd), Croydon CR0 4YY A CIP record for this book is available from the British Library ISBN 978 0 7486 9678 9 (hardback) ISBN 978 0 7486 9679 6 (paperback) ISBN 978 0 7486 9680 2 (webready PDF) ISBN 978 0 7486 9681 9 (epub) The right of the contributors to be identified as authors of this work has been asserted in accordance with the Copyright, Designs and Patents Act 1988 and the Copyright and Related Rights Regulations 2003 (SI No. 2498). Published with the support of the Edinburgh University Scholarly Publishing Initiatives Fund.

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CONTENTS

The Contributors Acknowledgements List of tables and figures Preface 1 PART 1:

Introduction

ENERGY POLICY DELIVERY IN GENERAL 2 Six Maxims for Informed Energy Analysis and Policy Benjamin K. Sovacool 3 Ending Subsidies for Fossil Fuel Exploration in a World of Unburnable Carbon Shelagh Whitley 4 Were North Sea Oil and Gas ‘Field Allowances’ Subsidies – and Does it Matter? David Powell 5 Renewable Energy Disputes Peter D. Cameron 6 Using a Legacy Frame to Deliver Energy and Environment Policies Kaitlin T. Raimi and Michael P. Vandenbergh 7 The Emergence of EU Energy Law Silke Goldberg 8 How to Improve Regulation Thomas P. Triebs 9 Delivering Energy Networks Security: Economics, Regulation and Policy Tooraj Jamasb and Rabindra Nepal

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The Role of Marketing in Delivering Energy Law and Policy Paul Haynes

ENERGY POLICY DELIVERY IN THE UNITED STATES 11 A Brief History of US Energy Policy Daniel H. Cole and Peter Z. Grossman 12 Applying Innovation Policy to the US Energy/ Climate Challenge William B. Bonvillian 13 National Scientific Laboratories as an Energy Policy Vehicle: the United States’ Experience William F. Fox 14 Delivering Energy Policy in the US: the Role of Taxes Roberta F. Mann 15 Delivering the Wind: Deconstructing Renewable Energy Success in Texas Monty Humble 16 Solar Rights in the United States Sara C. Bronin 17 The US–China Climate Agreement: a New Direction Edward Flippen 18 Going Green: The United States Department of Defense and Energy Security Alexios Antypas 19 US Conjunctive Water Management and Sustainable Energy Development Jason B. Aamodt ENERGY POLICY DELIVERY IN THE EUROPEAN UNION 20 Delivering New Polity: Paving the Way for the European Energy Union Elina Brutschin 21 Antitrust Enforcement in the EU Energy Sector Kim Talus 22 Delivering Energy Policy in the EU: Some Thoughts on the Role of Consumers Emanuela Michetti 23 The Growing Impact of Free Movement Provisions in the EU Energy Market Sirja-Leena Penttinen

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Energy, Externalities and the Need to Revisit Deutsche Bahn: a Proposal to Reverse the European Stance on EU State Aid Law and International Aviation Geert van Calster RES: Towards a New European Policy Theodore C. Panagos Energiewende in Germany: the Dawn of a New Energy Era Lutz Mez What is a Sustainable Policy? A Case for the Energiewende Gerardo Zarazua de Rubens The Finnish Energy Policy: Fulfilling the EU Energy and Climate Targets with Nuclear and Renewables Sanna M. Syri and Behnam Zakeri The EU–Russia Relationship and the EU Energy Union: from Dependence and Vulnerability towards Competition and a Free Flow Marek Martyniszyn

ELECTRICITY POLICY DELIVERY 30 The Role of Uncertainty in Energy Investments and Regulation Luis M. Abadie and Joseph V. Spadaro 31 Energy Security in an Unpredictable World: Making the Case Against State Aid Limitations in Electricity Generation Paul Murphy 32 Delivering a Low-carbon Electricity System in a Liberalised Market Roger Kemp 33 A Proposal for Reforming an Electricity Market for a Low-carbon Economy Raphael J. Heffron 34 The Role of the Demand Side in Electricity Malcolm Keay and David Robinson 35 Replacing Fossil Fuel Generation with Renewable Electricity: is Market Integration or Market Circumvention the Way Forward? Olivia Woolley 36 Susceptibility of Electricity Generation to Climate Variability and Change in Europe: a Review of Literature Muriel C. Bonjean Stanton, Suraje Dessai and Jouni Paavola

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The External Dimension of Cross-border Electricity Transmission Planning in the EU Karolis Gudas Integrating Vehicles and the Electricity Grid to Store and Use Renewable Energy David Hodas A Stitch in Time: Could Ireland’s Forthcoming White Paper Breathe New Life into its Brave but Faltering Renewable Electricity Policy? Eva Barrett Recent Developments in the Hungarian Electricity Regulatory Framework Robert Szuchy

NUCLEAR ENERGY 41 Delivering the Revival of Nuclear Power Keith Baker 42 Energy Policy: the Role of Nuclear Power S. D. Thomas 43 Financing New Nuclear Power Stations Simon Taylor 44 UK Nuclear New-build Plans in the Light of International Experience Tony Roulstone 45 Delivering UK Nuclear Power in the Context of European Energy Policy: the Challenges Ahead Philip Johnstone 46 Nuclear Liability: Current Issues and Work in Progress for the Future Cheryl Parkhouse 47 The Present Status of Nuclear Third-Party Liability and Nuclear Insurance Stephen F. Ashley, William J. Nuttall and Raphael J. Heffron 48 Small Modular Reactors: the Future or the Swansong of the Nuclear Industry? Giorgio Locatelli and Tristano Sainati RENEWABLE ENERGY 49 Coherent Promotion of Renewables under a Carbon Emissions Cap Philippe Thalmann

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Renewable Energy Policies Change Carbon Emissions Even Under Emissions Trading Johannes Jarke and Grischa Perino The Renewable Trajectory: Avoiding the Temptation of Cheap Oil Michael LaBelle Impact of Renewable Portfolio Standards on In-state Renewable Deployment in the US Gireesh Shrimali Renewable Support Policies in Europe: Evaluation of the Push–pull Framework for Wind and PV in the EU Ruben Laleman A View from the Global Wind Industry Jim Platts The New Concept of Competitive Bidding on Photovoltaic in the German Renewable Energy Act 2014 Joachim Sanden Legal Certainty for Green Energy Projects: Sure, but at What Price? Wouter Vandorpe The Future of Hydroelectric Power in the United States: Thinking Small Dan Tarlock Hydropower: from Past to Future Uncertainties Ludovic Gaudard and Franco Romerio Renewable Energy Production in Marine Areas and Coastal Zone: the Norwegian Model Sigrid Eskeland Schütz The Geopolitics of Clean Energy: Re-engaging with Russia Through Renewable Energy Cooperation Anatole Boute

FOSSIL FUELS 61 Talking About Shale in Any Language Alison Peck 62 The Shale Revolution, Fracking and Regulatory Activity in the US: a Policy Divided James W. Skelton, Jr 63 Fractured Systems: A Multiple Policy Proposal for Promoting Safe Shale Gas Delivery in the United States Caroline Cecot 64 Preparing Pennsylvania for a Post-Shale Future Ross H. Pifer

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The Decline of Coal and the Economic Toll on the Appalachian Region Patrick R. Baker The EU Network Codes and Prospects of Cross-border Natural Gas Pipeline Projects Gokce Mete Building the Energy Union: The Problem of Crossborder Gas Pipeline Interconnections in Baltic, Central and South-Eastern Europe Jack D. Sharples Eminent Domain Authority for Upstream Gas Infrastructure: an Alternative Approach Tara Righetti Petroleum Licensing on the UKCS Fifty Years On: Problems, Solutions and More Problems? John Paterson Greenland Offshore Petroleum Regulation Towards ‘The Blue Arctic’ Irina Kim

ENERGY JUSTICE 71 Energy Justice: the Yin and Yang Approach Roman Sidortsov 72 Sustainable Development and Energy Justice: Two Agendas Combined Kirsten E. H. Jenkins 73 Assessing the Justice Implications of Energy Infrastructural Development in the Arctic Darren McCauley, Robert Rehner and Maria Pavlenko ENERGY POVERTY AND HEALTH 74 Energy Poverty and Affordable Sustainable Energy Technologies (ASETs) Lakshman Guruswamy 75 Challenging Energy Poverty Policies: Insights from South-eastern Europe Saska Petrova 76 Policy Changes for Future-proofing Housing Stock Charlotte A. Adams 77 Challenges for Health Services in Identifying Which Groups are Most Vulnerable to Health Impacts of Cold Homes Anna Cronin de Chavez 78 Energy, Life, Metabolism and the Food Chain James J. A. Heffron

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PART 10: ENERGY EFFICIENCY AND DEMAND 79 Energy Efficiency and Energy Demand Steve Sorrell 80 Energy Demand Reduction Policy Katy Roelich and John Barrett 81 Demand Response in Wholesale Markets Joel B. Eisen 82 Perceived Effectiveness of Different Methods of Delivering Information on Energy Efficiency Lucie Stevenson and Danny Campbell 83 Developing Behavioural Interventions: Three Lessons Learned for Delivering Energy Policy Wändi Bruine de Bruin and Tamar Krishnamurti 84 Policy Mixes in Stimulating Energy Transitions: The Case of UK Energy Efficiency Policy Florian Kern 85 The Journey of Smart Metering in Great Britain: a Revisit Tao Zhang 86 Rethinking Household Energy Consumption Strategies: the Importance of Demand and Expectations Louise Reid 87 Financial Incentives for Energy-efficient Appliances Souvik Datta PART 11: ENERGY SECURITY 88 Energy Security and Energy Policy Incoherence Hugh Dyer 89 Designing International Trade in Energy Governance for EU Energy Security Rafael Leal-Arcas 90 NATO and European Energy Security Behrooz Abdolvand and Konstantin Winter 91 Genealogy of the Current Gas Security Situation in the EU–Ukraine–Russia Energy Triangle and the Role of International Law Maksym Beznosiuk

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PART 12: COUNTRY-SPECIFIC AND INTERNATIONAL ENERGY POLICY DELIVERY 92 German Energy Law 489 Katharina Vera Boesche 93 Delivering Energy Law and Policy in Malta 495 Simone Borg

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94 Delivering Energy Efficiency Policies in Romania Sebastian Radocea 95 Energy Law in the Czech Republic: ‘Unbundling’ ČEZ Michael J. Allen 96 Delivering Energy Policy Reform in Ukraine: Legal Issues in the Light of European Integration Yuliya Vashchenko 97 A Systemic Approach to Renewable Electricity Technology Deployment: The ‘Missing Link’ in Optimising Policy Delivery in the UK? Geoffrey Wood 98 Delivering Energy Policy: Is there a Need for Key Changes in the Next UK Parliamentary Period? Chris Eaglen 99 Energy and the State in the Middle East Jim Krane 100 Delivering Energy Policy in Argentina Tomás Lanardonne 101 The Arctic: Source of Energy? Source of Conflict? Source of Policy Innovation Joseph F. C. DiMento PART 13: CITIES, COMMUNITY ENERGY AND PUBLIC ENGAGEMENT 102 Delivering Energy (Often) Requires Public Consent Heather E. Hodges, Colin P. Kuehl, Eric R. A. N. Smith and Aaron C. Sparks 103 Public Engagement and Low Carbon Energy Transitions: Rationales and Challenges Paul Upham 104 Delivering Energy Policy in Ireland: Protest, Dissent and the Rule of Law Áine Ryall 105 National Energy Policy, Locally Delivered: the Role of Cities Catherine S. E. Bale 106 Community Energy in the UK Sandra Bell 107 Distributed Energy Resources: Back to the Future and More James E. Hickey, Jr 108 Promoting Cost-effective Distributed Generation: Lessons from the United States Karim L. Anaya

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PART 14: CLIMATE CHANGE AND THE ENVIRONMENT 109 Energy and Climate Policy: Synergies, Conflicts and Co-benefits Hannes R. Stephan 110 The Multi-level System of Global Governance: Opportunities for more Ambitious Climate Strategies Martin Jänicke 111 The What, How and Where of Climate Law Navraj Singh Ghaleigh 112 Environmental Law and Climate Change John McEldowney 113 Energy and Environment Studies: the Role of Legal Scholarship Gavin F. M. Little 114 Overview of the EU Climate Policy Based on the 2030 Framework Noriko Fujiwara 115 Climate Policy Instrumentation in Spain Mikel González-Eguino, Anil Markandya and Luis Rey 116 Planning Consent and the Law of Nuisance Francis McManus 117 Multi-state Endangered Species Act Listings: the Impact to Energy and New Conservation Approaches in the United States Temple L. Stoellinger 118 Delivering Energy to the Drylands: Obligations under the UN Convention to Combat Desertification (UNCCD) to Provide Energy, Water and More Roy Andrew Partain PART 15: NEW TECHNOLOGIES AND ENERGY INITIATIVES 119 Delivering New Energy Technologies: the Military as Consumer and Innovator Samuel R. Schubert 120 Delivering Energy Policy for Planet Ocean by Investing in Ocean Thermal Energy Conversion Infrastructure Anastasia Telesetsky 121 The Necessity of Government Support for the Successful Deployment of Carbon Capture and Storage Matthew Rooney

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122 Too Little and Too Late? An Evaluation of the Regulation of Carbon Capture and Storage as an Integral Element of a Future Low-carbon Energy System Stuart Bell 123 Carbon Capture and Storage Readiness Assessment: a Premature Regulatory Requirement? Owen McIntyre 124 Value of Energy Storage: the Required Market and Policy Supports Behnam Zakeri and Sanna M. Syri 125 Energy Storage Systems: a Risky Investment to Provide the Required Flexibility for Future Smart Grids Diletta Colette Invernizzi and Giorgio Locatelli 126 An Energy Partnership between the European Union and Brazil for the Promotion of Second-generation Biofuels Stavros Afionis and Lindsay C. Stringer 127 Conclusion

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THE CONTRIBUTORS

Jason B. Aamodt, University of Tulsa, USA Jason Aamodt serves as the Assistant Dean for the University of Tulsa, College of Law, and focuses his research on sustainable development, energy justice and indigenous rights. In addition to managing a cutting-edge online law degree programme, he is the founding member of the Indian and Environmental Law Center which, among other things, certified the first geographically defined toxic tort class action in Oklahoma, created a new cause of action in Indian accounting cases and obtained a National Law Journal Top-25 verdict in 2013. Luis M. Abadie, Basque Centre for Climate Change, Spain Luis Abadie is a Research Professor in the Basque Centre for Climate Change (BC3) in Bilbao, has a PhD in Economics (University of the Basque Country UPV/EHU, 2007) and is a graduate in Industrial Engineering (UPV/EHU, 1979) and in Computer Science (University of Deusto, 1985). He has extensively published in the fields of energy and climate change. His main research fields are energy economics, carbon markets, greenhouse gas emissions, real options and financial economics. Dr Behrooz Abdolvand, Berlin Centre for Caspian Region Studies, Freie Universität Berlin, Germany Behrooz Abdolvand has been a Lecturer in International Relations and Energy Policy at the Otto-Suhr-Institute of the Freie Universität Berlin since 1998, where he is the coordinator of the graduate school programme ‘Caspian Region Environmental and Energy Studies’ (CREES). Since 2002 he has worked as a consultant in the energy sector, and since 2013 has been Associate Fellow at the German Council on Foreign Relations (DGAP). Dr Charlotte A. Adams, Research Manager BritGeothermal, Department of Earth Sciences, Durham University, UK Charlotte Adams trained as a hydrogeologist and has a keen interest in ground source heat and geothermal energy. Prior to joining Durham University in 2009

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she gained industrial experience whilst carrying out energy audits and renewable energy assessments for a range of domestic and industrial buildings. Her research interests include micro-generation, efficient provision of heat, the built environment, energy efficiency and sustainability of historic buildings. She currently manages the BritGeothermal Research Partnership. Dr Stavros Afionis, School of Earth and Environment, Sustainability Research Institute, University of Leeds, UK Stavros Afionis is a Postdoctoral Research Fellow at the Sustainability Research Institute (SRI) of the School of Earth and Environment at the University of Leeds. His doctoral research examined the role played by the European Union in international climate change negotiations. His research interests currently focus on environmental politics and, in particular, international climate change negotiations and global biofuel policies. Michael J. Allen, Charles University, Prague, Czech Republic Michael Allen is an independent researcher currently based in Prague. His research interests are in energy law, particularly issues concerning nuclear energy and, in particular, nuclear waste. Other areas of interest include renewable energy, energy justice, and environment and business transactions. His legal research focuses on the European and USA energy sectors. Dr Karim L. Anaya, Energy Policy Research Group, University of Cambridge, UK Karim Anaya holds a PhD in Energy Economics and a Masters degree in Technology Policy from the University of Cambridge. She has extensive experience in the public utility regulatory arena. Karim has been a consultant for different organisations (United Nations, World Bank, public utilities regulators). Her research topics are focused on regulation, economics and smart commercial arrangements of distributed generation; business models and economics of energy storage; and renewable energy and technical efficiency in electricity distribution and transmission system operation markets. Professor Alexios Antypas, Department of Environmental Sciences and Policy, Central European University, Budapest, Hungary Alexios Antypas is an Associate Professor in the Department of Environmental Sciences and Policy at Central European University. He specialises in the field of environmental policy and governance, and has published widely on environmental policy issues, including climate change policy and politics, multi-level governance in the European Union, environmental security, renewable energy policy, corporate social and environmental responsibility, and conservation and communities, among other topics. He has served as a consultant to the European Union, the Organization for Economic Cooperation and Development, the United Nations Environment Programme, the United Nations Development Programme, the World Health Organization, the Regional Center for Central and Eastern Europe, the Hungarian Ministry of Environment and the United

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States Forest Service. His current research interests include Arctic environmental governance, energy security and the politics of climate change. Dr Stephen F. Ashley, Department of Engineering and Innovation, Open University, UK Stephen Ashley is a Research Associate in the Department of Engineering and Innovation at the Open University. He received his BSc in Physics from Staffordshire University in 2003 and his PhD in Nuclear Structure Physics from the University of Surrey in 2007. Following a switch to nuclear-energy related research in 2011, his most recent research position was part of the EPSRC (UK) funded project entitled ‘Management of Nuclear Risk Issues: Environmental, Financial and Safety (NREFS)’ (Ref: EP/K007580/1). This project is part of the RCUK-India civil nuclear collaboration and his research has centred on looking at the role of nuclear insurance and law following the events at Fukushima Daiichi. Dr Keith Baker, School of Public Policy, Oregon State University, USA Keith Baker is an Assistant Professor in the School of Public Policy, Oregon State University. His interests include the governance of nuclear power, energy policy and public administration. Professor Patrick R. Baker, Natural Resources Law Center, the Appalachian School of Law, USA Patrick Baker is an Associate Professor of Law and Director of the Natural Resources Law Center at the Appalachian School of Law. Professor Baker teaches Administrative Law, Water Law, Oil and Gas Law, and Coal and Hard Mineral Law. He also serves as chair of the Institutional Development and Strategic Planning Committee. Dr Catherine S. E. Bale, Energy Research Institute and Sustainability Research Institute and Centre for Integrated Energy, University of Leeds, UK Catherine Bale is a University Academic Fellow at the Energy Research Institute and Sustainability Research Institute at the University of Leeds. She has a background in physical science, and obtained her Masters degree and DPhil from the University of Oxford. She has previously worked in the public sector developing strategic support programmes for the environmental and energy sectors in Yorkshire and the Humber. Her current research focuses on strategic energy planning in cities and the application of complexity science to energy challenges. She holds a Fellowship from the Engineering and Physical Sciences Research Council. Dr Eva Barrett, National University of Ireland Maynooth, Ireland Eva Barrett is a Lecturer in Law at National University of Ireland Maynooth and an Adjunct Assistant Professor (lecturing on Energy Law and Policy in the European Union) at Trinity College Dublin. She qualified as a solicitor while

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working for a large Irish commercial law firm in 2009, and subsequently worked in the European Commission in Brussels and at the Institute of International and European Affairs in Dublin. In 2014 she was elected Vice-President of Energy Law Ireland. Professor John Barrett, School of Earth and Environment, University of Leeds, UK John Barrett is Professor of Sustainability Research at the School of Earth and Environment, University of Leeds. His research interests include sustainable consumption and production (SCP) modelling, carbon accounting and exploring the transition to a low-carbon pathway. He has been an advisor to the UK government on the development of carbon footprint standards and the future of consumption-based emissions in the UK. Dr Sandra Bell, Department of Anthropology, Durham University, UK Sandra Bell is an environmental anthropologist who has researched and published on energy issues including community energy projects, electricity consumption and the evolution of smart grid technologies. Professor Stuart Bell, York Law School, University of York, UK Stuart Bell is a Professor of Law at York Law School, University of York. Maksym Beznosiuk, Uppsala University, Sweden and Jagiellonian University, Poland Maksym Beznosiuk is an Erasmus Mundus Scholar at Uppsala University/ Jagiellonian University. Maksym’s research interests are in energy law and policy, EU–Ukraine relations and, in particular, international energy security and international law, and EU–Ukraine cooperation in the energy sphere. Dr Katharina Vera Boesche, former Scientific Assistant (Assistant Professor) with the Institute for German and European Antitrust Law, Competition Law, and in Energy Law, Faculty of Law, Freie Universität Berlin, Germany Katharina Vera Boesche is a lawyer specialising in energy law, competition law and contract law. Muriel C. Bonjean Stanton, School of Earth and Environment, University of Leeds, UK Muriel Bonjean Stanton is a postgraduate research student in the School of Earth and Environment at the University of Leeds, exploring how public and private organisations frame and respond to risks associated with Climate Variability and Change (CV&C). Her research interests mostly centre on private-sector adaptation, public-private interactions around CV&C, climate governance and policy, and institutional and behavioural change. Muriel has ten years’ experience in adaptation to CV&C and natural resource management in both developing and developed contexts.

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William B. Bonvillian, Massachusetts Institute of Technology, Washington Office, USA William Bonvillian is Director of the Massachusetts Institute of Technology’s Washington Office and teaches innovation policy on the adjunct faculty of Georgetown University and Johns Hopkins School of Advanced International Studies. He co-authored (with Charles Weiss) the books Technological Innovation for Legacy Sectors (Oxford University Press, 2015) and Structuring an Energy Technology Revolution (MIT Press, 2009), and has written numerous articles on energy and innovation policy. Professor Simone Borg, Department of Environmental Law and Resources Law, University of Malta, Malta Simone Borg LLD, MJur (International Law), PhD is Deputy Dean and Head of Department of Environmental Law and Resources Law at the University of Malta. She is also a visiting professor at the University of Leuven and the IMO International Maritime Law Institute in Malta. She is currently Malta’s Ambassador on Climate Action. Professor Borg has published various law books and legal articles on environmental law, resources law, climate change law and the conservation of living marine resources. Dr Anatole Boute, Chinese University of Hong Kong, China Anatole Boute has a PhD in Law from the University of Groningen and is an Associate Professor at the Chinese University of Hong Kong and Legal Advisor to the International Finance Corporation (World Bank Group). He has been admitted to the Brussels Bar, where he practised in the field of energy and environmental law. He is the author of Russian Electricity and Energy Investment Law (Brill Nijhoff, 2015). Professor Sara C. Bronin, University of Connecticut School of Law and Center for Energy and Environmental Law, USA Sara Bronin is Professor of Law at the University of Connecticut School of Law. Her scholarly research examines property, land use, historic preservation, green building and renewable energy law. In addition to her teaching responsibilities, she currently serves as Faculty Director for the university’s Center for Energy and Environmental Law. An attorney and architect, Professor Bronin has also served as an expert witness and as a consultant to cities, public agencies and private firms. Professor Wändi Bruine de Bruin, Centre for Decision Research, Leeds University Business School, UK Wändi Bruine de Bruin holds a University Leadership Chair in Behavioural Decision Making at the Leeds University Business School, where she co-directs the Centre for Decision Research. She is Collaborating Professor at Carnegie Mellon University’s Department of Engineering and Public Policy. Her research focuses on public risk perception and communication, as for example applied to climate change and low-carbon technologies.

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Dr Elina Brutschin, Webster University Vienna, Austria Elina Brutschin has a PhD from the University of Konstanz, Germany, on the liberalisation of the European gas market. Besides her expertise in energy matters, her research interests focus on Eastern European studies. She is Assistant Professor at Webster University Vienna and is currently working on a publication depicting the history of the European gas market and the role of the European Commission as a policy entrepreneur. Peter D. Cameron, Centre for Energy, Petroleum and Mineral Law and Policy and University of Dundee, UK Peter Cameron is Director of the Centre for Energy, Petroleum and Mineral Law and Policy (CEPMLP), and Professor of International Energy Law and Policy, University of Dundee, UK. Peter was elected as Fellow of the Royal Society of Edinburgh in 2013. He is Co-director of the recently established International Centre for Energy Arbitration and Honorary Professorial Fellow at Edinburgh University’s Europa Institute. Peter is a barrister (England and Wales, Middle Temple), and has regularly been asked by governments and investors to testify in arbitral proceedings as an expert witness. He is currently preparing a second edition of his publication International Energy Investment Law: The Pursuit of Stability (Oxford University Press, 2010), including new chapters on gas and renewable energy disputes, and damages in energy claims. A second edition of his Legal Aspects of EU Energy Regulation (co-authored with Raphael J. Heffron) will also appear in 2016, to be published by Oxford University Press, as will a book-length publication on international best practice, Oil, Gas and Mining: A Source Book, to be published by the World Bank. Dr Danny Campbell, Economics Division, Stirling Management School, University of Stirling, UK Danny Campbell is a Senior Lecturer in Economics in the Economics Division at the University of Stirling. He is an expert on environmental valuation and has degrees in agricultural economics and rural development and a PhD in environmental economics from Queen’s University Belfast. His main area of research concerns the valuation of natural resources as well as methodological and econometric issues relating to discrete choice experiments. Dr Caroline Cecot, Law Clerk to the Hon. Raymond J. Lohier, Jr, New York, USA Caroline Cecot earned her JD and her PhD in law and economics at Vanderbilt University in May 2014. Her research focuses on risk, administrative law, and energy and environmental regulation. Before going to Vanderbilt, Caroline worked as a research associate at the AEI-Brookings Joint Center for Regulatory Studies in Washington, DC for two years after graduating from Harvard University in June 2006 with an AB in economics magna cum laude. She was Vanderbilt’s 2014–15 Postdoctoral Research Scholar in Law and Economics and taught Risk and Environmental Regulation II. She is currently a law clerk

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to the Honorable Raymond J. Lohier, Jr, on the US Court of Appeals for the Second Circuit in New York, and plans to pursue a position in legal academia. Professor Daniel H. Cole, Indiana School of Law, USA Daniel Cole is Professor of Law and Professor of Public and Environmental Affairs at Indiana University, where he also serves on the Affiliated Faculty of the Vincent and Elinor Ostrom Workshop in Political Theory and Policy Analysis. Dr Anna Cronin de Chavez, Centre for Health and Social Care Research, Sheffield Hallam University, UK Anna Cronin de Chavez is a Research Fellow at the Centre for Health and Social Care Research at Sheffield Hallam University. She is a biological/medical anthropologist with an interest in fuel poverty and the impact of cold temperatures on health, and is currently conducting research into challenges in keeping warm and healthy faced by two vulnerable groups: children with asthma and people with sickle-cell disease. She has also worked on the evaluation of fuel poverty interventions with health improvement agencies. Her doctoral thesis examined the beliefs and practices of mothers from different cultures regarding protecting their babies from heat and cold. Dr Souvik Datta, Center of Economic Research (CER-ETH), Department of Management, Technology and Economics, ETH Zürich, Switzerland Souvik Datta completed his PhD in Economics at the University of British Columbia, Vancouver in 2011 and is currently a Postdoctoral Researcher at ETH Zürich. His research interests are on issues in environmental economics, energy economics and policy evaluation, with a particular focus on empirical analysis, for example analysing the cost-effectiveness of energy-efficiency programmes, estimating the price responsiveness of electricity demand and the environmental impact of a luxury tax on automobiles. Professor Suraje Dessai, School of Earth and Environment, University of Leeds, UK Suraje Dessai is Professor of Climate Change Adaptation in the School of Earth and Environment at the University of Leeds. His research focuses on the management of climate change uncertainties, perception of climate risks and the science-policy interface in climate change impacts, adaptation and vulnerability. He is the recipient of an ERC Starting Grant and a lead author of the Fifth Assessment Report of the IPCC WG2. Professor Joseph F. C. DiMento, University of California Irvine, USA Joseph DiMento is Professor of Law, Planning, and Criminology, Law and Society. He specialises in domestic and international law with a focus on environmental and land use. Among his most recent works are (co-authored with Alexis Jaclyn Hickman) Environmental Governance of the Great Seas:

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Law and Effect (Edward Elgar Publishing, 2012) and (co-edited with Pamela Doughman) Climate Change: What it Means for Us, Our Children, and Our Grandchildren, 2nd edn (MIT Press, 2014). Dr Hugh Dyer, School of Politics and International Studies, University of Leeds, UK Hugh Dyer is Associate Professor of World Politics in the School of Politics and International Studies at the University of Leeds. His recent work includes the monograph Coping and Conformity in World Politics (Routledge, 2012), a co-edited volume International Handbook of Energy Security (Edward Elgar Publishing, 2013) and an article ‘Climate anarchy: Creative disorder in world politics’ in International Political Sociology 8(2) (2014). His research interests are at the boundary of traditional perspectives on international relations and the challenges of environmental change. Dr Chris Eaglen, London, UK Chris Eaglen is an engineer engaged in nuclear and infrastructure projects and their procurement. Chris’s research interests are in energy, environmental, contract law and policy, and in particular electricity generation and distribution infrastructure, nuclear and fossil fuel power engineering, as well as organising manufacturing, fabrication and construction capability contract arrangements. Professor Joel B. Eisen, University of Richmond School of Law, USA Joel Eisen teaches and writes in the areas of energy law and policy, environmental law and policy, and smart grids. He is a co-author of the leading law and business school text on energy law, energy, economics and the environment, and has written numerous books, book chapters, treatises and law review articles on electric utility regulation. His scholarship has appeared in journals at Harvard, UCLA, Duke, Notre Dame, Fordham, Illinois, Wake Forest and William & Mary law schools, among other venues. In recognition of his contributions to scholarship, Richmond School of Law named him the inaugural Austin Owen Research Fellow in 2013. His article ‘Residential renewable energy: by whom?’ was honoured as one of the top four environmental law articles of 2011. He was the University of Richmond’s Distinguished Educator for 2010–11 and, in spring 2009, a Fulbright Professor of Law at the China University of Political Science and Law in Beijing, China. Professor dr juris Sigrid Eskeland Schütz, University of Bergen, Norway Sigrid Eskeland Schütz is a licensed solicitor (2001) and dr juris (2008) whose thesis is on the Norwegian planning and building act and implementing EU directives on environmental impact assessment. In 2009–10 she was member of a government-appointed committee on toxic substances that looked at measures needed to fulfil the obligations of the Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR). Her interests are (EEA) environmental law, land use planning, coastal zone management and

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marine spatial planning. She is head of the research group for natural resource law, environmental law and development law. Edward Flippen, University of Virginia School of Law, USA and Queen Mary University of London, UK Edward Flippen is a lawyer and Lecturer in Energy Regulation and Policy at the University of Virginia School of Law and Queen Mary University of London. Professor William F. Fox, USA William Fox has recently retired after more than forty-two years of full-time teaching and practice. His most recent academic affiliation was the School of Law, Pennsylvania State University. He continues in part-time teaching at the School of Transnational Law, Peking University (Shenzhen campus) and is an Honorary Fellow of the Centre for Energy, Petroleum and Mining Law and Policy at the University of Dundee. Dr Noriko Fujiwara, Centre for European Policy Studies, Brussels, Belgium Noriko Fujiwara is Associate Research Fellow and Head of Project Development at the Energy and Climate Change Unit, Centre for European Policy Studies (CEPS) in Brussels. She has undertaken research on climate change and energy at international, EU and country levels. Recent topics include lowcarbon technology and innovation, post-carbon cities, climate change mitigation, energy efficiency, renewable energy, the EU emissions trading scheme and international carbon markets. She has a DPhil in International Relations from the University of Sussex, an MPhil in Development Studies from the University of Cambridge and a Master of Law (International Political Economy) from Hitotsubashi University, Japan. Dr Ludovic Gaudard, University of Geneva, Switzerland and London School of Economics, UK Ludovic Gaudard is Research Associate at the University of Geneva and Visiting Fellow at the London School of Economics. He holds a PhD in Interdisciplinary Studies (Economics and Environmental Sciences), a Masters degree in Environmental Sciences and a Bachelor’s degree in Physics. His research focuses on the impact of climate change, new technologies (such as smart grid) and market liberalisation on hydropower, with regard to the physical, technical and economic aspects. He also focuses on integrating simulations, optimisation and econometrics with risk and uncertainty analysis. Silke Goldberg, Herbert Smith Freehills, London, UK Silke Goldberg is Counsel in the Global Energy Group of Herbert Smith Freehills where she specialises in European energy law. Silke has been admitted to the bar in England and Wales and the Republic of Ireland and is also a member of the Berlin Bar. Silke is the editor of the European Energy Handbook, and publishes regularly on topics related to European energy regulation and climate change. Her publications include (as co-editor) Climate Change

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Liability: Transnational Law and Practice (Cambridge University Press, 2012); and (with Henrik Bjornebye) ‘Introduction and comment on the third energy package’, in Bram Delvaux et al., EU Energy Law and Policy Issues (Intersentia, 2012). Dr Mikel González-Eguino, Basque Centre for Climate Change and University of the Basque Country, Spain Mikel González-Eguino is a Senior Researcher at the Basque Centre for Climate Change (BC3) in Bilbao. He has a PhD in Economics (University of the Basque Country, 2006) and a degree in Engineering (University of Deusto, 2001). His main interests lie in the fields of environmental, energy and public economics, and his work has been published in several of the leading journals in the field including Climate Policy, Ecological Economics, Energy Economics, Journal of Environmental Management, The Energy Journal and Water Policy. He has worked on environmental and economy-related issues for European, Spanish and Basque firms and institutions. His doctoral thesis won him the Enrique Fuentes Quintana prize (FUNCAS, 2006) and he has obtained his accreditation as Professor Titular – in Economics (ANECA, 2012). Professor Peter Z. Grossman, Butler University, USA Peter Grossman is the Clarence Efroymson Professor of Economics at Butler University, Indianapolis. He is the author of several books on energy and energy policy. Karolis Gudas, World Trade Institute, University of Bern, Switzerland and the Swiss National Centre of Competence in Trade Regulation Karolis Gudas is a PhD Research Fellow at the World Trade Institute, University of Bern and the Swiss National Centre of Competence in Trade Regulation. He is a dispute resolution lawyer at Motieka & Audzevicius and a former Junior Fellow at the European Commission Institute for Energy. Professor Lakshman Guruswamy, University of Colorado at Boulder, USA Lakshman Guruswamy is Nicholas Doman Professor of Law, University of Colorado at Boulder. He was born in Sri Lanka and is a recognised expert in international environmental and energy law. He teaches International Environmental Law, Global Energy Justice and Oil and International Relations at the University of Colorado and is the author of numerous books and articles, including International Energy and Poverty: The Emerging Frontiers (Routledge, 2015). He is currently engaged in writing Global Energy Justice (Foundation West, forthcoming 2016). Dr Paul Haynes, School of Management, Royal Holloway, University of London, UK Paul Haynes is a Lecturer in Marketing in the School of Management, Royal Holloway, University of London. Paul’s research interests are in branding, sustainability, networks, technological innovation and complexity.

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Professor James J. A. Heffron, MRIA, FRSC, School of Biochemistry and Cell Biology, National University of Ireland, Ireland James Heffron is Professor Emeritus in Biochemistry at the National University of Ireland, Cork. His research interests are in energy metabolism, human metabolic diseases and toxicology of natural and synthetic chemicals. Dr Raphael J. Heffron, Energy and Natural Resources Law Institute, Queen Mary University of London, UK Raphael Heffron is a Senior Lecturer in Energy and Natural Resources Law at the Energy and Natural Resources Law Institute, Queen Mary University of London. Raphael’s research interests are in energy law and policy, and in particular electricity markets, energy subsidies, low-carbon energy, energy justice and Arctic energy law. Of importance in his research is the aim to understand the legal challenges involved in planning for new energy infrastructure projects. James E. Hickey, Jr, Maurice A. Deane School of Law, Hofstra University, USA James Hickey, Jr teaches courses on Energy and International Law at Hofstra University School of Law. He is a past Chair of the American Bar Association (ABA) Special Committee on electric industry restructuring and has been a consultant to the Energy Charter Secretariat and a Special Assistant to the National Petroleum Council. He has over seventy publications to his name, including five books, two of which deal with energy law and policy. His most recent book, The Legal Doctrines of the Rule of Law and the Legal State (Rechtsstaat) (Springer, 2014) was co-edited with the 2013–14 President of the ABA. He is a Life Fellow of the American Bar Foundation. Professor Hickey holds a JD from the University of Georgia Law School and a PhD in International Law from Cambridge University (Jesus College). Professor David Hodas, Delaware Law School – Widener University, USA David Hodas is is Distinguished Professor of Law at Delaware Law School – Widener University in Wilmington, DE. He teaches and writes on Sustainable Energy Law and Policy, Climate Change Law, and Environmental, Administrative and Constitutional Law. He co-authored Climate Change Law: Mitigation and Adaptation (West-Thomson Reuters, 2009), is a member of the Energy Expert Group of the IUCN Environmental Law Commission, chairs the State of Delaware Governor’s Energy Advisory Council and is an editor of the IUCN Academy of Environmental Law e-journal. Professor Hodas has a BA cum laude and with honours in political science, Williams College (1973); a JD cum laude, Boston University School of Law (1976); and an LLM in Environmental Law (Feldshuh Fellow), Pace University School of Law (1989). Heather E. Hodges, University of California, Santa Barbara, USA Heather Hodges is a PhD candidate at the University of California, Santa Barbara. Her research is primarily focused on how political behaviour and political communication shape environmental policy outcomes, particularly in the context of wildfire and energy.

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Monty Humble, University of Texas School of Law, USA Monty Humble is an Adjunct Professor at the University of Texas School of Law, teaching courses in Renewable Energy Policy and Renewable Project Development. He practised law for thirty-two years before founding his own renewable energy development company. Diletta Colette Invernizzi, School of Civil Engineering, University of Leeds, UK Diletta Colette Invernizzi is a PhD student at the School of Civil Engineering at the University of Leeds. Diletta has a Bachelor’s degree in Energy Engineering and a Masters Degree in Management Engineering, both obtained at Politecnico di Milano. Her final Masters dissertation focused on investment appraisal in energy storage systems, which remains one of her main research topics. Professor Tooraj Jamasb, Durham University Business School, UK Tooraj Jamasb is Professor of Energy Economics at Durham University Business School and Co-director at Durham Energy Institute. He holds a PhD in Energy Economics (University of Cambridge) and has Masters degrees in Energy Management and Policy from the University of Pennsylvania, the French Institute of Petroleum (IFP) and the Norwegian School of Management (BI), as well as a BBA from Tehran Business School. His research includes energy sector reform, energy networks, incentive regulation, energy policy, energy demand and public acceptance, and energy technology. He is also co-editor of the books The Future of Electricity Demand: Customers, Citizens and Loads (Cambridge University Press, 2011), Delivering a Low-Carbon Electricity System: Technologies, Economics, and Policy (Cambridge University Press, 2008) and Future Electricity Technologies and Systems (Cambridge University Press, 2006). He has participated on projects for the Council of European Energy Regulators (CEER), several European energy regulators, energy companies and the World Bank. He is Research Associate at the Electricity Policy Research Group (EPRG, Cambridge) and the Centre for Energy and Environmental Policy Research (CEEPR, MIT). He is member of the academic advisory panel of the Northern Ireland Utility Regulator (UREGNI). Professor Martin Jänicke, Environmental Policy Research Centre, Freie Universität Berlin, Germany and Institute for Advanced Sustainability Studies, Potsdam, Germany Martin Jänicke is Founding Director of the Environmental Policy Research Centre, Freie Universität Berlin, and Senior Fellow at the Institute for Advanced Sustainability Studies, Potsdam. He was Vice President of the German Advisory Council of the Environment, a member of parliament and a policy advisor in China. Works on state failure, ecological modernisation, capacity building and best practice in environmental policy have been published in several languages. Dr Johannes Jarke, Department of Socioeconomics, University of Hamburg, Germany Johannes Jarke is a Postdoctoral Researcher and Lecturer at the University of Hamburg. He studied economics at the universities of Heidelberg and

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Mannheim and received his honours PhD in 2013. He works in the field of applied micro- and experimental economics with a special interest in regulation and informal governance of common and shareable assets. Kirsten E. H. Jenkins, School of Geography and Geoscience, University of St Andrews, UK Kirsten Jenkins is a PhD candidate at the University of St Andrews. She previously undertook a Master of Research degree in Sustainable Development and a Bachelor of Science degree in Sustainable Development at the same institution. Her Economic and Social Research Council funded PhD studies focus on discourses of energy justice throughout the nuclear energy system. Kirsten hopes to progress to a career in academia following her PhD, and has a strong personal interest in Scottish energy provision and Arctic energy developments. Philip Johnstone, Science Policy Research Unit, University of Sussex, Brighton, UK Philip Johnstone is a Research Fellow at the Science Policy Research Unit (SPRU), University of Sussex. He currently works on the ESRC-funded Discontinuity in Technological Systems (DiscGo) alongside colleagues in Dortmund, Twente and Paris, a project focusing on the governance process of discontinuing certain technological trajectories. This task is a crucial one in accelerating transitions to more sustainable energy systems. Phil is a member of the Sussex Energy Group (SEG), where his work is centred around nuclear power, the democratic implications of different energy technologies and governance processes surrounding the shift towards decentralised energy systems. He is also the Tyndall Centre Coordinator for the University of Sussex. Malcolm Keay, Oxford Institute for Energy Studies (OIES), UK Malcolm Keay is Senior Research Fellow at the OIES, where his research focuses on electricity markets in the UK and Europe and the implications of climate change policies. Professor Roger Kemp, Engineering Department, Lancaster University, UK Roger Kemp is a Professorial Fellow in the Engineering Department at Lancaster University. He joined the university as a second career, after thirty-five years in industry. He is a Fellow of the Royal Academy of Engineering and of the Institution of Engineering and Technology, and has contributed to several reports on energy policy by these bodies. Dr Florian Kern, School of Business, Management and Economics, University of Sussex, UK Florian Kern is Co-director of the Sussex Energy Group and Senior Lecturer at the Science Policy Research Unit (SPRU). He co-convenes the MSc in Energy Policy for Sustainability. Dr Kern’s research focuses on energy, climate and innovation policy in the context of transitions towards more sustainable energy

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systems. His research has been published in journals such as Energy Policy, Technological Forecasting & Social Change, Policy & Politics, Policy Sciences and Environment and Planning C. Work on this chapter was enabled through the Centre on Innovation and Energy Demand which is funded by the Research Councils UK’s EUED Programme (grant number EP/KO11790/1). Irina Kim, Centre for Enterprise Liability, University of Copenhagen, Denmark Irina Kim is a PhD researcher at the Centre for Enterprise Liability (CEVIA), University of Copenhagen. Prior to work in academia, Irina practised law in international law firms and in-house, specialising in natural resources law and business aspects of oil and gas operations. Irina’s primary research area concerns environmental law, and in particular issues of liability for offshore petroleum operations in the Arctic. Dr Jim Krane, James A. Baker III Institute for Public Policy, Rice University, USA Jim Krane is the Wallace S. Wilson Fellow for Energy Studies at the James A. Baker III Institute for Public Policy, based at Rice University in Houston, Texas. He researches political and geopolitical aspects of energy, with a focus on exporting states, particularly those in the Middle East. He is the author of the book Dubai: The Story of the World’s Fastest City (Atlantic Books, 2009). He holds a PhD and an MPhil from Cambridge University’s Judge Business School, and a Masters in International Affairs from Columbia University. Dr Tamar Krishnamurti, Department of Engineering and Public Policy, Carnegie Mellon University, USA Tamar Krishnamurti is an Assistant Research Professor in Carnegie Mellon University’s Department of Engineering and Public Policy. Her research interests lie in understanding the human judgments that shape decision-making. She applies basic judgment and decision-making knowledge to the design of effective communications, decision aids and interventions, including those concerned with energy consumption and conservation. Colin P. Kuehl, University of California, Santa Barbara, USA Colin Kuehl is a PhD candidate studying global environmental politics at University of California, Santa Barbara. His research focuses on how norms and identities shape environmental behaviour. Professor Michael LaBelle, CEU Business School and Department of Environmental Sciences and Policy, Central European University, Hungary Michael LaBelle is an Assistant Professor teaching courses on Sustainability, Innovation and Energy Technologies. His research is centred on the interaction of government institutions and private companies and how they foster innovation in energy technologies and contribute to a low-carbon future. Professor LaBelle’s current research concentrates on the development of shale gas in

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Europe, smart energy technologies and how policies and regulations influence innovation in the energy sector. His previous work assessed the efforts of institutions in the European Union to encourage the use of new low- or zero-carbon technologies in the energy sector, including energy efficiency measures. Much of his research involves issues of risk governance, with special attention paid to the sunk cost of energy investments. Dr Ruben Laleman, Ghent University, Belgium Ruben Laleman obtained a Masters degree in Life Science Engineering at Ghent University in 2008, an additional Masters in Business Economics in 2009 and a PhD in Applied Economics in 2015, both from the same institution. He is a member of the Centre for Environmental Economics and Environmental Management (CEEM) and co-organiser of the ‘Economics of Electricity Markets’ international summer school at Ghent University. He has published articles in leading academic energy journals such as Renewable Energy and Renewable and Sustainable Energy Reviews. His research interests are focused on energy policy, renewable energy, energy transition and electricity markets. Tomás Lanardonne, Perez Alati, Grondona, Benites, Arntsen & Martinez de Hoz (Jr), Buenos Aires, Argentina Tomás Lanardonne holds a law degree cum laude from Universidad de Buenos Aires and a Masters in Administrative Economic Law cum laude from Universidad Católica Argentina. He obtained a Masters in Energy Law and Policy from the University of Dundee (CEPMLP), as a British Chevening Scholar. He is Special Counsel at the energy team of Perez Alati, Grondona, Benites, Arntsen & Martinez de Hoz (Jr) in Buenos Aires. Professor Dr Rafael Leal-Arcas, Centre for Commercial Law Studies, Queen Mary University of London, UK Rafael Leal-Arcas is Professor of European and International Economic Law at the Centre for Commercial Law Studies, Queen Mary University of London. He has a PhD (European University Institute, Florence), a JSM (Stanford Law School), an LLM (Columbia Law School), an MPhil (London School of Economics and Political Science), and a BA and LLB (Granada University), and is a 2015 Research Fellow for the Energy Community Secretariat. Professor Dr Leal-Arcas is a member of the Madrid Bar and author of the books International Energy Governance: Selected Legal Issues (Edward Elgar Publishing, 2014); Climate Change And International Trade (Edward Elgar Publishing, 2013); International Trade And Investment Law: Multilateral, Regional And Bilateral Governance (Edward Elgar Publishing, 2010) and Theory And Practice of EC External Trade Law and Policy (Cameron May, 2008). He is editor-in-chief of Renewable Energy Law and Policy Review. Professor Gavin F. M. Little, University of Stirling, UK Gavin Little is a Professor in the Stirling Law School, University of Stirling. He specialises in environmental law, and has particular interests in public law

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aspects of environmental governance and in interdisciplinary approaches to legal scholarship. The themes and issues sketched out in his chapter are analysed and developed in detail in his article ‘Developing environmental law scholarship: going beyond the legal space’ Legal Studies (2016, forthcoming). Dr Giorgio Locatelli, School of Civil Engineering, University of Leeds, UK Giorgio Locatelli is a Lecturer at the School of Civil Engineering at the University of Leeds. He has a Bachelor’s and a Masters degree in Mechanical Engineering and a PhD in Industrial Engineering, Economics and Management from Politecnico di Milano. His main research topic is infrastructural megaprojects, particularly in the energy sector, with a focus on the nuclear industry. He is author of more than eighty international publications, mostly on energy megaprojects. He also works as a consultant and visiting academic for several institutions, including the International Atomic Energy Agency. Professor Roberta F. Mann, University of Oregon School of Law, USA Roberta Mann is the Mr & Mrs L. L. Stewart Professor of Business Law at the University of Oregon School of Law, where she teaches Federal Income Tax, Business Tax and Tax Policy. Before teaching, she served on the staff of the Joint Committee on Taxation of the United States Congress and at the Office of Chief Counsel, Internal Revenue Service. Her scholarship focuses on the interaction between tax policy and the environment. Professor Anil Markandya, Basque Centre for Climate Change and Basque Foundation for Science, Spain Anil Markandya has worked in the field of resource and environmental economics for more than thirty years. He has held academic positions at the universities of Princeton and Harvard in the USA and at University College London and Bath University in the UK. He was a lead author for chapters of the third and fourth IPCC Assessment Reports on Climate Change (which were awarded a share of the Nobel Peace Prize in 2007) as well as one for the fifth IPCC Report published in 2014. In 2008 he was nominated by Cambridge University as one of the top fifty contributors to thinking on sustainability in the world. In 2012 he was elected President of the European Association of Environmental and Resource Economics and in 2013 became a member of the Scientific Council of the European Environment Agency. Anil Markandya is Director of the Basque Centre for Climate Change (BC3) in Bilbao and is honorary Professor of Economics at the University of Bath. Dr Marek Martyniszyn, Lecturer in Law, Queen’s University Belfast, UK Marek Martyniszyn specialises in the international and transnational aspects of competition law and policy, including the limits of extraterritorial jurisdiction and the issue of state involvement in anticompetitive practices. In broader terms, his research interests lie in international economic law. Before becoming Lecturer in the School of Law at Queen’s University Belfast, Dr Martyniszyn was a Senior Research Fellow in the Institute for Consumer Antitrust Studies at

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the Loyola University Chicago School of Law. He holds a PhD from University College Dublin and an LLM from the Europa-Institut at Saarland University. Dr Darren McCauley, Department of Geography and Sustainable Development, University of St Andrews, UK Darren McCauley held full-time lectureships at Trinity College Dublin, Queen’s University Belfast and the University of Stirling, as well as fellowships at the BMW Institute at Georgetown University in Washington, DC, the Institute for a Sustainable World at Queen’s University Belfast and the Centre for History and Policy at Stirling University. He is involved in a wide range of energy-based academic and commercially funded research and also retains a keen interest in complementary areas of research, seeking to understand technology-society relationships such as biofuels, biotechnology, micro-generation third-generation nuclear reactors. Professor John McEldowney, School of Law, University of Warwick, UK John McEldowney is a Professor in the School of Law and researches in the field of public law and environment law. Professor Owen McIntyre, School of Law, University College Cork, Ireland Owen McIntyre is a Senior Lecturer and Director of Research at the School of Law, University College Cork. His principal area of interest is environmental law and he currently serves as Chair of the IUCN World Commission on Environmental Law’s Specialist Group on Water and Wetlands; as a member of the Project Complaints Mechanism of the European Bank for Reconstruction and Development; and as a member of the Scientific Committee of the European Environment Agency. Francis McManus, Honorary Professor of Law, University of Stirling, UK and Emeritus Professor of Law, Edinburgh Napier University, UK Francis McManus’s research interests lie in the areas of environmental law and the law of delict, in relation to which he has published widely. He has a special interest in noise law. Gokce Mete, Centre for Energy Petroleum and Mineral Law and Policy, University of Dundee, UK Gokce Mete is concurrently undertaking doctoral-level research at the Centre for Energy Petroleum and Mineral Law and Policy at the University of Dundee as an AIPN Scholar. Her research examines EU internal gas market legislation, assessing its potential to attract investment into the energy infrastructure. Gokce is also a Research Fellow at the Energy Charter Secretariat, analysing the implementation of the Energy Charter, and is responsible for planning and managing the regular International Meeting of Experts on Reliable and Stable Transit jointly hosted by the ECS and Turkmenistan. She previously studied for her LLM at Queen Mary University of London, focusing on international

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investment arbitration in the energy sector. She has published on legal issues related to energy transit and cross-border pipelines. Professor Lutz Mez, Freie Universität Berlin, Germany Lutz Mez is Professor in Political Science at the Freie Universität Berlin. Since 1984, Dr Mez has been working at the Otto-Suhr-Institute for Political Science. He is co-founder of the Environmental Policy Research Centre and was its executive director until April 2010. In 2009 he became coordinator of the Berlin Centre for Caspian Region Studies (BC CARE) at the Freie Universität Berlin. Dr Mez is a specialist in the comparative analysis of nuclear power, energy and climate change policies. Dr Emanuela Michetti, Riga Graduate School of Law, Latvia Emanuela Michetti has a Masters degree in Economics and a PhD in Law and Economics, both from the University of Siena, Italy. An economist specialising in regulation, competition and consumer protection in network industries, in particular energy and transport, she has over ten years’ experience combining academic and industry positions. She has been Visiting Lecturer at the Riga Graduate School of Law since 2012, and currently works in a UK regulatory authority. Paul Murphy, Milbank, Tweed, Hadley & McCloy LLP, Washington, DC, USA Paul Murphy is Special Counsel in the Washington, DC office of Milbank, Tweed, Hadley & McCloy LLP and a member of the firm’s Global Project Finance Group. His practice focuses on multiple aspects of the nuclear industry, and he has made significant contributions to scholarship in the areas of the development and financing of nuclear power, working with the International Atomic Energy Agency, the OECD’s Nuclear Energy Agency, the International Framework for Nuclear Energy Cooperation and the US government. Rabindra Nepal, CDU Business School, Charles Darwin University, Australia Rabindra Nepal is a Lecturer in Economics at the CDU Business School, Charles Darwin University, Australia. Professor William J. Nuttall, Department of Engineering and Innovation, Open University, UK William Nuttall is a Professor of Energy in the Department of Engineering and Innovation at the Open University. Following a first-class degree in Physics from the University of East Anglia in 1987, he won a Fulbright Postgraduate Student Award to MIT to study for a PhD in Physics. On returning to the UK in 1993 he worked as a scientist at Keele and Birmingham universities and then for the Institute of Physics in science policy. He joined the teaching faculty of Cambridge University in 2002. In Cambridge he taught Technology Policy and held a shared post between Judge Business School and Cambridge University Engineering Department. He is author of Nuclear Renaissance Technologies

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and Policies for the Future of Nuclear Power (Taylor and Francis, 2005), coeditor of several other books and has written more than fifty journal articles. In 2011 Professor Nuttall was elected Fellow of the Institute of Physics. He is also a Fellow of Hughes Hall Cambridge. Professor Jouni Paavola, School of Earth and Environment, University of Leeds, UK Jouni Paavola is Professor of Environmental Social Science and Director of the ESRC Centre for Climate Change Economics and Policy (CCCEP) in the School of Earth and Environment at the University of Leeds. His research examines environmental governance institutions and their environmental, economic and social justice implications, with a focus on climate change and biodiversity. Dr Theodore C. Panagos, PFG Law Firm, Athens, and International Hellenic University, Greece Theodore Panagos is a lawyer by profession, Managing Partner at PFG Law Firm (Athens) and Visiting Professor in Energy Law at the International Hellenic University. He is former Vice-Chairman of the Regulatory Authority for Energy and former Member of the National Energy Council. He has authored books on the legal framework of unbundling in energy, energy markets and hydrocarbons and his articles have been published in various legal reviews. He was a member of the committee that granted authorisations for hydrocarbon exploration and exploitation projects. He recently published a series of articles concerning the energy policy approach between West and East. Dr Cheryl Parkhouse, Burges Salmon LLP, Bristol, UK Cheryl Parkhouse is a Senior Associate solicitor in the Nuclear Unit, Burges Salmon LLP, Bristol. She specialises in nuclear and environmental regulatory issues in decommissioning and new-build projects; radioactive contaminated land, waste disposal and licensing matters; and commercial transactions including nuclear supply chain contracts and agreements relating to various stages of the fuel cycle. Cheryl regularly advises on and has a particular interest in nuclear liability, including the negotiation of nuclear indemnities, both in on-site commercial transactions and in national and international nuclear transport agreements. Dr Roy Andrew Partain, School of Law, University of Aberdeen, UK Roy Andrew Partain, PhD (Law), JD, MSc (Econ), MSc (Econ), is a Reader of Energy Law at the School of Law within the University of Aberdeen. His energy law research applies a law and economics focus on unconventional or innovative sources of energy. Recent research has included studies on efficient mechanism design for the potential risks of offshore methane hydrate developments, on providing a law and economics foundation to liabilities from the operation of carbon capture and storage (CCS) facilities and on the potential liability regimes for novel forms of nuclear fusion energy devices.

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John Paterson, Centre for Energy Law, University of Aberdeen, UK Educated at the universities of Aberdeen and Edinburgh and at the European University Institute, John Paterson trained as a solicitor in the UK civil service before pursuing an academic career. He worked in Belgium and in England before moving to Aberdeen in 2004. He has long experience of international projects in research, teaching, training and consultancy in the energy field. He is co-editor of Oil and Gas Law: Current Practice and Emerging Trends (Dundee University Press, 2015) and co-directs the University of Aberdeen’s successful LLM programmes in Oil and Gas Law. Maria Pavlenko, West Sands Advisory Ltd, St Andrews, UK Maria Pavlenko is a Research Analyst at West Sands Advisory Ltd, a consultancy firm that specialises in supporting strategic decisions of businesses in the emerging and frontier markets. This involves conducting research to identify, analyse and monitor developments and trends that may impact commercial interests in a variety of sectors, e.g. financial, energy, political and legal, in Russia, CIS and Latin America. Maria retains a keen interest in energy-related topics with a focus on the sustainability of Arctic resource exploration. Her research interests are largely in the Arctic oil and gas businesses, in particular their behaviours in regards to stakeholders as well as their social accounting and corporate social responsibility practices. Professor Alison Peck, West Virginia University College of Law, USA Alison Peck is Professor of Law at West Virginia University, in the heart of the Marcellus Shale basin. She teaches and writes about natural resources, administrative process and environmental democracy, both USA and international, with special focus on agriculture and energy. Previous articles include ‘Does regulation chill democratic deliberation? The case of GMOs’, Creighton Law Review 46(4) (2013), 653–705, and ‘Sustainable development and the reconciliation of opposites’, St Louis University Law Journal 57 (2012), 151–84. She is currently researching comparative hydraulic fracturing law throughout the Americas to provide advice to legislatures in Argentina and elsewhere in updating oil and gas regulations for risk management related to unconventional oil and gas development. Sirja-Leena Penttinen, UEF Law School, University of Eastern Finland, Finland Sirja-Leena Penttinen is a Lecturer in European Law at UEF Law School. Her research interests include EU energy law as well as more general economic EU law. She is a member of the Centre of Climate Change, Energy and Environmental Law at the University of Eastern Finland. Professor Grischa Perino, Department of Socioeconomics, University of Hamburg, Germany Grischa Perino is a Professor of Economics at the University of Hamburg and a Research Professor at the Hamburg Institute of International Economics

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(HWWI). He has previously taught at the universities of East Anglia and Cambridge and received his PhD in 2007 from the University of Heidelberg, Germany. His research interests are in the area of environmental regulation and innovation. Saska Petrova, School of Environment, Education and Development, University of Manchester, UK Saska Petrova is a Lecturer at the University of Manchester. Her main research interests are in intra-community relations and vulnerabilities as they relate to natural resource management, energy flows, social justice and local governance. She is also the research coordinator of the Centre for Urban Resilience and Energy (CURE), which combines the work of twenty world-leading scholars focusing on the spatial and social dimensions of sustainability transitions. Many of the findings from her work are reported in her monograph Communities in Transition (Ashgate, 2014) as well as a number of papers in leading scientific journals such as Environment and Planning A, Urban Studies, Geoforum, Area, Energy Policy and Geojournal. Professor Ross H. Pifer, Penn State Dickinson School of Law, University Park, Pennsylvania, USA Working in the heart of the Marcellus Shale formation, Ross Pifer has given numerous presentations throughout Pennsylvania, across the USA and internationally on shale gas topics to audiences consisting of landowners, attorneys, judges, government officials, academics and the general public. He also has written a number of publications on shale law issues and, as Clinical Professor of Law at Penn State Dickinson School of Law, he teaches courses on Oil and Gas Law, Law and Policy of Shale Development, and Agricultural Law. He recently authored ‘Historical background of Pennsylvania oil and gas law’ for a treatise entitled ‘The law of oil & gas in Pennsylvania’. His current research includes effective governance of shale development globally; compulsory pooling of oil and gas interests in Pennsylvania; and a comprehensive review of the issues, questions, problems and opportunities that have arisen by and through shale development. At Penn State Law, he serves as the Director of the Center for Agricultural and Shale Law and the Director of the Rural Economic Development Clinic. Dr Jim Platts, Institute for Manufacturing, University of Cambridge, UK In the 1980s Jim Platts created the designs, the manufacturing processes, the team and the company that made all the wind turbine blades in the UK (now the Vestas global blade technology centre on the Isle of Wight). Now based in the University of Cambridge’s Institute for Manufacturing, he teaches manufacturing design and leadership and supervises many industrial projects globally. David Powell, Friends of the Earth (England, Wales & Northern Ireland), UK David Powell is Senior Economics Campaigner with Friends of the Earth, leading the organisation’s work on economics and finance as it affects environmental

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policy. He has an MSc in Environmental Policy, an MA in English Literature and a graduate diploma in economics. He has secured media coverage for his work quantifying and exposing the value of the government’s ‘field allowances’ for North Sea oil and gas – the subject of his chapter in this volume – and has presented on the topic to the UK Parliament. He has provided expert advice to the work of NGOs across the environment and development sector on oil and gas subsidies. Sebastian Radocea, Ţuca Zbârcea & Asociații, Bucharest, Romania Sebastian Radocea has wide-ranging experience in energy law (with a focus on the power and energy-efficiency sectors), M&A and corporate/commercial law. He is currently advising on the first-ever implementation in Romania of energy efficiency projects in the public sector, while having previously acted on some of the country’s highest-profile deals, such as the first unbundling of the power distribution and supply activities of a former State-owned utility, the acquisition by the largest utility company in Central and Eastern Europe of a minority stake in two power distribution and supply companies, and the development of the largest onshore wind farm project located in Romania. Dr Kaitlin T. Raimi, Assistant Professor, Gerald R. Ford School of Public Policy, University of Michigan, USA Kaitlin Raimi is a Social Psychologist and Assistant Professor, Gerald R. Ford School of Public Policy, University of Michigan. Formerly, she was a Postdoctoral Fellow at the Vanderbilt Institute for Energy and Environment. Her areas of interest include belief superiority, self-presentation, and the role of knowledge and ideology in the creation and maintenance of belief and behaviours related to climate change and the environment. Robert Rehner, Department of Geography and Sustainable Development, University of St Andrews, UK Robert Rehner was consultant and financial auditor at KPMG Germany for a range of different industries, including practitioners within the renewable energy sector, before joining the University of St Andrews as Research Fellow for sustainable energy. His research interests evolve around different energy sources and the implications of energy infrastructure on environmental and social structures. Complementary to this he is exploring possible electricity market implications in the context of the nuclear phase-out in Germany. Louise Reid, Department of Geography & Sustainable Development and Centre for Housing Research, University of St Andrews, UK Louise Reid is currently based at the University of St Andrews in the Department of Geography and Sustainable Development, where she is also Co-director of the Centre for Housing Research. Louise moved to St Andrews from the University of Aberdeen in 2010, initially taking up a research fellowship before moving into a lectureship in 2011. Louise’s research interests surround sustainable housing, particularly everyday low-carbon living and personal well-being.

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Dr Luis Rey, Basque Centre for Climate Change, Bilbao, Spain Luis Rey received his undergraduate education at the University of Navarra (Pamplona, Spain), where he obtained a degree in Economics in 2003. The following year he obtained a Masters degree in Economics and Finance at the University of Navarra. He holds a PhD in Economics from the European University Institute in Florence, Italy. He has worked at the consultancy firm Naider in Bilbao, Spain and the Economics for Energy research centre in Vigo, Spain. He currently works as a Postdoctoral Researcher at the Basque Centre for Climate Change (BC3). His research interests are energy economics, environmental economics and international economics. Professor Tara Righetti, University of Wyoming College of Law, USA Tara Righetti joined the University of Wyoming College of Law faculty in the autumn of 2014. Prior to that, she served as CEO and general counsel of a privately owned upstream oil and gas company with operations in six states and on the outer continental shelf. Professor Righetti teaches classes on Oil and Gas Law and Energy Transactions and Finance. Her other areas of interest include state-owned oil enterprises, pipeline law and the environmental design of energy man camps. Professor Righetti’s research focuses on legal issues related to development of oil and gas on split estates, local regulation of oil and gas development, royalty payment statutes and energy development on tribal land. She is currently working on several projects that cumulatively look at the impact of unitisation pursuant to the Mineral Leasing Act on surface access and use by the unit operator. David Robinson, Oxford Institute for Energy Studies, UK David Robinson is an independent consultant and Senior Research Fellow at the Oxford Institute for Energy Studies (OIES). His current research focus is on the design and regulation of energy markets to make liberalisation and decarbonisation compatible. Dr Katy Roelich, School of Earth and Environment and School of Civil Engineering, University of Leeds, UK Katy Roelich is a Senior Academic Fellow at the School of Earth and Environment and School of Civil Engineering, University of Leeds. Prior to joining Leeds Katy was co-leader of the Rethinking Development theme at the Stockholm Environment Institute and worked in environmental and engineering consulting in the UK and overseas for nine years. Her current research centres on the governance of sustainable transitions. Dr Franco Romerio, Institute for Environmental Sciences, University of Geneva, Switzerland Franco Romerio leads the Energy, Policy and Economics group at the Institute for Environmental Sciences (ISE), University of Geneva. He holds a PhD in Economics and a Masters in History, both from the University of Geneva, as well as a postgraduate degree in Energy from the Federal Institute of Technology in

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Lausanne (EPFL). His research focuses on the organisation of energy policy and electricity markets, hydropower, nuclear energy and risk management in the field of energy. He teaches Energy Economics and Policy at the University of Geneva and at the EPFL. Matthew Rooney, Energy Policy Research Group, University of Cambridge, UK Matthew Rooney is a Chartered Mechanical Engineer currently working towards a PhD in Energy Policy at the University of Cambridge. He holds an MEng in Mechanical Engineering from the Queen’s University of Belfast and an MPhil in Technology Policy from Cambridge Judge Business School. His PhD thesis is concerned with the deployment of large-scale baseload power plants and the value of building commercial-scale demonstration projects, with a focus on two technologies: advanced nuclear fission and fossil fuel combustion with carbon capture and storage. He has a particular interest in bringing together the concepts of technological learning, real options analysis and system dynamics. Professor Tony Roulstone, University of Cambridge, UK Tony Roulstone established and teaches on the Nuclear Energy Masters programme at the University of Cambridge and he is a Visiting Professor of Nuclear Engineering at City University in Hong Kong. His research interests are the economics and safety of nuclear power, including a special interest in small modular reactors. Áine Ryall, School of Law, University College Cork, Ireland Áine Ryall is based at the School of Law, University College Cork, Ireland. Her teaching and research interests focus on the intersections between international, EU and national environmental law, with a particular focus on implementation of the Aarhus Convention. This has led to a number of research projects on different aspects of access to justice in environmental matters. This contribution draws on a research project, ‘Mapping the Future of Environmental Justice in Ireland’, funded by an Irish Research Council New Foundations grant. Tristano Sainati, School of Engineering, University of Lincoln, UK Tristano Sainati is a PhD student and Assistant Lecturer in Industrial Engineering at the University of Lincoln. He has a Bachelor’s and Masters degree in Engineering from Politecnico di Milano. He has some years of experience as a researcher both at the University of Lincoln and at Politecnico di Milano. Professor Joachim Sanden, Law School, Leuphana University Lüneburg, Germany and Ministry for City Development and Environment of the Free and Hanseatic City of Hamburg, Germany Joachim Sanden is Extraordinary Professor at Leuphana University Lüneburg, Germany and Vice Director-General of the Directorate-General for Environmental Protection, Ministry of Urban Development and Environment of

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the Free and Hanseatic City of Hamburg, Germany. He is Visiting Research Fellow at the Centre for Conflict, Rule of Law and Society, University of Bournemouth, UK. His main area of expertise is in public law. Dr Samuel R. Schubert, Webster University, Vienna, Austria Samuel Schubert is an Assistant Professor of International Relations at Webster University in Vienna, Austria and author of several energy-related works on USA, UK and EU energy policy, EU-Russian energy relations and the effects of energy-resource wealth on state stability. His most recent work includes (with Johannes Pollak and Maren Kreutler), Energy Policy of the European Union (Palgrave, forthcoming 2016); ‘Lessons for European autonomy in space from past pursuits of energy autonomy’ in C. Al-Ekabi (ed.), European Autonomy in Space (Springer, 2015); and (with Elina Brutschin) ‘Two futures: EU-Russia relations in the context of Ukraine’, European Journal of Futures Research 2(1) (2014), 52–9. His research into energy-related national security matters dates back to 2006 when he published ‘Revisiting the oil curse’, Development 49(3) (2006), 64–70, which led to a 2007 study for the European Parliament, ‘Being rich in energy resources – a blessing or a curse’, that examined how aspects of a resource curse in many of the EU’s primary external suppliers affects the EU’s energy security. In addition to his scholarly research, Dr Schubert brings over a decade of policy experience through his work with the UN and think tanks. He is a graduate of George Washington University’s Political Science programme and earned his PhD at the University of Vienna writing on the relationship between national energy policies, international cooperation and conflict, and energy R&D. Dr Jack D. Sharples, Department of Political Science and Sociology, European University at St Petersburg, Russian Federation Jack Sharples is a Lecturer in Energy Politics at the European University at St Petersburg. His research interests are in the political economy of energy, energy geopolitics and EU–Russia energy relations, in particular state-business relations in Russia’s gas sector, the political economy of Russia’s gas exports to Europe, the role of Ukrainian gas transit in EU-Russia gas relations, EU energy security, and the development of the EU gas market and the prospects for Gazprom on that market. Dr Gireesh Shrimali, Steyer-Taylor Center for Energy Policy and Finance, Stanford University, USA Gireesh Shrimali is a Faculty Fellow at Stanford University’s Steyer-Taylor Center for Energy Policy and Finance, a joint centre of the Stanford law and business schools. Previously, he taught at the Indian School of Business (ISB), where he helped found, and continues to manage, the CPI-ISB Energy and Environment Programme in collaboration with the Climate Policy Initiative (CPI). His current research focus is on renewable energy finance and policy. At the Steyer-Taylor Center his research is centred on instruments for provision of low-cost, long-term capital for renewable energy in developing countries. His

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previous work has included topics such as analysis of India’s renewable policies; the impact of federal and state policy on the development and deployment of renewable energy in the USA; and business models for off-grid energy in developing countries. He holds a PhD from Stanford University, an MS from the University of Minnesota, Minneapolis, and a BTech from the Indian Institute of Technology, New Delhi, all in Electrical Engineering. He has over nine years of industry experience. Roman Sidortsov, Scott Polar Research Institute, University of Cambridge, UK and Institute for Energy and the Environment, Vermont Law School, USA Roman Sidortsov serves as a Senior Global Energy Fellow at the Institute for Energy and the Environment and teaches Oil and Gas Development and Renewable Energy courses in the distance-learning programme. He is also a Doctoral Researcher at the Scott Polar Research Institute at the University of Cambridge, UK. Mr Sidortsov has taught at Irkutsk State Academy of Law and Economics in Russia and at Marlboro College Graduate School’s Managing for Sustainability programme in the USA. Prior to returning to academia, he practised law in Russia as in-house counsel for an American non-profit organisation, and in the USA as a transactional attorney. His research focuses on legal and policy issues related to the development of sustainable energy systems, energy justice, energy geopolitics, risk governance in the oil and gas sector, and Arctic offshore oil and gas exploration and extraction, with a special emphasis on the Russian Federation, Norway and the USA. He received his first law degrees (Bachelor’s and Masters) from Irkutsk State University in the Russian Federation and his JD and LLM degrees from Vermont Law School. Navraj Singh Ghaleigh, Edinburgh Law School, University of Edinburgh, UK Navraj Singh Ghaleigh is Senior Lecturer in Climate Law at the University of Edinburgh where he teaches at the Law School, Business School and School of Geosciences. His research is both interdisciplinary, focusing especially on economics and PIL, and transnational, with a particular interest in East Asian climate law. He is involved with various learned societies including the Society of Legal Scholars, the Royal Society of Arts and Climate Strategies. James W. Skelton, Jr, Adjunct Professor of Law, University of Houston Law Center, Attorney at Law and International Legal Consultant, USA James Skelton has practised law for nearly forty years, primarily specialising in international and domestic petroleum transactions. He worked for Conoco/ ConocoPhillips for twenty-eight years, most of which were spent handling upstream international oil and gas transactions. After retiring in 2008, he reentered private practice and also began teaching at the University of Houston Law Center, where he is Adjunct Professor of Law. He has published thirteen articles and two book reviews in legal periodicals, made presentations at fourteen legal conferences in Houston, Dallas, London and Moscow, and coauthored the textbook Doing Business in Emerging Markets: a Transactional Course (Foundation Press, 2014).

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Professor Eric R. A. N. Smith, University of California, Santa Barbara, USA Eric R. A. N. Smith is a Professor in the Department of Political Science and affiliated with the Bren School of Environmental Science & Management and the Environmental Studies Programme at the University of California, Santa Barbara. His research focuses on environmental politics, public opinion and elections. Steve Sorrell, Science Policy Research Unit and Centre on Innovation and Energy Demand, University of Sussex, UK Steve Sorrell is a Senior Lecturer at the Science Policy Research Unit (SPRU) and Director of the Centre on Innovation and Energy Demand, University of Sussex, as well as an energy and climate policy specialist with over twenty years of experience in applied, problem-oriented research that is relevant to both academic and stakeholder audiences. Steve’s areas of expertise include resource depletion and the economics of energy efficiency, including in particular the phenomenon of ‘rebound effects’. Professor Benjamin K. Sovacool, Centre for Energy Technologies, Department of Business and Technology, Aarhus University, Denmark and Science Policy Research Unit, University of Sussex, UK Benjamin Sovacool is Professor of Business and Social Sciences and Director of the Centre for Energy Technologies, Department of Business and Technology, Aarhus University, Denmark and Professor of Energy Policy, Science Policy Research Unit, University of Sussex, UK. His chapter in this volume draws from and extends the arguments presented in a forthcoming book to be published by Johns Hopkins University Press in 2016, entitled Fact and Fiction in Global Energy Policy: Fifteen Contentious Questions. Dr Joseph V. Spadaro, Basque Centre for Climate Change, Bilbao, Spain Joseph Spadaro is an Environmental Research Scientist with a PhD in Energy from the Ecole Nationale Supérieure des Mines de Paris, France. He is presently Research Professor at the Basque Centre for Climate Change (BC3) in Bilbao, Spain, where he has been involved in several projects funded by the European Commission, including the PURGE Project, in the role of senior scientific investigator at BC3, and the BASE Project, leading the work on the impact assessment of climate extremes and human health. In addition to ongoing work on air pollution, his interests include research on the nexus between prioritisation of long-term techno-economic options in support of urban climate adaptation and clean air policies; the reduction of health vulnerability; and ways to bring about changes in consumer attitudes and consumption patterns related to energy use, household purchases and diets. He is co-author of the book How Much is Clean Air Worth? Calculating the Benefits of Pollution Control (Cambridge University Press, 2014). Aaron C. Sparks, University of California, Santa Barbara, USA Aaron Sparks is a PhD student at the University of California, Santa Barbara. He studies environmental politics and policy within the American system. He

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is interested in better understanding the individual-level motivations for political participation and its connection to policy-making, especially in regards to energy and environmental issues. Hannes R. Stephan, University of Stirling, UK Hannes Stephan is a Lecturer in Environmental Politics and Policy at the University of Stirling. He conducts research on various aspects of environmental politics, covering global, European and national levels of analysis. He is particularly interested in energy justice/security, climate change, the governance of sustainability and agricultural biotechnology. His recently published monograph – a comparative study of the politics of GM food and crops in the USA and the EU – is entitled Cultural Politics and the Transatlantic Divide over GMOs (Palgrave, 2015) and his current research explores the politics of unconventional gas in Scotland. Hannes Stephan is a co-convenor of the Environmental Politics Standing Group of the European Consortium for Political Research (ECPR). Lucie Stevenson, Economics Division, Stirling Management School, University of Stirling, UK Lucie Stevenson works as a Compliance Systems Graduate within the Sustainable Solutions Business Unit at Jacobs Engineering UK, where she is involved in a range of projects relating to energy, carbon and environmental management. Lucie has an MSc in Energy Management from Stirling University and a BA in Applied Social Sciences from Robert Gordon University. Professor Temple L. Stoellinger, College of Law and Haub School of Environment and Natural Resources, University of Wyoming, USA Temple Stoellinger joined the University of Wyoming in 2013. She has a dual appointment with the College of Law where she is the Co-director of the Center for Law and Energy Resources and an Adjunct Assistant Professor at the Haub School of Environment and Natural Resources. Temple is a Faculty Supervisor for the University of Wyoming’s Energy, Environment and Natural Resources Law Clinic and teaches a variety of Energy and Natural Resources courses. Before joining the University of Wyoming, she worked in the Projects and Technology Legal Department for Shell, International B.V. at their world headquarters in the Netherlands. From 2004 to 2010 she served as a natural resource analyst and advisor to then Wyoming Governor Dave Freudenthal where she had the opportunity to work on a wide variety of energy and natural resource issues of state-wide, regional and national significance. Professor Lindsay C. Stringer, School of Earth and Environment, Sustainability Research Institute, University of Leeds, UK Lindsay Stringer is Professor in Environment and Development at the Sustainability Research Institute (SRI) of the School of Earth and Environment at the University of Leeds. Lindsay’s research advances understanding of human-environment relationships, focusing on the links between livelihoods

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and environment; and science, policy and environmental governance, with particular emphasis on the land, climate, water and energy sectors. Professor Sanna M. Syri, Department of Energy Technology, Aalto University, Finland Sanna Syri is Professor in Energy Economics at the Department of Energy Technology, Aalto University. Professor Syri’s fields of research and expertise are energy economics, mitigation of climate change, EU-wide energy and climate policy, and electricity markets. She is frequently consulted by the Finnish Parliament to support national-scale decisions in environmental and energy policies. She is also a member of the Finnish Climate Panel, appointed by the Minister of Environment, and leader of many research projects, such as Sustainable Transition of European Energy Systems (STEEM), supported by Aalto University’s Energy Efficiency platform. Dr Robert Szuchy, Department of Commercial and Financial Law at the Faculty of Law of Károli Gáspár University, Hungary Robert Szuchy is an Associate Professor in the Department of Commercial and Financial Law at the Faculty of Law of Károli Gáspár University, Budapest, Hungary. He holds a PhD in Competition Law and is author of several articles in the field of competition, business and energy law. His main fields of research are the regulatory frameworks of the electricity market, competition law in the energy market and energy price regulation. Professor Kim Talus, University of Eastern Finland and University of Helsinki, Finland Kim Talus is a Professor of European Energy Law at the University of Eastern Finland Law School and a Professor of Energy Law at the University of Helsinki. He is also the editor-in-chief of OGEL and an expert member (electricity) at the Finnish Market Court. Professor Dan Tarlock, Chicago-Kent College of Law, Chicago, Illinois, USA Dan Tarlock is Distinguished Professor of Law at the Chicago-Kent College of Law in the Illinois Institute of Technology and holds an AB and LLB from Stanford University. He has taught and written in the fields of environmental, land use, energy, natural resources and water resources law. He has also participated in the Water Science and Technology Board of the National Research Council-National Academy of Sciences’ assessments of aquatic ecosystem restoration on large river systems. Since 2014, Professor Tarlock has served as a member of the Technical Committee of the Stockholm-based Global Water Partnership. Dr Simon Taylor, Judge Business School, University of Cambridge, UK After studying economics at Cambridge, Oxford and the London School of Economics, Simon spent nine years as an equity analyst at a number of investment banks, including BZW, JPMorgan and Citigroup, where he was involved

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in several major equity transactions and takeovers and led research teams covering the European and global utilities sectors. In 2001 he became Deputy Head of European Equity Research at JPMorgan where he had management responsibility for the technical and quantitative research teams and for the technology, media and telecoms sectors. He joined Cambridge University’s Judge Business School in 2007 as Lecturer in Finance and is the Director of the Cambridge Master of Finance degree. He is a Research Associate of the Energy Policy Research Group. In 2009 he was awarded a Cambridge University Pilkington Teaching Prize. His book on the history of nuclear power in the UK will be published in 2016. Anastasia Telesetsky, Associate Professor, University of Idaho College of Law Natural Resources and Environmental Law Programme, and Member of the International Union for Conservation of Nature’s World Commission on Environmental Law Anastasia Telesetsky is an Associate Professor of Law at the University of Idaho College of Law where she teaches in the Natural Resources and Environmental Law Program. Her research focuses on sustainability and marine resources. Her LLM is from the University of British Columbia and she holds a JD from UC Berkeley. Professor Philippe Thalmann, Ecole Polytechnique Fédérale de Lausanne, Switzerland Philippe Thalmann obtained a diploma in Economics from the University of Lausanne in 1984 and a PhD in Economics from Harvard University in 1990. Since 1994, he has been Professor of Economics at the Swiss Federal Institute of Technology, Lausanne. He teaches and publishes on the economics of the housing, property and construction markets, and the economics of the environment, climate change and sustainable development. Professor S. D. Thomas, Business School, University of Greenwich, UK S. D. Thomas was a member of the energy policy group at the Science Policy Research Unit at Sussex University from 1979 to 2000. Since then, as Professor of Energy Policy, he has led the energy research in the Public Services International Research Unit at Greenwich University. His main research areas are economics and policy for nuclear power; liberalisation and privatisation of energy industries; and corporate policies of energy companies. Dr Thomas P. Triebs, Ifo Institute – Leibniz Institute for Economic Research at the University of Munich, Germany Thomas Triebs specialises in empirical work on production, productivity and management and applies productivity and efficiency measurement to issues regarding policy, management and regulation.His background combines economics, management and policy. He holds a PhD from Judge Business School, Cambridge and an MA (Econ) from Maastricht University.

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Dr Paul Upham, Sustainability Research Institute and Centre for Integrated Energy Research, University of Leeds, UK Paul Upham is Senior University Research Fellow at the Centre for Integrated Energy Research and Sustainability Research Institute, University of Leeds. Paul works on energy technology governance, particularly on public engagement in socio-technical transitions. He has been Visiting Professor in Governance of Energy Systems and Climate Change at the Finnish Environment Institute (SYKE), Helsinki; and Senior Research Fellow at the Tyndall Centre for Climate Change Research (University of Manchester) and Manchester Business School. Professor Geert van Calster, University of Leuven, Belgium Geert van Calster is a Professor in the University of Leuven and Member of the Brussels Bar. Professor Michael P. Vandenbergh, Law School, Vanderbilt University, USA Michael Vandenbergh is the David Daniels Allen Distinguished Chair of Law, Director of the Climate Change Research Network and Co-director of the Energy, Environment and Land Use Program at Vanderbilt University Law School. His areas of interest include environmental law, private environmental governance and the social influences on household energy behaviour. Wouter Vandorpe, Energy & Utilities Practice, Fieldfisher (Field Fisher Waterhouse LLP), Brussels, Belgium and Institute for Environmental and Energy Law, Catholic University of Leuven, Belgium Wouter Vandorpe is a Brussels-based energy and utilities lawyer at Fieldfisher (Field Fisher Waterhouse LLP), Senior Associate Energy Practice, scientific researcher at the Institute for Environmental and Energy Law, Catholic University of Leuven, Belgium and a member of the editorial staff of Milieu- en Energierecht, a journal on environmental and energy law. He holds an LLM in Energy and Environmental Law from the Catholic University of Leuven and has been a member of the Brussels Bar Association since 2006. He advises enterprises and authorities primarily on matters related to energy law, including electricity and gas market regulations, renewable energy projects, liberalisation issues and interconnections, energy efficiency and energy performance related issues, drafting of energy contracts, and EU implementation topics. He regularly acts before the Belgian Council of State and Constitutional Court, and before the European Court of Justice. Professor Yuliya Vashchenko, Department of Administrative Law, Faculty of Law, Taras Shevchenko National University of Kyiv, Ukraine Yuliya Vashchenko received her LLM in 1999 and her PhD in 2003 from Taras Shevchenko National University of Kyiv, Ukraine. Since 2003, she has been an Associate Professor of the Administrative Law Chair of the Faculty of Law at Taras Shevchenko National University of Kyiv. Her fields of expertise include administrative and regulatory law, energy law and human rights law. She is

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author of over seventy scientific publications and actively participates in drafting energy legislation in Ukraine. Shelagh Whitley, Research Fellow, Overseas Development Institute, London, UK Shelagh Whitley’s research is focused on private climate finance and the role of subsidies in shaping private investment. Prior to joining the Overseas Development Institute (ODI) she worked in the carbon markets, on clean-energy finance and climate policy development within the public and private sectors. From 2006 to 2011 Shelagh worked for Camco, a carbon project developer, working on the origination, execution and financing of compliance and voluntary carbon projects covering a range of low-carbon technologies in regions including Asia, Africa and North and South America. Shelagh was Chair of the Carbon Markets and Investors Association (CMIA) Voluntary Market stream, and is currently Vice-Chair of the Technical Advisory Committee of the Gold Standard. From 2004 to 2006 Shelagh was a Project Manager with the Climate Group, a non-profit organisation dedicated to advancing business and government leadership on climate change, where she ran a finance-sector leadership group and contributed to the development of the Voluntary Carbon Standard (VCS). Shelagh has a Masters Degree in International Environmental Policy and Finance from the Fletcher School at Tufts University in the USA, and a Combined Honours BSc in Biology and International Development Studies from Dalhousie University in Canada. Konstantin Winter, Berlin Centre for Caspian Region Studies, Freie Universität Berlin, Germany Konstantin Winter was awarded an MA in Political Sciences at the Freie Universität Berlin. He wrote his thesis on the dimensions of German natural gas supply security. He has been a Research Assistant at the Berlin Centre for Caspian Region Studies (BC CARE) since 2011, and has published several articles regarding security and energy policy in Central Asia and the Caspian Sea region. Dr Geoffrey Wood, School of Law, University of Stirling, UK Geoffrey Wood holds an MSc in Renewable Energy and Environmental Modelling and a PhD in Energy Law, Policy and Regulation, both from the University of Dundee. Currently he is a Teaching Fellow in International Energy Law and Policy at the University of Stirling and a contributing lecturer at the University of Dundee. An interdisciplinary researcher, his work focuses on the development of legal and governance frameworks for renewable and low-carbon energy transitions that enables the appropriate market framework and policy environment for new energy technology deployment. Olivia Woolley, School of Law, University of Aberdeen, UK Olivia Woolley is a Lecturer in Energy and Environmental Law in the School of Law at the University of Aberdeen. In her research she examines how law can be used to support the growth of renewable energy consumption as part of

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a low-carbon energy transition. Ecological Governance, a book based on her doctoral research concerning the development of legal frameworks for preserving ecosystem functionality, was published by Cambridge University Press in 2014. Behnam Zakeri, Department of Energy Technology, Aalto University, Finland Behnam Zakeri is a Doctoral Researcher in the fields of energy systems analysis, energy economics and power markets. He has recently examined the possible role of energy storage systems in the future high renewable energy scenarios. His work on the economics of energy storage in the Nordic power market was acclaimed as one of the best papers in the eleventh International Conference on European Energy Markets (EEM 2014), Krakow, Poland. He is also studying the benefits of flexibility solutions, including energy storage for the island energy systems and is also a member of the STEEM multidisciplinary research project. Gerardo Zarazua de Rubens, Cornwall Energy, UK Gerardo Zarazua de Rubens is a Research and Strategy Analyst at Cornwall Energy, where his current role focuses on researching international energy markets and development strategies for regional constructs of electricity supply, including the democratisation of energy production. Gerardo holds a Master of Science with distinction in Sustainable Development (2014) from the University of St Andrews, UK, and a Bachelor’s degree in International Business (2012) from the Tecnológico de Monterrey (ITESM-CEM), Mexico, which included two periods of study abroad at the universities of Nottingham and Exeter. His research interests focus on energy and climate policy, the governance for low-carbon economies and pressing issues of sustainable development, such as water security. Dr Tao Zhang, Lecturer in Marketing and Sustainability, Birmingham Business School, University of Birmingham, UK Tao Zhang is Lecturer in Marketing and Sustainability at Birmingham Business School, University of Birmingham. He gained his PhD in Energy Economics from the Energy Policy Research Group, Judge Business School, University of Cambridge. His research interests are in the areas of energy economics and policy, energy consumer behaviour and innovation management, and agent-based modelling for the energy market. He is a founding member of the Environmental and Energy Economics and Management research cluster in Birmingham Business School, an associate researcher of the ESRC Energy Policy Research Group and an external advisor to the State Grid Corporation China.

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ACKNOWLEDGEMENTS

I extend my sincere thanks to all those who have inspired me on my academic journey to date and who consequently, in some small way, contributed to this book. My sincere gratitude also goes to my family for their assistance and understanding during the book’s production. And finally, this book is: Le haghaidh mo bhean chéile agus mo h-oileán Raphael J. Heffron, September 2015 For Ian and Olivia. Gavin F. M. Little, September 2015

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TABLES AND FIGURES

TABLES 11.1 Important US energy legislation since 1973 14.1 Tax expenditure for fossil fuels, renewables and efficiency: 2009 dollars 26.1 Current figures (2013) and quantitative targets of the Energiewende 43.1 Comparisons of risk bearing among current and likely new nuclear projects 44.1 UK nuclear new-build programme 44.2 National nuclear programmes compared 53.1 Pull/push ratio for wind and PV in the EU 53.2 Pull/push ratio for wind and PV in the EU with a five-year time lag for RD&D efforts 63.1 Categorising water contamination harms from shale development 80.1 EU and UK policy on energy demand reduction 82.1 Estimation results 93.1 Energy regulations in Malta 98.1 Planning inspectorate projects, December 2014 108.1 Electricity utility data from California, Colorado, Oregon and New York 108.2 Comparison of the different mechanisms applied by the four electric utilities 108.3 Competitive mechanism design elements applicable to the UK context 115.1 Classification of the instruments by policy landscapes 115.2 Vehicle registration tax rates in Spain, 2008 115.3 Feed-in tariffs for RES in Spain, 2012

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58 76 131 226 231 234 286 287 337 425 441 498 521 572 573 576 612 614 616

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FIGURES 14.1 30.1 30.2 32.1 32.2 32.3 51.1 53.1 53.2 76.1 76.2 77.1

82.1 89.1 99.1 99.2 110.1 124.1

125.1

Impact of the wind PTC Volatility of CO2 emission allowances Volatility of oil prices Weekly load patterns – winter and summer UK energy flows, 2008 Daily wind energy output, winter 2008–9 Basic innovation process for energy RD&D budgets in the EU for PV and wind Deployment costs for PV and wind in the EU Gas consumption and CO2 emissions associated with heating 180 litres of water to a range of output temperatures Simplified schematic diagram showing the configuration of hot water cylinders and thermal stores HeaTmaPPE: model of healthy living temperatures and physiological, psychological and environmental responses in cold temperatures Typical best–worst scaling task The various aspects of energy governance Gasoline prices and political participation Energy intensity per unit of GDP The ‘Rio Model’ of multi-level sustainability governance The annual costs of three EES technologies compared with the possible yearly benefits in competitive marketplaces in the Nordic power market Main investment risks

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77 155 156 165 165 169 275 285 286 401 402

410 440 474 529 531 588

666 672

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PREFACE

This Reader, as its title suggests, introduces a range of perspectives on energy law and policy issues from across the EU and the US. It provides perspectives not only from practising energy lawyers and legal scholars but also from scholars across the social sciences and sciences. The aims of the book are to constructively criticise current provision, to explore fresh options, to inspire and drive forward new debate on energy law and policy, to engage other disciplines with ‘energy lawyers’ and to reach out to policy-makers. The inspiration behind the project was John Brockman’s book This Book Will Make You Smarter (Transworld Publishers, 2012). While it is not possible to put all the experts who contributed in the same room at the same time as John Brockman has sought to do over time, putting their views in the same book is, we think, a good first step. We hope the book will be useful for undergraduates and postgraduates who should not only benefit academically from reading the contributions but should also gain an appreciation of the more practical aspects of research in the field. In addition, they can see who the leading researchers are in relation to a particular topic. And there may even be some ideas that will stimulate a PhD or future research project! As is apparent from many of the contributions, the impact that the energy sector has on our lives is enormous. However, the most important point to be made overall is that we need to be ambitious when we think of the energy sector. And in this regard we agree with Professor Steven Chu (Professor at the University of California, Berkeley), a former US Secretary of State for Energy, who in his visiting lectures to universities in the United Kingdom in 2014 implores researchers to think more ambitiously when we consider the energy sector and what we as humans can achieve in this area. We have borrowed a quote which he regularly includes in his talks: The greater danger for most of us lies not in setting our aim too high and falling short; but in setting our aim too low, and achieving our mark. Michelangelo

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Finally, we wish to thank all those who contributed to this project and hope they will enjoy the collection of ideas. We are indebted to each of the authors for rising to the challenge of preparing the varied and wide range of articles. Their encouragement along the way was much appreciated. We are also very grateful to the Clark Foundation for Legal Education, based in Edinburgh, for financial support and all those at Edinburgh University Press, notably John Watson and Rebecca Mackenzie, for their assistance in bringing the project to fruition. In particular, we would like to thank Ellie Bush for her patience and for meticulously overseeing the project and its completion into a book. Raphael J. Heffron and Gavin F. M. Little, September 2015

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INTRODUCTION

There are laws and there are policies. This book addresses their effectiveness and analyses law and policy in terms of delivery. It tackles one of the most complicated of law and policy areas – energy. Energy law and policy experts from across the European Union and the United States have contributed short chapters analysing current provision and considering how best to achieve energy policy objectives. Perspectives are offered from a range of disciplines, including the sciences, law, politics, economics and engineering. From evaluating policy delivery on wind farms in Texas in the US, to developing nuclear power across Europe, this book presents fresh thinking on key concepts and ideas on energy law and policy delivery in a concise and readable format. The book, which consists of 125 contributions from a total of 147 energy experts, has the aim of making a significant contribution to the development of new ideas on effective policy delivery in the energy field. It provides fresh, inspirational, controversial and interdisciplinary perspectives for policymakers, researchers, students and the public. ‘Energy’ has taken on a new significance beyond that of the laws of physics. From being the province of scientists and engineers, it is now, thanks to global polices on the environment and climate change and the need to develop massive new energy-generation capacity, something of a hot topic for politicians, policy-makers and lawyers. Moreover, it is likely to remain so for the foreseeable future. The issues involved are extremely complex; this is because the energy sector has a long-term orientation. New, large energy infrastructure projects generally take years to plan, develop and build and they then often have operating time-scales greater than the average human life-span. Meanwhile, technologies and scientific understanding develop constantly. In this context, governments struggle to support or indeed develop and deliver new energy policies. ‘Energy law’ and its study is interlinked with energy policy. Energy law as an academic subject has begun to emerge in universities, and there is an increasing number of dedicated postgraduate law programmes across the

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world, particularly in the European Union. This is mirrored in the legal profession, with the majority of international firms and even large national law firms having distinct and separate energy law divisions, which are gearing up to work on the development of major new energy infrastructures. Major themes to be explored in these chapters are therefore the issues involved in designing, implementing and utilising legal frameworks for new energy infrastructure development and how they can be factored into policy decisiontaking effectively. The chapters have been grouped together to form 15 parts, representing the current and key areas in energy law and policy delivery. As the book contains 125 chapters from contributors, we as editors do not want to draw attention to particular contributions. Rather, we would like readers to embark on their own journeys through it. There is much intellectual richness to be found on the way. We hope that this collection of essays will inspire new thinking and ideas in scholarly research and in the energy sector in general.

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SIX MAXIMS FOR INFORMED ENERGY ANALYSIS AND POLICY Benjamin K. Sovacool1

INTRODUCTION Given the often contested nature of different energy technologies and resources, this chapter offers some fruitful guidance to help readers improve analytical skills in energy planning and decision-making. The following six maxims can help bring far better perspective and understanding to the analysis of energy problems. Members of the general public: this will make you better citizens; and policy-makers: this will make you better practitioners. 1. Know the players – to reveal competing interests, understand where power lies and how it manifests itself in energy decisions 2. Inform yourselves – to counter rapidity of change, keep up to date and educate yourself about energy technologies and issues 3. Be prudent about risk – to manage risk and uncertainty, attempt to make energy decisions that are based on clear ethical principles and are well informed by data 4. Seek diversity and inclusivity – to avoid undemocratic exclusion and opposition by special interest groups, remember that energy decisions must meet the needs of a broad spectrum of citizens and stakeholders

1

Benjamin Sovacool is Professor of Business and Social Sciences and Director of the Centre for Energy Technologies, Department of Business and Technology, Aarhus University and Professor of Energy Policy, Science Policy Research Unit, University of Sussex. His chapter in this volume draws from and extends the arguments presented in a forthcoming book to be published by Johns Hopkins University Press in 2016, entitled Fact and Fiction in Global Energy Policy: Fifteen Contentious Questions. The author appreciates the generous feedback from his co-authors Marilyn A. Brown and Scott V. Valentine for helping him refine the analysis depicted here.

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5. Practise self-reflection – to understand underlying ideologies, strive to become aware of your own ideological frames that might prohibit a balanced analysis 6. Embrace technological agnosticism – to avoid energy evangelism, look beyond a given energy technology to the services it provides and recognise that many systems can deliver the same service. KNOW THE PLAYERS This postulate is to seek to know the players: make the interests behind an energy system transparent, acknowledge trade-offs and expect pushback. Readers can start by making an attempt to understand the undercurrents in support of a given energy system. In short: continually ask, ‘Energy for whom?’ or ‘Who benefits from a particular technology or decision?’. Understanding the relationship between power and technological dominance is important on three levels. First, it reminds us that the existing energy regime – with its gas stations, oil refineries, electric substations, transmission lines, expansive natural gas pipelines, coal mines and varying types of generating and consuming technology – was and is by no means inevitable. Instead, the success of incumbent technologies is the product of coercion, competition and politicking. Since the current system was created and entrenched by people, it can also be changed by people, but to do so requires competitive engagement with powerful foes. Second, clarifying the reasons why certain stakeholder groups support certain energy technologies allows us to study and analyse the enabling factors that create winners and losers. The implication of this is that a technology can acquire market appeal in two ways – by possessing superior technology or by possessing stakeholder appeal. The Danish wind power industry is a case in point. Initially, the Danish government’s strategy was to encourage large manufacturing concerns to lead a wave of wind power development that was predicated on economies of scale. When it became apparent that larger firms were not interested in this market niche and that support for wind power was largely predicated on support from farmers and farming cooperatives, the government altered its policy to encourage cooperative investment.2 The success of this is now evident when viewing the vistas of virtually every rural area throughout Denmark. Third, revealing competing interests highlights that competition will always exist among certain energy options, meaning we should expect pushback as there will inevitably be losers amidst any change. Satisfying everybody or every energy objective is an elusive practice. As evidence of this, one study investigated five distinct strategic approaches designed to lessen a country’s dependence on imported fuels, provide energy services at the cheapest price possible, enable

2

S. V. Valentine, Wind Power Politics and Policy (Oxford University Press, 2014).

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universal access to electricity grids, mitigate greenhouse gas emissions and foster energy systems that can operate under conditions of water stress and scarcity.3 The study concluded that all five strategies were, more often than not, in conflict with each other. A group that supports climate change mitigation might support a ramped-up presence for nuclear power whereas a group supporting water security might seek to phase out nuclear power. No single strategy optimised all energy security criteria. INFORM YOURSELVES To counter rapid changes in energy technologies, prices, resources and so on, readers should stay informed. Critical to this challenge is ensuring that the source of your knowledge is diverse to avoid becoming biased by the media or others. Policy-makers and planners should also support public education outreach programmes. Thomas Jefferson is attributed as having said that ‘a democratic society depends upon an informed and educated citizenry’, but that, in order for education to occur, people had to be informed ‘even against their will’.4 With that said, information and education programmes must be carefully tailored to suit the audience. Information is less likely to be used if accessing or interpreting it requires a Sherpa. When stakeholder engagement is an objective of an education campaign, change directed at behaviour that is perceived to be directly under the individual’s control, involves few barriers or adjustments and includes built-in incentives (or has an absence of disincentives) tends to be the easiest to initiate.5 Psychologists Bator and Cialdini, for example, have found that public information campaigns can accomplish their goals if they (1) recognise saturation and realise that their message must compete with thousands of others; (2) set achievable goals that emphasise moderate and easy changes in behaviour; and (3) target specific audiences and thoroughly understand the demographics, lifestyles, values and habits of that audience.6 When structured this way, public information campaigns have changed norms and shifted social attitudes. This is exemplified by specific programmes in relation to mitigating household hazardous waste disposal and littering, reducing these undesirable behaviours by 10 to 20 per cent.7

3

4 5

6

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B. K. Sovacool and H. Saunders, ‘Competing policy packages and the complexity of energy security’, Energy 67 (2014), 641–51. Quoted in B. K. Sovacool, Dirty Energy Dilemma (Prager, 2008), p. 213. A. R. Carrico, P. Padgett, M. P. Vandenbergh, J. Gilligan and K. A. Wallston, ‘Costly myths: an analysis of idling beliefs and behavior in personal motor vehicles’, Energy Policy 37(8) (2009), 2881–8. R. J. Bator and R. B. Cialdini, ‘The application of persuasion theory to the development of effective proenvironmental public service announcements’, Journal of Social Issues 56(3) (2000), 527–41. M. P. Vandenbergh, ‘From smokestack to SUV: the individual as regulated entity in the new era of environmental law’, Vanderbilt Law Review 57 (2004), 515–610.

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BE PRUDENT ABOUT RISK To learn to discern risk and uncertainty, another maxim must be pursued: strive to be comprehensive and search for the hidden linkages. At its core, any emergent technology can be considered to be a response to some earlier flawed technology. Therefore, all new technologies will inevitably possess weaknesses that an analyst must try to somehow identify. A truly prudent energy strategy is one that is comprehensively informed, inter-disciplinarily aware and ethical. Just as the technological options in the energy sector are diverse, so are the criteria for judging acceptability of a given technology. Specifically, the following types of questions can be raised whenever one considers the desirability of a particular energy technology or pathway: 1. 2. 3. 4. 5. 6. 7.

Does it harm the environment? Does it degrade the social structure of local communities? Does it damage traditional culture? Does it benefit local economies and utilise local resources? Does it provide education or local participation? Does it promote efforts aimed at conservation and efficiency? Does it foster the well-being of future generations?

While the importance of such questions may appear blatantly obvious, most assessments of energy technology continue to ignore the entire range of possible impacts a given energy system can have on society. Further complicating evaluation, some technological decisions serve some social and environmental goals while directly undermining others. For instance, the deployment of a large, nuclear plant in a small, rural community could greatly benefit a select few in the local economy and might even be of value in stimulating industrial growth, but it would also put the community at risk for the sake of electricity that will largely be exported to remote power markets, or put them in danger of a catastrophic accident. Similarly, building a large dam may help displace a polluting coal plant (thus improving the environment), but in the process destroy aquatic habitats and force widespread relocation of homes and businesses. SEEK DIVERSITY AND INCLUSION To minimise exclusionary forms of decision-making, the fourth postulate suggests that the diverse viewpoints and public needs must be comprehensively woven into energy policy decisions. This helps appease competing factions and reduces the costs associated with stakeholder dissent and opposition. Moreover, inclusion of input from diverse actors spread across many disciplines, social classes, cultures and geographic locations also enhances feedback, reduces groupthink and improves decision-making. Harvard public policy professor Harvey Brooks has noted that scientific disputes have always been value laden, and no practical way of disentangling social interests from technical issues exists. Brooks concluded that policy issues could only be resolved by bringing experts and generalists from the public together so that the values

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and preferences of the masses were heard. Brooks suggested that this strategy leverages two types of expertise. Specialists provide expertise from their fields, while generalists provide expertise regarding the preferences of society. ‘Only continual confrontation between generalists and experts,’ Brooks concluded, ‘can synthesize the values of society and the facts of nature into a policy decision that is both politically legitimate and consistent with the current state of technical knowledge’.8 In a just society, citizens have a right to knowledge and information, the right to participation, the right to guarantees of informed consent and the right to life or limitation from danger.9 These rights, however, need to be exercised because, to adequately address many of the hazards in modern society – dangerous chemicals and wastes, nuclear power, genetically engineered organisms – the public must be engaged in the policy-making process. One useful tool for fostering diversity, inclusion and justice is critical stakeholder analysis – a technique for identifying actors connected to a particular project or energy system. Critical stakeholder analysis can jump-start dialogue and facilitate discussions among previously disconnected actors, making it an important component of democratic decision-making. It can also reveal power asymmetries between stakeholders. The process of identifying stakeholder interests can promote common understanding of key agendas and help incentivise collaboration. By making the power relations of stakeholders more visible, critical stakeholder analysis can improve social responsibility and result in acceptable change.10 As such, we encourage active participation by all in energy discussions so that the energy technology preferences selected for integration into society better match interests and values in the best possible manner. Moreover, one is asked to remain cognisant of the fact that decisions made today will not only impact the lives of all who currently tread on this planet, but will also impact the livelihood of all those who come after us. We have an obligation to balance our interests with theirs. PRACTISE SELF-REFLECTION The fifth maxim encourages enhanced self-reflection: we all must become more aware of our hidden values and ideological frames, and the weaknesses of the assumptions underpinning them. By understanding why we embrace the energy perspectives we do, we can then begin to understand how we prioritise issues; and accordingly, how this differs from the manner in which others prioritise things.

8

H. Brooks, ‘The resolution of technically intensive public policy disputes’, Science, Technology & Human Values 9(1) (1984), 39–50. 9 P. J. Frankenfeld, ‘Technological citizenship: a normative framework for risk studies’, Science, Technology & Human Values 17(4) (1992), 459–84. 10 P. De Leon and D. M. Varda, ‘Toward a theory of collaborative policy networks: identifying structural tendencies’, Policy Studies Journal 37(1) (2009), 59–74; J. S. Dryzek and A. Tucker, ‘Deliberative innovation to different effect: consensus conferences in Denmark, France and the United States’, Public Administration Review 68(5) (2008), 864–76.

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Part of this process involves realising that even monkeys fall from trees. As proof, psychologist Philip Tetlock studied 284 ‘experts’ who made their living commenting or offering advice on political, social and economic trends.11 At the end of the study, after these experts had made 82,361 forecasts, Tetlock found that the specialists were not significantly more reliable than non-specialists in predicting events. Why are even smart people so prone to making these mistakes? Experts fall in love with their hunches, and they really hate to be wrong. Most people, including experts, tend to dismiss new information that does not fit with what they already believe. Experts use a double standard: they are tough in assessing the validity of information that undercuts their worldview, but lax in scrutinising information that supports their worldview. The problems which stem from blinkered or biased perspectives on an issue can be reduced considerably by nurturing a habit of scepticism concerning one’s own knowledge. Sociologist Steve Woolgar refers to this as benign introspection.12 Sociologist Michael Lynch adds that enhancing self-awareness can include training oneself to recognise the philosophical roots and historical context of one’s views – what we called frames earlier in this chapter. By becoming more self-aware, we become more conscious of personal biases, and learn to critically reflect on the well-springs of our own personal values.13 EMBRACE TECHNOLOGICAL AGNOSTICISM The final postulate is to encourage technological agnosticism by focusing on energy services rather than energy systems. We tend to forget that energy provision is a means to an end and not an end in itself. Energy is useful only insofar as it performs tasks that serve human needs. We do not consume electricity or oil for the fun of it, but rather we consume it to provide thermal comfort, cooked food, hot water, television shows, recorded music and a host of other services. We don’t absolutely need to drill, mine, leech, extract and deplete natural resources at breakneck fashion to achieve this, but we do need a way to provide humanity with the service of energising our lifestyles. Such a statement, while obvious to many analysts who take the time to think about energy technology and use, has somewhat profound implications.14 Practising technological agnosticism reorients the direction of energy policy interventions. Proper policy no longer centres on securing barrels of oil or tons of coal as an end in itself, but on optimising human mobility and comfort. An

11

P. Tetlock, Expert Political Judgment: How Good is It? Can We Know? (Princeton University Press, 2005). 12 S. Woolgar, ‘Reflexivity is the ethnographer of the text’, in S. Woolgar (ed.), Knowledge and Reflexivity: New Frontiers in the Sociology of Scientific Knowledge (Sage, 1988), pp. 1–13. 13 M. Lynch, ‘Against reflexivity as an academic virtue and source of privileged knowledge’, Theory, Culture & Society 17(3) (2000), 363–75. 14 B. K. Sovacool, ‘Security of energy services and uses within urban households’, Current Opinion in Environmental Sustainability 3(4) (2011), 218–24; see also B. K. Sovacool, ‘Conceptualizing urban household energy use: climbing the “energy services ladder”’, Energy Policy 39(3) (2011), 1659–68.

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energy policy dedicated only towards securing oil or coal is akin to a major corporation that still uses telex machines to communicate with customers and suppliers. It is a policy that fails to recognise that the objective should be to optimise the end goal (communication), not entrenched investment. By reframing energy policy as a piece of a puzzle to optimise mobility or comfort, far more sustainable options emerge. This might include the construction of walking, cycle and running paths to enhance mobility and altering standards, innovation paths and education to enhance comfort. Technological agnosticism is centred on the notion that many technologies can provide the same energy service – indeed, at the current scale of energy demand, there is no single technology that can satisfy all energy needs without giving rise to other problems; instead, a portfolio of options is the only viable approach. As Oxford climate change policy researchers Prins and Raynor suggest, agnosticism implies that rather than a silver bullet, the solution lies in silver buckshot.15 SUMMARY In sum, rather than treating energy data and knowledge as static, we should view it as perpetually evolving as resources are exhausted, prices change, values alter and technologies mature. Whether we endeavour to create an energy future on the basis of distorted, unrealistic representations or inclusive, critical, reflexive and prudent strategies is ours alone to decide.

15

G. Prins and S. Rayner, ‘The wrong trousers: radically rethinking climate policy’. A Joint Discussion Paper of the James Martin Institute for Science and Civilisation, University of Oxford and the MacKinder Centre for the Study of Long-Wave Events, London School of Economics, 2007.

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ENDING SUBSIDIES FOR FOSSIL FUEL EXPLORATION IN A WORLD OF UNBURNABLE CARBON Shelagh Whitley1

If countries intend to meet their commitments to limit average global warming to 2ºC target, at least two-thirds of existing proven reserves of oil, gas and coal need to be left in the ground.2 By way of example, in the absence of carbon capture and storage, 92 per cent of the United States’ coal reserves, 38 per cent of the Middle East’s oil reserves and 56 per cent of the former Soviet Union’s gas reserves are unburnable before 2050.3 Yet governments continue to invest scarce public resources in the expansion of fossil-fuel reserves, even though cuts in such subsidies are critical for ambitious action on climate change and low-carbon development. Current market conditions reinforce the case for an international phaseout of exploration subsidies. The glut in fossil fuel supplies, a sluggish global economy and moves toward energy efficiency have driven oil prices to a multiyear low. Growth in demand for coal is slowing, and prices have fallen to their lowest level since 2009.4 Almost two-thirds of greenfield (new) coal mines 1

2

3

4

Shelagh Whitley’s research is focused on private climate finance and the role of subsidies in shaping private investment. Prior to joining ODI she worked in the carbon markets, on clean energy finance and climate policy development within the public and private sectors. Intergovernmental Panel on Climate Change, Climate Change 2013: The Physical Science Basis, Summary for Policymakers (IPCC, 2013), p. 25, available at www.ipcc.ch/report/ar5/wg1/ docs/WGIAR5_SPM_brochure_en.pdf; IEA, World Energy Outlook 2012, Executive Summary (International Energy Agency, 2012), available at www.iea.org/publications/freepublications/ publication/English.pdf C. McGlade and P. Ekins, ‘The geographical distribution of fossil fuels unused when limiting global warming to 2ºC’, Nature 517 (2015), 187–90. International Energy Agency, Medium Term Coal Market Report (IEA, 2014), available at www. iea.org/newsroomandevents/pressreleases/2014/december/global-coal-demand-to-reach-9-billion-tonnes-per-year-by-2019.html

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are simply not economic at today’s prices.5 Without government support for exploration and wider fossil fuel subsidies, large swathes of today’s fossil fuel development would be unprofitable. Directing public finance and consumer spending towards a sector that is uneconomic, as well as unsustainable, represents a double folly. Six years ago, leaders of the G20 countries pledged to phase out ‘inefficient’ fossil fuel subsidies.6 Few subsidies are less efficient than those directed to exploration – yet evidence presented from our recent research points to a large gap between G20 commitment and action. Our recent study completed in partnership with Oil Change International estimates that, collectively, G20 governments spend $88 billion on annual exploration subsidies.7 To put this figure in context, this is almost double the amount of financing the International Energy Agency (IEA) estimates is needed to achieve universal access to energy by 2030.8 It is also more than double the global spending on exploration by the top twenty private oil and gas companies ($37 billion in 2013)9 – which suggests that their exploration is highly dependent on public finance. This research defined exploration subsidies from the G20 countries as including: ‘investment by state-owned enterprises’, which represents government support of around $49 billion annually; ‘national subsidies’ delivered through direct spending and tax breaks that account for another $23 billion per year, and ‘public finance’ from banks and financial institutions that amounts to another $16 billion per year. While the pattern of support may vary, all G20 countries provide exploration subsidies. The following are among the key findings from our review of national subsidies alone:10 • The US provided some $5.1 billion in national subsidies to fossil fuel exploration in 2013 – almost double the level in 2009. Congress has failed to pass subsidy cuts proposed by the President in a series of budgets. • Australia is providing $3.5 billion for the development of offshore and inland fossil fuel resources.

5

Carbon Tracker Initiative, Carbon Supply Cost Curves: Evaluating Financial Risk to Coal Capital Expenditures (CTI, 2014), available at www.carbontracker.org/wp-content/uploads/2014/09/ CTI-Coal-report-Sept-2014-WEB1.pdf 6 G20, ‘Leaders’ statement: the Pittsburgh Summit’ (2009), available at www.g20.org/sites/default/ files/g20_resources/library/Pittsburgh_Declaration_0.pdf 7 E. Bast, S. Makhijani, S. Pickard and S. Whitley, The Fossil Fuel Bailout: G20 Subsidies to Oil, Gas and Coal Exploration (Overseas Development Institute, 2014), available at www.odi.org/ sites/odi.org.uk/files/odi-assets/publications-opinion-files/9235.pdf 8 International Energy Agency, Energy Access Projections to 2030 (IEA, 2014), available at www. worldenergyoutlook.org/resources/energydevelopment/energyaccessprojectionsto2030 9 Rystad Energy, Rystad Energy UCube Upstream Database (Rystad Energy, 2014), available at www.rystadenergy.com/Databases/UCube 10 Bast et al., Fossil Fuel Bailout.

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• Russia provides $2.4 billion in national subsidies for fossil fuel exploration. • The UK has introduced national subsidies for fossil fuel exploration valued up to $1.2 billion a year, including for promoting offshore and unconventional gas/oil exploration. Between 2009 and 2014 these were worth $838 million to Total (headquartered in France), $407 million to Statoil (Norway), $229 million to Centrica (UK) and $72 million to Chevron (US). Investment by state-owned enterprises (SOEs) represents a major source of government support for exploration by several G20 countries. Levels of support range from $2 billion to $5 billion in Russia, Mexico and India, to $9 billion in China, $11 billion in Brazil and $17 billion in Saudi Arabia. Both national subsidies and investment by SOEs have pushed back the frontier for fossil fuel exploration. Russia’s Gazprom, for example, has started production from its first Arctic offshore site through the Prirazlomnoe project. Even with extensive tax breaks and public investment in infrastructure, the project is of dubious commercial viability: two-thirds of the reported internal rate of return of 14 per cent can be traced to tax breaks.11 Domestic and international public finance also plays a significant role in supporting fossil fuel exploration. Support from financial institutions owned by the governments of Canada, China, Japan, the Republic of Korea and Russia figures prominently in financing for exploration around the world, including in developing countries. In addition, the G20 countries provide public finance for exploration through their stake in multilateral development banks (MDBs). Our research found that the MDBs provided an average of $521 million every year for fossil fuel exploration between 2010 and 2013. Almost two-thirds of this total originated from the World Bank Group, calling into question the alignment of loan practices with the Bank’s stated policy goal of driving low-carbon development. The bulk of the World Bank’s exploration portfolio in fossil fuels can be traced to the International Finance Corporation. Support for fossil fuel exploration is one part of a broader picture of subsidisation. Globally, subsidies for the production and use of fossil fuels were estimated at $775 billion in 2012.12 This is without taking into account the wider costs associated with air pollution and greenhouse-gas (GHG) emissions. By contrast, subsidies for renewable energy amounted to

11

L. P. Lunden and D. Fjaertoft, Government Support to Upstream Oil & Gas in Russia: How Subsidies Influence the Yamal LNG and Prirazlomnoe Projects (Sigra Group, 2014), available at www.iisd.org/gsi/sites/default/files/ffs_awc_russia_yamalprirazlomnoe_en.pdf 12 Oil Change International, No Time to Waste: The Urgent Need for Transparency in Fossil Fuel Subsidies (OCI, 2012), available at http://priceofoil.org/content/uploads/2012/05/1TFSFIN.pdf

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just $101 billion in 2013.13 Linking this to global energy investment figures shows that for every US dollar in renewable subsidies US$2.50 are invested in renewable energy, while a US dollar in fossil fuel subsidies only draws US$1.30 of investment. Above all, governments should price carbon to reflect the social, economic and environmental damage associated with climate change, and to reduce emissions to levels compatible with the globally agreed 2ºC target. Governments in the G20 and beyond should act immediately to phase out fossil fuel subsidies to exploration. In the context of unburnable carbon, the following specific recommendations emerge from our research.14 1. An immediate end to government support for fossil fuel exploration, including: • amending government budgets and tax codes to ensure that budget and tax expenditures do not support fossil fuel exploration • identifying and ending direct government expenditures to stateowned enterprises for fossil fuel exploration • ending bilateral finance to fossil fuel exploration • encouraging multilateral institutions to end finance for fossil fuel exploration. 2. The adoption of a strict timeline for the phase-out of remaining fossil fuel subsidies for production and consumption, with country-specific measurable outcomes. 3. Introducing greater transparency in budget reporting so that citizens and legislative bodies are aware of real spending on fossil fuel subsidies, including: • increasing transparency through a publicly disclosed, consistent reporting scheme for all national subsidies for fossil fuels • improving the transparency of reporting on investment in and finance for fossil fuels by state-owned enterprises and majority publicly owned financial institutions • working within international institutions and processes, such as the Organization for Economic Cooperation and Development, and the United Nations Framework Convention on Climate Change, to ensure that any existing incentives for fossil fuel production are eliminated and that no new incentives are established • establishing or identifying an international body to facilitate and support the reform of fossil fuel subsidies. 4. Transfer subsidies from exploration and other fossil fuel subsidies to support for the transition to low-carbon development and universal energy access. 13

International Energy Agency, World Energy Investment Outlook, Factsheet (IEA, 2014), available at www.iea.org/media/140603_WEOinvestment_Factsheets.pdf 14 Bast et al., Fossil Fuel Bailout.

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Despite broad agreement that fossil fuel subsidies are a problem, they have proven politically difficult to eliminate. Governments must be held accountable for the exploration subsidies highlighted in this report and the clear opportunities for reform. The G20 must lead by taking swift and decisive action to end public support for fossil fuel exploration. Phasing out such subsidies is a critical and necessary step to limit the impacts of climate change. Removing public support for fossil fuels would rebalance our energy systems, forcing the industry to operate on a more level playing field. Ending these subsidies would also free up scarce government resources for development needs and social goods.

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WERE NORTH SEA OIL AND GAS ‘FIELD ALLOWANCES’ SUBSIDIES – AND DOES IT MATTER? David Powell1

INTRODUCTION The UK government is determined to extract ‘every drop’ of oil and gas from the North Sea. To support this it has expanded ‘field allowances’ – tax reductions for some types of field. The government’s position is that these allowances are not subsidies; were they, it would contravene the commitment of the UK and G8 to end all subsidies for fossil fuels. The picture is muddied as there is no one accepted definition of a ‘subsidy’; although many definitions suggest field allowances are indeed subsidies – and a UK parliamentary committee agreed – the government steadfastly disagrees. This can quickly become a circular semantic debate and one that can obscure the bigger picture. The real issue is that field allowances are part of delivery on the overall policy objective of the government – ‘maximising economic recovery’ of oil and gas. This is not consistent with avoiding dangerous climate change. If all countries drilled ‘every drop’ of fossil fuel, the world would certainly head for many degrees of global warming. The maths are undisputed even by oil majors: keeping temperature rises to only 2ºC – the stated goal of the UK,

1

David Powell leads Friends of the Earth’s work on economics and finance as it affects environmental policy. He has an MSc in Environmental Policy, an MA in English Literature and a graduate diploma in Economics. He has secured media coverage for his work quantifying and exposing the value of the Government’s ‘field allowances’ for North Sea oil and gas, and has presented on the topic to the UK Parliament. He has provided expert advice to the work of NGOs across the environment and development sector on oil and gas subsidies.

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EU and G8 – requires leaving two-thirds of known fossil fuels in the ground. So, regardless of whether a particular measure is or isn’t a subsidy, any support for the further exploitation of fossil fuels should be ended as a matter of urgency. NORTH SEA OIL AND GAS: THE TAX REGIME AND ‘FIELD ALLOWANCES’ 2 UK government policy is to ‘maximise economic recovery’ of oil and gas from the UK Continental Shelf (UKCS). Oil and gas production from the UKCS is in sharp decline; production of both peaked in 1999 and had fallen by 2013 to a level less than half of that peak.3 Yet while 42 billion barrels of oil equivalent (bboe) are estimated to have been extracted to date, the government estimates that there may be up to 21 bboe remaining.4 The headline tax rate for UKCS production on fields approved after 1993 is, as of April 2015, 50 per cent.5 This tax rate is made up of two separate legislated components: • a special ‘ring-fenced’ rate of corporation tax (30 per cent) – higher than the standard rate of 21 per cent paid by most other companies • an additional ‘supplementary charge’ (20 per cent). The Chancellor reduced the supplementary charge from 32 per cent to 30 per cent in his Autumn Statement of December 2014, and again to 20 per cent in his March 2015 Annual Budget. In his Budget speech of March 2014, the UK Chancellor George Osborne stated his intention to ‘review the whole [North Sea oil and gas] tax regime to make sure it is fit for the purpose of extracting every drop of oil and gas we can’. And in January 2015 the UK Treasury announced plans to end the system of field allowances and introduce a new general ‘investment allowance’. The allowance was proposed to cover all fields regardless of characteristic or size. A proportion of the 30 per cent supplementary charge would be waived on profits from extraction resulting from new capital investment within any new or existing North Sea project, with that proportion determined by the level of 2

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This chapter was written in May 2015, very soon after the formation of the new Conservative government. All policy statements in this paper are those inherited from the previous Conservative-led coalition government, and are thought to be still be applicable to the new administration as of the time of writing. Department of Energy and Climate Change (hereafter DECC), ‘UKCS oil and gas production projections’ (2014), available at www.gov.uk/government/uploads/system/uploads/attachment_data/ file/287001/production_projections.pdf Scottish Government, ‘Scotland’s independent expert commission on oil and gas: maximising the total value added’ (2014), available at www.scotland.gov.uk/Publications/2014/07/6560/5 A third tax, the Petroleum Revenue Tax (PRT), also applies but is levied only at oil fields approved before 1993. For relevant fields, it takes the marginal rate of tax to 81 per cent. It is largely excluded from this analysis because the ‘field allowances’ this chapter discusses affect only the supplementary charge and so the principles of whether this represents a subsidy are the same for both PRT and non-PRT paying fields.

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capital expenditure (this is the model of both the existing Brown Field Allowance and the new onshore regime for unconventional gas). The government argued that for some ‘small or technically challenging’ new fields, the headline tax rate of 62 per cent was too high to ‘maximise economic recovery’. It therefore gradually introduced a suite of bespoke ‘field allowances’.6 Field allowances waive the supplementary charge for profits from qualifying fields, up to a designated amount of profit – so, for a time, reducing the headline rate of tax to only 30 per cent. For example: • Small Field Allowances exempt £150 million in profit from the 20 per cent supplementary charge – therefore saving producers up to £30 million. • Ultra Heavy Oil Allowances exempt £800 million in profit, saving up to £160 million. • Brown Field Allowances work differently – exempting an amount of profit relative to the capital expenditure undergone to produce the additional oil or gas. My own research, corroborated by the Department for Energy and Climate Change (DECC), suggests that the total undiscounted value of these tax reductions to the industry, assuming they were all taken up in full, was £1.06 billion in 2013–147 and £1.952 billion in 2012–13.8 ARE FIELD ALLOWANCES SUBSIDIES? There is no internationally accepted definition of a subsidy – a fact the government has relied upon to defend, for example, its subsidising of nuclear power (despite promises not to do so) on the basis that it is not a subsidy because all low-carbon energy also receives subsidy.9 Under a number of authoritative definitions, field allowances could be argued to be subsidies: • The International Monetary Fund (IMF) defines an energy subsidy as anything that affects what the price for energy would otherwise have been in a ‘perfectly competitive’ market.10 As in practice all markets require rules to operate, it is reasonable to assume that a legislated

6

DECC, ‘Oil and gas mining: supplementary charge’, available at www.gov.uk/oil-gas-and-mining-supplementary-charge#field-allowance 7 Friends of the Earth, ‘UK tax breaks to oil and gas companies in 2013/14’ (2014), available at www.foe.co.uk/sites/default/files/downloads/14-worth-2.7-billion-46637.pdf 8 Friends of the Earth, ‘UK fossil fuel tax breaks, 2012/13’ (2013), available at www.foe.co.uk/ sites/default/files/downloads/uk_fossil_fuel_tax_breaks.pdf 9 See Q247 of UK Parliament, Environmental Audit Committee – Minutes of Evidence, Energy Subsidies in the UK (2013), available at www.publications.parliament.uk/pa/cm201314/cmselect/cmenvaud/c61-iv/c6101.htm 10 International Monetary Fund (hereafter IMF), ‘Energy subsidy reform: lessons and implications’ (2013), available at www.imf.org/external/np/pp/eng/2013/012813.pdf

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headline rate of tax paid by all players is in practice a central component of such a market. • The Organization for Economic Cooperation and Development (OECD) defines it as government ‘support’ for energy production – a ‘deliberately’ broader definition than some interpretations of a subsidy – including ‘selectively reducing, rebating or removing the taxes that [energy producers] would otherwise have to pay’.11 • The International Energy Agency et al. provides a third definition: ‘An energy subsidy is defined as any government action that lowers the cost of energy production, raises the revenues of energy producers or lowers the price paid by energy consumers.’12 The UK’s government’s position is that fossil fuel subsidies are ‘economically and environmentally perverse’.13 It states that the UK ‘does not have any fossil fuel subsidies’14 and that field allowances are not subsidies. This latter point was outlined by then Energy Minister Michael Fallon, giving evidence to the Environmental Audit Committee (EAC) inquiry into energy subsidies in 2013: ‘If they are paying a tax higher than other businesses are paying it cannot be a subsidy. It cannot be both a subsidy and a tax, can it?’15 In other words, the government’s position is that because corporation tax on oil and gas from the North Sea is set at a higher rate (30 per cent) than other sectors even after the waiving of the supplementary charge, it does not count as a subsidy. But this implies that the relevant factor is the taxation of oil and gas relative to other sectors in the economy, such as manufacturing. Yet the rate of tax for oil and gas is higher in recognition of its typically very high profitability from the exploitation of what is a shared national resource, and the legitimate desire of the Exchequer to capture a fair rate of return. A more useful comparison is of the tax rate of projects with field allowances with those of the sector as a whole. The headline rate of tax has been set in law (the supplementary charge is legislated for in the Corporation Tax Act 2010, and amended when necessary by subsequent legislation, such as the Finance 11

Organization for Economic Cooperation and Development (hereafter OECD), ‘An OECD-wide inventory of support to fossil-fuel production or use’ (2012), available at www.oecd.org/site/ tadffss/PolicyBrief2013.pdf 12 IEA, OECD, World Bank, ‘The scope of fossil fuel subsidies in 2009 and a roadmap for phasing out fossil-fuel subsidies’ (2010), available at www.worldenergyoutlook.org/media/weowebsite/ energysubsidies/second_joint_report.pdf 13 Prime Minister’s Office, ‘UN Climate Summit 2014: David Cameron’s remarks’ (September 2014), available at www.gov.uk/government/speeches/un-climate-summit-2014-david-camerons-remarks 14 UK Parliament, ‘Fracking: written question – 212776’ (November 2014), available at www.parliament.uk/business/publications/written-questions-answers-statements/written-question/Commons/2014-10-30/212776 15 See Q285 of UK Parliament, Environmental Audit Committee, ‘Minutes of evidence, energy subsidies in the UK’ (2013), available at www.publications.parliament.uk/pa/cm201314/cmselect/ cmenvaud/c61-iv/c6101.htm

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Act 2015). Projects benefiting from field allowances pay less tax than those without field allowances. The EAC’s final report into energy subsidies concluded that while they accepted that the allowances ‘did not fully offset relatively high starting rates of corporation tax . . . the allowances nevertheless represent a subsidy because the higher tax rates compensate for the use of state-owned fossil fuel deposits’.16 That was not the end of the matter; the government, in its official response, disagreed with the committee.17 As Dr William Blyth from Oxford Energy Associates has warned, the debate on subsidies can indeed be characterised by more heat than light.18 THE EFFECT OF POLICY AND THE FUTURE LANDSCAPE So much for the semantic debate. What is the actual purpose and effect of field allowances? They have certainly made a material economic difference to beneficiary companies, representing a de facto reduction in the legislated headline rate of tax. The government credits field allowances with helping to deliver resurgent levels of investment in the North Sea. In 2014, a record £14.4 billion was invested of which £7 billion is said by the Treasury to have been unlocked by field allowances.19 The allowances are designed to help get as much oil and gas from the North Sea as possible – about which the UK government is unapologetic, seeking to ‘maximise economic recovery’. This is the wrong priority, the implication of which is that it is consistent for all other countries to do likewise. This is simply incompatible with avoiding dangerous climate change. Keeping global temperature rises to no more than two degrees is the stated aim of the UK, EU and the United Nations. This has stark implications for fossil fuel extraction, as the International Energy Agency (IEA) states that ‘no more than one-third of proven reserves of fossil fuels can be consumed prior to 2050 if the world is to achieve the 2°C goal, unless carbon capture and storage (CCS) technology is widely deployed’.20 This is the ‘unburnable carbon’ analysis21 whose

16

See UK Parliament, Environmental Audit Committee, ‘Report: energy subsidies in the UK’ (November 2013), para 66, available at www.publications.parliament.uk/pa/cm201314/cmselect/cmenvaud/61/6106.htm#a10 17 See UK Parliament, Environmental Audit Committee, ‘Report: energy subsidies in the UK, Appendix – Government response’ (November 2013), para 66, available at www.publications. parliament.uk/pa/cm201314/cmselect/cmenvaud/1103/110304.htm 18 W. Blyth, Oxford Energy Associates, in UK Parliament, Environmental Audit Committee, ‘Energy subsidies in the UK: written evidence’ (November 2013), available at www.publications. parliament.uk/pa/cm201314/cmselect/cmenvaud/writev/61/energy.pdf 19 HM Treasury, ‘Fiscal reform of the UK Continental Shelf: consultation on an investment allowance’ (January 2015), available at www.gov.uk/government/uploads/system/uploads/attachment_data/file/397299/investment_allowance_consultation_final.pdf 20 IEA, ‘World Energy Outlook – Executive Summary’ (2012), available at www.iea.org/publications/freepublications/publication/English.pdf. It should be noted that Carbon Tracker (see next footnote) are clear that even a very fast roll-out of CCS – which the world is not on course to do – will in practice make only a marginal impact on the amount of carbon that is ‘unburnable’. 21 See the Carbon Tracker Initiative at www.carbontracker.org

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raw mathematics is accepted in full by companies such as Shell22 and BP, and even by President Barack Obama23 and the Governor of the Bank of England, Mark Carney.24 By far the biggest subsidy that oil and gas companies receive is not having to pay the environmental damage of climate change and local impacts like oil spills that their activities lead to. Quite what this hidden subsidy amounts to may be impossible to accurately quantify; the true damages of climate change on peoples, species, economies and cultures are probably too complex to calculate with any great accuracy. However they will be high: one authoritative estimate puts a figure for the ‘social cost of carbon’ at $100/tonne.25 Whether agreed as a ‘subsidy’ or not, all forms of active stimulus for oil and gas production and consumption must be ended as an urgent priority. It is important not to let a semantic debate over what is and what is not a subsidy cloud attention to the real problem: in the face of the unimpeachable maths of climate change and unburnable carbon, continuing government support – economically, institutionally and fiscally – for the untrammelled extraction of ‘every drop’ of oil and gas.

22

D. Hone, Climate Change Advisor for Shell, ‘The carbon bubble reality check’ (May 2013), available at http://blogs.shell.com/climatechange/2013/05/bubble 23 Bloomberg, ‘Giving up fossil fuels to save the climate: the $28 trillion writedown’ (June 2014), available at www.bloomberg.com/news/articles/2014-06-26/giving-up-fossil-fuels-to-save-theclimate-the-28-trillion-writedown 24 Emerging Markets, ‘Carney raises the heat on climate: you can’t burn all the oil’ (October 2014), available at www.emergingmarkets.org/Article/3389530/Economics-and-Policy/Carneyhammers-the-point-you-cant-burn-all-the-oil.html 25 C. Hope, ‘How do the new estimates of transient climate response affect the social cost of CO2?’ (May 2013), available at www.chrishopepolicy.com/2013/05/how-do-the-new-estimates-of-transient-climate-response-affect-the-social-cost-of-co2

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RENEWABLE ENERGY DISPUTES Peter D. Cameron1

No category of investor-state disputes has demonstrated both rapid growth and a capacity to surprise as much as that concerning renewable energy (RE). Since 2009 the number of disputes between investors and host governments over various kinds of RE, from wind to solar, has mushroomed.2 Given the strong social and political consensus behind RE as a building block in a low-carbon future, the speed and scale of this recourse to formal dispute settlement mechanisms invites the question: what went wrong?3 Many countries have introduced legal and regulatory schemes for the promotion and incentivisation of RE, whether in the form of wind, geothermal, 1

2

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Peter Cameron is Director of the Centre for Energy, Petroleum and Mineral Law and Policy (CEPMLP), and Professor of International Energy Law and Policy, University of Dundee, UK. Peter was elected as Fellow of the Royal Society of Edinburgh in 2013. He is Co-director of the recently established International Centre for Energy Arbitration and Honorary Professorial Fellow at Edinburgh University’s Europa Institute. Apart from investor-state disputes about the withdrawal or curtailment of subsidies, there have been two other categories of dispute arising from RE policies: the first is the cases that came before the European Court of Justice in 2014 concerning the legality of national support schemes within the EU, which exclude exporters and importers of renewable energy-generated electricity from their scope; the second comprises cases concerned with the relationship between subsidies and trade obligations under the World Trade Organization. These are not considered in this chapter. For an overview of these and other RE disputes see K. Talus, ‘Introduction - renewable energy disputes in Europe and beyond: an overview of current cases’, Transnational Dispute Management 12(3) (2015), 1–17. Inevitably, there is a growing body of literature comprising commentary on these disputes. A handicap the authors face at present is the dearth of final awards and lack of published information on the cases that are ongoing. As a result, it tends to focus on international and national scene-setting; analysis of national incentives and legislation; listing known cases and examining provisions of the relevant treaty instruments such as fair and equitable treatment (FET), taxation or indirect expropriation. That said, some useful analysis can be found in the following: J. M. Tirado, ‘Renewable energy claims under the Energy Charter Treaty: an overview’, Transnational Dispute Management 12(3) (2015), 1–22.

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solar, biofuels or hydroelectricity. Investment in RE has often required statebacked incentives to ensure support for relatively new or higher-cost technologies and to ensure that these long-term initiatives take root in markets where conventional fuels are already established. In Europe most of these schemes date from the early 2000s, and received robust policy and legal support from European Union institutions. A common example of this kind of measure is the ‘feed-in tariff’, a mechanism (not a subsidy) which supported the promotion of RE by requiring utilities to pay producers of RE for their output and usually allowed them to pass on those costs to consumers.4 The popularity of RE as a policy option lay in part as a means of meeting climate change targets and obligations in national and international law. By providing these incentives, investment in RE grew very significantly. However, a change occurred in many countries in the years following the financial crisis of 2008–9. On the face of it, the impact of recession and austerity policies made governments, businesses and consumers less willing to accept the upfront costs associated with the RE sector. In practice, this was not what happened in Europe. After the Renewable Energy Directive of 2009, the accompanying mandatory national targets accelerated financial support and investment until 2012–13. The unexpected very large take-up of the more generous Support Schemes and corresponding escalation in cost during the period 2008–13, especially in Germany, Italy, Spain, the Czech Republic and the UK, drove governments to withdraw or curtail them, sometimes retrospectively, with bankruptcies resulting in certain cases. Since a proportion of the investment in RE came from internationally operating companies (including entities owned ultimately by investors in Abu Dhabi, Mexico and the USA) who were attracted by the offer of guaranteed returns over a long period, some of the aggrieved investors were able to draw upon the legal protections available under bilateral and multilateral treaty instruments, and so launch claims against the governments responsible for these measures. Three notable features of these investor-state disputes have resulted. First, many investors and their advisors have a preference for the Energy Charter Treaty (ECT) as the legal basis for their claims against governments.5 There is an irony here. The raison d’être of the ECT was to promote investment by capital-exporting countries like EU member states in the newly marketoriented countries of Central and East Europe. Investors were allowed to file

4

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There are different kinds of ‘feed-in tariff’ in various EU member states: common features include the provision of a price above the market price to be paid for electricity generated from RE sources (‘fed into the grid’); the tariff is usually guaranteed for a period between fifteen and twenty-five years and differentiation is permitted according to, for example, the size of the facility, its geographical location or the type of RE; and over time the price may be allowed to vary to take into account technological advances that impact on it. The programmes have also included local content requirements. For a list of known cases that are based on the ECT, see the official website of the Energy Charter Secretariat at www.energycharter.org/what-we-do/dispute-settlement/all-investment-disputesettlement-cases

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claims against ECT member states directly for any violations of the protections under the ECT. An arbitration mechanism was deemed to be essential to the achievement of that broad aim given the unproven character of the national courts in these newly democratic countries, and the need for a simplified enforcement regime. Without recourse to arbitration by an external body, it was thought that investors were unlikely to commit capital to large new energyrelated projects. Article 26 of the ECT gives the investor an option to choose between arbitration before the International Centre for the Settlement of Investment Disputes, the Arbitration Institute of Stockholm Chamber of Commerce or ad hoc arbitration under the United Nations Commission on International Trade Law. It is ironic, then, that so far the RE-related claims have almost entirely been made against states such as Spain or Italy (together with more than two dozen cases known under the ECT) that have long been members of the EU. Alternatively, they have been made against states like the Czech Republic (seven claims under the ECT by mid-2015) which were fast-tracked to EU membership from a post-communist setting due in part to the perceived strength of their institutions and the market orientation of their economy. As a result, the ECT has now overtaken the North American Free Trade Agreement (NAFTA) Chapter 11 as the multilateral treaty most used by investors to make claims against states: a result that is entirely triggered by RE cases. Second, the role of several European states as respondents in disputes, even though they were long known to be champions of investor-state dispute settlement, has triggered a review by these states of the commitments they have typically made through these legal instruments.6 A contributory factor, unrelated to RE, was the German government’s role as respondent in international arbitration with the Swedish company Vattenfall, in connection with its decision to phase out nuclear power in the country. The timing for such a review has also been influenced by the complex and often controversial negotiation of multilateral trade and investment partnerships such as the Transatlantic Trade and Investment Partnership (TTIP)7 and the TransPacific Partnership (TPP).8 Controversy has focused on the confidentiality of the proceedings that are initiated by a claim (on the ground that this is non-transparent) and the authority of a tribunal to reach a binding decision (on the ground that public policy is involved and they lack the authority to pronounce on this).9

6

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8 9

There have been disputes between investors and states in other countries such as Canada, but there is no surge of cases in any region comparable to that in Europe. For an overview of some of the issues involved in this negotiation, see http://ec.europa.eu/trade/ policy/in-focus/ttip/documents-and-events/index_en.htm For an overview from the US perspective, see https://ustr.gov/tpp/Summary-of-US-objectives For example, an article in The Guardian by C. Provost and M. Kennard, ‘The obscure legal system that lets corporations sue countries’ (10 June 2015), available at www.theguardian.com/ business/2015/jun/10/obscure-legal-system-lets-corportations-sue-states-ttip-icsid

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A further comment on the players in the current RE disputes might well be that this phenomenon places another nail in the coffin of simple north-south classifications of the global economic order, in which state sovereignty was seen as vulnerable to the incursions of international corporations wielding instruments of West-generated international economic law. Here, it is the capitalexporting states that figure as respondents. A third notable feature of the growth in this category of disputes is that it has added fuel to an existing issue about jurisdiction: what is the relationship between the ECT and the Treaty of European Union (TEU) with respect to disputes between EU-based investors and EU member states who are also signatories of the ECT? This issue of the legal source of investor protection in ‘intra-EU’ disputes has been evident in other (non-RE) disputes,10 but has been given further momentum by the recourse of many investor claimants to the ECT in disputes that involve EU member states. Since cases on RE have already been heard by the European Court of Justice, it cannot be claimed that EU institutions have no competence or experience in handling disputes on RE subjects.11 THE CORE LEGAL ISSUES Inevitably, there are different fact patterns in the many cases now pending, and many unique features to the national measures taken and procedures adopted by states when rolling back their incentive schemes. It is also likely that this process of limiting incentive frameworks for RE has not come to an end. Other states will follow, possibly learning from the experiences of Spain and the Czech Republic in their choice of approach, and seeking to limit the number of disputes arising in the national courts and before international tribunals.12 Where a treaty-based claim has in fact arisen, some protections are more likely to be at the centre of investor claims than others. However, a major

10

The European Commission’s argument has been that investment tribunals lack jurisdiction over cases involving only EU member states since it is only the EU that has competence to rule on issues of EU law: for example, Electrabel v. Hungary (ICSID Case ARB/07/19); EDF v. Hungary (UNCITRAL); Ioan Micula et al. v. Romania (ICSID Case ARB/05/20); US Steel Global Holdings v. Slovakia (PCA UNCITRAL). In each of these cases, the Commission intervened as a non-disputing party. This pattern of interventions is set to continue in cases against the Czech Republic and Spain. 11 For example, the Alands Vindkraft case, in which the Court assessed a denial by the Swedish Energy Agency to award green certificates to a Finnish company, Alands Vindkraft: Case C-573/12, Alands Vindkraft (2014); the general conclusion – that national support schemes were not designed to cover green electricity produced in another member state – was supported in the Essent Belgium case (Case C-204-208/12, Essent Belgium NV (2014)); see also Green Network: Case C-66/13, Green Network SpA (2014). 12 The UK has approached the issue of retroactivity with care but litigation has resulted nonetheless: see a discussion of the UK approach by A. Johnston, ‘Recent renewables litigation in the UK: some interesting cases’, Transnational Dispute Management 12(3) (2015), available at www. transnational-dispute-management.com/article.asp?key=2228. Other EU states which have introduced measures to curtail existing schemes include Belgium, Bulgaria, France, Greece, Italy and Slovakia.

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obstacle at the present time is the lack of information about the cases themselves, given the confidentiality that surrounds them. The kind of arguments made by claimants in RE cases can be expected to include the claim that a violation of fair and equitable treatment (FET; Art 10 ECT), and particularly the investors’ legitimate expectation of regulatory certainty and fairness, of the kind identified by the tribunal in Total v. Argentina.13 This defence may be a more secure basis than one founded on the stability of the underlying legal and business framework.14 It could be argued that this is merely different language used by different tribunals for the same standard of protection. Some dynamic and potential instability would seem to be inevitable in any regulatory scheme for RE, taking into account the impact of evolving technology, for instance. The challenge for the tribunal would seem to be to ensure that any adjustments are made in a fair way, which includes providing the investor with sufficient stability to preserve the business calculations made prior to their making the investment. However, the regulatory schemes established were, at least in some European countries, flawed at the outset, either by providing too much support for a particular RE source or in underestimating the scale of investment that the incentives on offer would attract, leading to over-capacity. The manner in which the overall regulatory scheme is then adapted given the undertakings made to investors becomes important. In the context of the ECT standard on FET, Art 10(1) requires the host state to provide constant protection as it promotes investment, and transparent as well as stable conditions for investors. Clearly, any idea of transparency or consistency fits uncomfortably with retroactive measures, or with attempts to involve the EU on questions of state aid.15 Arguments also likely to be made include ones based on indirect expropriation with the effect of reducing the value of long-term investments (Art 13 ECT). Different interpretations of doctrine on these matters can be expected, especially ones that relate to regulatory measures by host states. However, because the proceedings are confidential, information about the arguments made and the fact pattern in particular cases is dependent upon secondary sources and is sporadic in character.

13

Total SA v. Argentine Republic, Decision on Liability, para 122: the tribunal has to ask itself whether a host state has taken the necessary actions to ensure that the ‘concessionnaire is able to recover its operations costs, amortise its investments and make a reasonable return over time’. 14 For a discussion of this, see U. E. Özgür, ‘In search of consistency and fairness in investor-state arbitration: an “institutional” approach to interpreting the doctrine of legitimate expectations’, Transnational Dispute Management 1 (2014), available at www.transnational-dispute-management.com/article.asp?key=2049 15 Consider the remarks by R. Dolzer and C. Schreuer, Principles of International Investment Law, 2nd edn (Oxford University Press, 2012), p. 149: ‘Transparency is closely related to protection of the investor’s legitimate expectations. Transparency means that the legal framework for the investor’s operations is readily apparent and that any decisions affecting the investor can be traced to that legal framework’.

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While there are issues about retroactive application of measures in the cases involving Spain, in those involving the Czech Republic they are likely to focus on the application of a tax filter under the ECT: does the imposition of a tax on existing power plants give rise to an expropriation?16 Tax filtering is a creature of US practice even though the US was not even a signatory to the ECT. However, its inclusion in the ECT followed proposals from Canadian and US observers in the treaty negotiations.17 Again, outside the European context the cases in Canada involving RE under NAFTA Chapter 11 turn on taxation measures that are slightly different.18 There are also likely to be procedural issues worthy of comment. In some cases, there appears to have been consolidation of claims to assist parties with limited resources in meeting the costs associated with the arbitration process. CONCLUSIONS Any analysis of investor-state disputes arising from renewable energy investments has to be tentative at the present time. Even when awards are handed out, there are likely to be few that are accessible due to confidentiality restrictions. Nonetheless, in a very short time this disparate collection of cases has triggered some wider reflections on investor-state dispute settlement, adding fuel to existing controversies and challenging some conventional wisdom. They have propelled the ECT into the frontline of treaties that investors might favour to protect their interests, ensuring that analysis of its provisions will keep academic lawyers, arbitrators and counsel busy for some time to come. These cases have also underscored the vulnerability of investors in this sector to the kind of policy realignments that have long been a source of concern to investors in the hydrocarbons and mining industries. Given the key role that private capital is likely to play in the future development of a low-carbon agenda, interest in the outcomes of the ongoing RE cases – particularly with respect to the scope of the regulatory powers of states that are ECT members – is likely to extend well beyond the parties directly involved in the disputes themselves.

16

The ECT imposes limits on the claims that can be raised in relation to taxation measures under Article 21 ECT: see Energy Charter Secretariat, ‘Taxation of foreign investments under international law: Article 21 of the Energy Charter Treaty in context’ (2015), 52–61, available at www.energycharter.org/fileadmin/DocumentsMedia/Thematic/Taxation_of_Foreign_ Investments_2015_en.pdf 17 Ibid., 40–4. 18 US investors have initiated two cases against Canada on the basis that the Feed-In Tariff programme in Ontario has adversely affected their wind energy investments: Mesa Energy v. Canada (UNCITRAL), NAFTA, 4 October 2011; Windstream v. Canada (UNCITRAL), NAFTA, 5 November 2013.

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USING A LEGACY FRAME TO DELIVER ENERGY AND ENVIRONMENT POLICIES Kaitlin T. Raimi1 and Michael P. Vandenbergh2

Many scholars and policy-makers suggest that immediate, vivid indications of climate change threats are required to motivate public support for climate change mitigation,3 but a promising alternative has been largely overlooked in the academic literature: invocation of the effects of environmental degradation on individuals’ long-term reputations. Some politicians have begun to use this

1

2

3

Kaitlin T. Raimi is a Social Psychologist and Assistant Professor, Gerald R. Ford School of Public Policy, University of Michigan. Formerly, she was a Postdoctoral Fellow at the Vanderbilt Institute for Energy and Environment. Her areas of interest include belief superiority, selfpresentation, and the role of knowledge and ideology in the creation and maintenance of belief and behaviours related to climate change and the environment. Michael Vandenbergh is David Daniels Allen Distinguished Chair of Law, Director of the Climate Change Research Network and Co-director of the Energy, Environment and Land Use Programme at Vanderbilt University Law School. Professor Vandenbergh’s areas of interest include environmental law, private climate governance and the social influences on household energy behaviour. E. U. Weber, ‘Experience-based and description-based perceptions of long-term risk: why global warming does not scare us (yet)’, Climate Change 77 (2006), 103–20; Center for Research on Environmental Decisions, ‘The psychology of climate change communication: a guide for scientists, journalists, educators, political aides, and the interested public’ (2009), available at https://coast.noaa. gov/digitalcoast/_/pdf/CRED_Psychology_Climate_Change_Communication.pdf; D. J. Hardisty and E. U. Weber, ‘Discounting future green: money versus the environment’, Journal of Experimental Psychology: General 138 (2009), 329–40; A. Luers, C. Pope and D. Kroodsma, ‘Climate risks: linking narratives to action’, Stanford Social Innovation Review (2013), available at www.ssireview. org/blog/entry/climate_risks_linking_narratives_to_action; A. Revkin, ‘Could climate campaigners’ focus on current events be counterproductive?’, New York Times, Dot Earth Blog (20 August 2013), available at http://dotearth.blogs.nytimes.com/2013/08/20/could-climate-campaigners-focus-on-current-events-be-counterproductive

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approach. For example, President Obama has directly challenged Americans to think about how ‘our children, and our children’s children’ will judge us based on our climate-related actions.4 Similarly, British prime minister David Cameron has argued that ‘as political leaders, we have a duty to think long term . . . when presented with an opportunity to safeguard the long-term future of our planet and our people, we should seize it’.5 This plea for consideration of future generations is based on projections that estimate that the worst climate consequences will not occur for decades or centuries but will last for millennia.6 New approaches to the collection and delivery of legacy information may be necessary to transform these aspirational statements into a more sustained policy response. Acting purely for the good of future generations may require a level of altruism that many people are unwilling to adopt.7 People engage in temporal discounting, in which future benefits are valued less highly than current rewards, leading people to act in favour of short-term gain.8 Climate change is also an intergenerational dilemma: unlike social dilemmas between contemporaries, those in the current generation who act for the good of future generations can expect no reciprocity or cooperation in return. Thus, self-interest tends to push current generations to continue to emit as much carbon as it takes to fuel their economy or comfort. Given these barriers to intergenerational climate action, environmental advocates have increasingly focused on the near-term consequences of climate change in order to motivate mitigation.9 However, focusing on relatively small and scientifically uncertain near-term effects may give the public the false impression that climate change is a minor problem or that scientific projections are imprecise.

4

5

6

7

8

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White House, ‘Remarks by the President on climate change’ (25 June 2013), available at www. whitehouse.gov/the-press-office/2013/06/25/remarks-president-climate-change R. Prince, ‘Cameron calls for “ambitious deal” to tackle climate change’, The Telegraph (23 September 2014), available at www.telegraph.co.uk/news/worldnews/northamerica/ usa/11117057/Cameron-calls-for-ambitious-deal-to-tackle-climate-change.html K. Hasselmann, M. Latif, G. Hooss, C. Azar, O. Edenhofer, C. C. Jaeger, O. M. Johannessen, C. Kemfert, M. Welp and A. Wokaun, ‘The challenge of long-term climate change’, Science 302(5652) (2003), 1923–6; J. Hovi, D. F. Sprinz and A. Underdal, ‘Implementing long-term climate policy: time inconsistency, domestic politics, international anarchy’, Global Environmental Politics 9 (2009), 20–39; Intergovernmental Panel on Climate Change, ‘Summary for policymakers’, in T. F. Stocket, D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and P.M. Midgley (eds), Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (Cambridge University Press, 2013). A. J. Caplan, C. J. Ellis and E. C. D. Silva, ‘Winners and losers in a world with global warming: noncooperation, altruism, and social welfare’, Journal of Environmental Economics and Management 37 (1999), 256–71; E. U. Weber and P. C. Stern, ‘Public understanding of climate change in the united states’, American Psychologist 66 (2011), 315–28. S. Frederick, G. Loewenstein and T. O’Donoghue, ‘Time discounting and time preference: a critical review’, Journal of Economic Literature 40 (2002), 351–401; Hardisty and Weber, ‘Discounting future green’. For a review, see Luers et al., ‘Climate risks’.

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We propose an alternative approach, one that uses concerns about long-term reputation to motivate behaviour in the short term.10 For decades, social scientists have demonstrated the strength with which a desire to build and maintain a good reputation motivates behaviour.11 Our own recent research has demonstrated that reputational concerns extend into one’s posthumous legacy.12 Concern about posthumous reputations has been understudied, but hints of this concern can be found in related work on generativity: the desire to help future generations, including through pro-environmental behaviours.13 Other research has showed that making mortality salient can provoke people to act in pro-social and pro-environmental ways.14 Although these theories focus on motivations other than reputation, such as altruism or anxiety about death, it is plausible that at least some of the phenomena demonstrated in this research are motivated by a desire to make a good impression on future generations. Strengthening this claim, our own research has demonstrated that concern about legacy reputation motivates intentions to engage in climate change mitigation.15 For legacy concerns to provoke mitigation, people must believe that climate change presents a reputational opportunity or threat. Specifically, they must believe that future generations will know about their climate-related behaviours and judge them accordingly. This intergenerational information-sharing is unlikely to exist naturally, as limits on information preservation and accessibility make it implausible that future generations will be able to sort through the vast array of information and discover the climate-relevant behaviours of most individuals. Yet there are ways that a channel of information from current to future generations could be created that would motivate reputation-saving

10

M. P. Vandenbergh and K. T. Raimi, ‘Climate change: leveraging legacy’, Ecology Law Quarterly 42 (2015), 139–70. 11 E. Goffman, The Presentation of Self in Everyday Life (Doubleday, 1959); B. R. Schlenker, Impression Management: The Self-Concept, Social Identity, and Interpersonal Relations (Brooks/ Cole, 1980); M. R. Leary, Self-Presentation: Impression Management and Interpersonal Behavior (Westview Press, 1995). 12 Vandenbergh and Raimi, ‘Climate change’, n. 10; K. T. Raimi and M. P. Vandenbergh, ‘Posthumous reputations: legacy as a self-presentational motivation’ (paper under review). 13 D. P. McAdams and E. de St Aubin, ‘A theory of generativity and its assessment through selfreport, behavioral acts, and narrative themes in autobiography’, Journal of Personality and Social Psychology 62 (1992), 1003–15; M. Kyle Matsuba, M.W. Pratt, J. E. Norris, E. Mohle, S. Alisat and D. P. McAdams, ‘Environmentalism as a context for expressing identity and generativity: patterns among activists and uninvolved youth and midlife adults’, Journal of Personality 80 (2012), 1091–115; L. Zaval, E. M. Markowitz and E. U. Weber, ‘How will I be remembered? Conserving the environment for the sake of one’s legacy’, Psychological Science 26 (2015), 231–6. 14 K. A. Wade-Benzoni and L. Plunkett Tost, ‘The egoism and altruism of intergenerational behavior’, Personality and Social Psychology Review 13 (2009), 165–93; M. Fox, L. Plunkett Tost and K. A. Wade-Benzoni, ‘The legacy motive as a catalyst for sustainable and ethical decision making in organizations’, Business Ethics Quarterly 2 (2009), 153–85; K. A. Wade-Benzoni, L. P. Tost, M. Hernandez and R. P. Larrick, ‘It’s only a matter of time: death, legacies, and intergenerational decisions’, Psychological Science 23 (2012), 704–9. 15 Vandenbergh and Raimi, ‘Climate change’; Raimi and Vandenbergh,‘Posthumous reputations’.

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climate change mitigation. For example, recent advances in data storage and analytics, sharing of public records via online databases and the growth of genealogy websites suggest that it would be possible to create a legacy registry in which people could record their own climate-related action for their progeny to find or in which publicly available records of climate behaviours could be saved for the future.16 A climate legacy registry could be delivered via a publicly managed government body, such as the Library of Congress, but government efforts to develop such a registry are likely to be unfeasible in many countries. Private institutions may offer a more viable option, by delivering climate policy responses that bypass government gridlock promptly and cost-effectively.17 The legacy information could be collected and managed privately, through a not-for-profit organisation, such as an environmental advocacy group, or through a for-profit corporation modelled on genealogy registries such as Ancestry.com. Funding and participation also could operate under a crowdsourcing model as part of a non-profit website, such as Wikipedia.org. Alternatively, simply reminding people that very few behaviours are totally private in an age of Big Data may be enough to spur action.18 Such messages could be delivered through traditional public service announcements or environmental advocacy campaigns, or as part of more targeted behavioural interventions. Whether or not people are explicitly asked to record their climate-relevant behaviours for posterity, the promise (or threat) that such behaviours could become public could provoke action in people who care about their long-term reputation. Using this long-term reputational frame not only would allow communicators to rely on previously untapped social motivations for climate action, but would also encourage them to present information about the long-term projections of climate change, rather than the more uncertain ground of near-term consequences.19 This would lend credibility to the climate science message, encourage the public to take a long-term view of the problem and motivate support for new energy and climate policies.

16

Vandenbergh and Raimi, ‘Climate change’. M. P. Vandenbergh, ‘Beyond elegance: a testable typology of social norms in corporate environmental compliance’, Stanford Environmental Law Journal 22 (2003), 55–144; M. P. Vandenbergh and J. M. Gilligan, ‘Beyond gridlock’, Columbia Environmental Law Journal 40(2) (2015), 217–303. 18 Raimi and Vandenbergh, ‘Posthumous reputations’. 19 Intergovernmental Panel on Climate Change, ‘Summary for policymakers’. 17

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7

THE EMERGENCE OF EU ENERGY LAW Silke Goldberg1

INTRODUCTION: THE POLICY CONTEXT – FROM SECTOR INQUIRY TO THIRD ENERGY PACKAGE The regulatory landscape of the energy sector in the EU (and beyond) has, in the space of less than a decade, undergone a profound change. Whilst traditionally, EU competence in energy matters was derived from neighbouring competency areas such as the competition regime or environmental law, this changed with the entry into force of the Treaty of Lisbon2 in December 2009. Amongst other things, this contains a new title, XXI, specifically dedicated to energy, which, in Article 194, lists the objectives of the Union energy policy as follows: In the context of the establishment and functioning of the internal market and with regard for the need to preserve and improve the environment, Union policy on energy shall aim, in a spirit of solidarity between member states, to ensure the functioning of the energy market; ensure security of energy supply in the Union; and promote energy efficiency and energy saving and the development of new and renewable forms of energy; and promote the interconnection of energy networks. This formalisation of EU energy competencies is of great importance to the legal footing of all future EU energy initiatives, as early European legislators had to rely on a patchy mix of legal bases for EU energy policy and legislative initiatives, which may have hindered the development of an earlier coherent EU energy strategy. 1

2

Silke Goldberg is counsel in the Global Energy Group of Herbert Smith Freehills where she specialises in European energy law. Silke is admitted in England and Wales and the Republic of Ireland. She is also a member of the Berlin bar (Rechtsanwaltskammer Berlin). Official Journal of the European Union (17 December 2007), C306/1.

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In 2005, the European Commission undertook an inquiry into competition in the gas and electricity markets (the ‘Sector Inquiry’) as provided under Article 17 of Regulation 1/20033 on the implementation of the EC Treaty rules on competition, aimed at assessing the prevailing competitive conditions and establishing the causes of the perceived market malfunctioning. Incidentally, the Sector Inquiry can be seen as an example (possibly the last) of the European Commission having to rely on its competition competencies in order to address issues pertaining to the design and regulation of the energy market. Whilst the Sector Inquiry was conducted prior to the signature of the Lisbon Treaty, the Third Energy Package (TEP) was adopted after its signature but before its entry into force (which occurred later in the same year). The Sector Inquiry examined eight key areas of the European energy market: (1) market concentration/market power; (2) vertical foreclosure (most prominently, inadequate unbundling of network and supply); (3) lack of market integration (including lack of regulatory oversight for cross-border issues); (4) lack of transparency; (5) price formation; (6) downstream markets; (7) balancing markets; and (8) liquefied natural gas (LNG). Following the Sector Inquiry, a legislation package containing three Regulations and two Directives4, commonly referred to as the Third Energy Package, or TEP, was adopted and entered into force on 4 September 2009. Member states had until March 2011 to transpose the majority of the provisions in the Third Electricity and Gas Directives into national law, the exception being the ‘third country clause’, which needed to be transposed by March 2013. The Third Gas and Electricity Regulations and ACER Regulation entered into force in September 2009. The TEP seeks to address in particular the findings of the Sector Enquiry regarding vertical foreclosure, the lack of market integration and transparency.

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Council Regulation (EC) No. 1/2003 of 16 December 2002 on the implementation of the rules on competition laid down in Art. 81 and Art. 82 of the Treaty (OJ L 1 of 4 January 2003, p. 1), as amended by Council Regulation (EC) No. 411/2004 (OJ L 68 of 6 March 2004, p. 1), Council Regulation (EC) No. 1419/2006 (OJ L 269 of 25 September 2006, p.1), Council Regulation (EC) No. 169/2009 (OJ L 61 of 5 March 2009, p. 1), Council Regulation (EC) No. 246/2009 (OJ L 79 of 26 February 2009, p. 1) and Council Regulation (EC) No. 487/2009 (OJ L 148 of 25 February 2009, p. 1). Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in electricity and repealing Directive 2003/54/EC (the Third Electricity Directive) OJ L 211of 14 August 2009, p. 55; Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas and repealing Directive 2003/55/ECA Gas Directive amending and completing the existing Gas Directive 2003/55 (the Third Gas Directive) OJ L 211 of 14 August 2009, p. 94; Regulation (EC) No. 713/2009 of the European Parliament and of the Council of 13 July 2009 establishing an Agency for the Cooperation of Energy Regulators (the ACER Regulation) OJ L 211 of 14 August 2009, p. 1; Regulation (EC) No. 714/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the network for cross-border exchanges in electricity and repealing Regulation (EC) No. 1228/2003 (the ‘New Electricity Regulation’) OJ L 211 of 14 August 2009, p. 15; and Regulation (EC) No. 715/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the natural gas transmission networks and repealing Regulation (EC) No. 1775/2005 1775/05 (the ‘New Gas Regulation’) OJ L 211 of 14 August 2009, p. 36.

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Other findings of the Sector Enquiry have been addressed through competition law remedies. In some cases (price formation, balancing markets), the findings are being remedied by secondary implementing legislation of the TEP such as the network codes or, alternatively, aspects of the EU Regulation on wholesale energy market integrity and transparency (‘REMIT’).5 This chapter briefly describes and analyses three aspects of the TEP which have had the biggest impact on the regulatory landscape: • unbundling (including the ‘third country clause’) • regulatory oversight • European Transmission System Operator (TSO) cooperation and network codes. UNBUNDLING For the purposes of the Third Electricity and Third Gas Directives the ‘unbundling’ regime is of central importance. In the context of the TEP, ‘unbundling’ means the separation of the operation of gas pipelines and electricity networks at transmission level from the business of producing or supplying either gas or electricity.6 Under the TEP there are three main unbundling options which the member states may select under certain circumstances. The options are: • the full ownership unbundling model • the independent system operator (‘ISO’) model • the independent transmission operator (‘ITO’) model. The full ownership unbundling model requires the complete separation of the operation of gas and electricity transportation/transmission networks and those activities related to production, generation and supply. The ownership unbundling model also puts in place new restrictions in respect of ownership. The operators of gas and electricity transmission networks are no longer permitted to be part of (or affiliated to) a corporate group which is also active in supply, generation or production. The operator of the network will also be obliged to own and control the entire network. The ownership unbundling model does not, however, prevent a person or a company from, in certain circumstances, holding shares in both a network operator and an entity involved in production/supply activities provided that the shares constitute a non-controlling minority interest. Such interest must not have any voting rights or other rights of veto in the entities concerned and must not have rights to appoint members to either of the entities’ boards of directors. In addition, no single person may be a member of the board of directors of the

5

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Regulation (EU) No. 1227/2011 of the European Parliament and of the Council of 25 October 2011 on wholesale energy market integrity and transparency OJ L 326 of 8 December 2011, p.1. Art. 9 of both the Third Electricity Directive and the Third Gas Directive.

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network operator and of a supply/production undertaking, and this may be particularly relevant to non-sector investors (such as pension funds). Under the ISO model7 the network must be managed by an identified ISO (which must perform all the functions of a network operator) although it is permitted for vertically integrated companies to maintain ownership of their network assets.8 The ISO model requires the ISO to comply with the same unbundling requirements as other network operators and be a completely separate undertaking from the vertically integrated company.9 On this basis, the ISO cannot have a shareholding in any supply or production entities. The ITO model permits TSOs to keep in place their vertically integrated structures. The model requires relevant TSOs to comply with additional regulations to ensure the independence of each such activity. The third country clause The TEP provides that national regulatory authorities (‘NRAs’) need to certify any TSO as compliant with the unbundling regime before the relevant TSO is allowed to take up its function as a TSO.10 In addition, under the so-called third country clause,11 national regulators are required to refuse certification of a TSO if the relevant company does not comply with the unbundling requirements, and its market entry would jeopardise the member state’s or the EU’s security of supply.12 TSOs must notify the relevant NRA if any circumstances13 arise that would result in an entity from a non-EU country acquiring control of the transmission system or its operator. The relevant NRA must also seek the view of the European Commission14 as to whether the foreign entity passes the unbundling and energy security tests and must take ‘utmost account’ of the Commission’s view. REGULATORY OVERSIGHT For the first time in European energy legislation, the TEP sets objectives for the NRAs with a notable European dimension. The Third Gas and Third Electricity Directives state that the NRAs’ objective is to: promot[e], in close cooperation with the Agency, regulatory authorities of other Member States and the Commission, a competitive, secure and environmentally sustainable internal market in natural gas within the Community, and effective market opening for all customers and suppliers in the Community, and ensuring appropriate conditions for the effective and reliable operation of gas networks, taking into account long term objectives.15 7

Art. 13, Third Electricity Directive and Art. 14, Third Gas Directive. Art. 14(1), Third Electricity Directive and Art. 15(1), Third Gas Directive. 9 Art. 13(2)(a), Third Electricity Directive and Art. 14(2)(a), Third Gas Directive. 10 Art. 10 of both the Third Electricity Directive and the Third Gas Directive. 11 Art. 11(3) of both the Third Electricity Directive and the Third Gas Directive. 12 Art. 11(1) of both the Third Electricity Directive and the Third Gas Directive. 13 Art. 11(2) of both the Third Electricity Directive and the Third Gas Directive. 14 Art. 11(5) of both the Third Electricity Directive and the Third Gas Directive. 15 Article 36(a), Third Electricity Directive and Article 40(a), Third Gas Directive. 8

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In order to reinforce the position of regulators at European level and ensure continued cooperation, the ACER Regulation created the Agency for Cooperation of Energy Regulators (‘ACER’). ACER is competent to issue opinions addressed to TSOs, NRAs and the European Commission, and can take individual decisions on technical issues. ACER’s tasks include: • participation in the development of European network codes16 • monitoring the development of the energy markets, particularly in relation to retail gas and electricity prices17 • monitoring the implementation of the TSO’s ten-year infrastructure investment plans18 • establishing non-binding ‘framework guidelines’ on conditions for access to the network for cross-border electricity and gas exchanges.19 ACER is permitted to provide recommendations designed to assist regulatory authorities and players in the market, to promote the sharing of information relating to good practice as well as to foster cooperation between national regulatory authorities and between regulatory authorities at the regional level. Such guidelines can be part of ACER’s own work programme or at the request of the Commission.20 NRAs may also ask ACER to issue an opinion where the application of the guidelines referred to in the Third Gas and Electricity Directives and the Third Gas and Electricity Regulations is unclear.21 The ACER Regulation grants ACER decision-making powers in specific areas, particularly with respect to cross-border projects and cooperation.22 ACER also fulfils the position of a ‘Regulator of last resort’ where the national regulator of a member state using an ISO model has failed to appoint an ISO within the required timeframe.23 TSO COOPERATION AND EUROPEAN NETWORK CODES The increasing energy demand and simultaneous import dependency of the EU will require improved transmission networks which are able to cope with the ‘energy traffic’ created by the export and import of electricity and gas during peak demand conditions. Cooperation between TSOs will make an important contribution to network reliability, particularly in heavily interconnected areas. The New Electricity Regulation and New Gas Regulation24 formalise the cooperation between transmission network operators, which at present is evident through platforms such as Gas Transmission Europe (GTE) 16

Article 6(4), ACER Regulation. Article 11(1), ACER Regulation. 18 Art. 6(8), ACER Regulation. 19 Art. 4(e), ACER Regulation. 20 Art. 7(2) and Art. 7(3), ACER Regulation. 21 Art. 7(4) and 7(6), ACER Regulation. 22 Art. 7(7), ACER Regulation. 23 Art. 8(1), ACER Regulation. 24 Art. 5 of both the New Electricity Regulation and New Gas Regulation. 17

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and European Transmission System Operators (ETSO), through the establishment of a European Network for Transmission System Operators for the electricity and gas sector (‘ENTSO-E’ and ‘ENTSO-G’, respectively). The ENTSOs’ responsibilities include: • the development of coherent market and technical codes needed for the integration of the electricity and gas markets, which the ENTSOs are tasked to develop in cooperation with ACER and the Commission on the basis of the framework guidelines developed by ACER • the finance and management of cooperative research and innovation activities focused on the technical development of European electricity and gas networks in relation to energy security, efficiency and low carbon technologies • the coordination of the planning of network investments and the monitoring of the development of transmission network capacities. The two ENTSOs must publish a Europe-wide, ten-year forwardlooking investment plan every two years. Since its inauguration, ACER has conducted more than twenty consultations and issued Framework Guidelines regarding a number of network codes, including Electricity grid connections; Capacity allocation and Congestion Management for Electricity; Capacity allocation mechanisms for the European gas transmission network; and Electricity system operation. The main conclusion that can be drawn from these consultations, the subsequent publication of Framework Guidelines and the adoption of network codes is that whilst the changes proposed in each set of Framework Guidelines may be relatively small, their effect is cumulative. Therefore, the changes will achieve results, although this will take some time. The benefits of such coherent European codes are generally to be found in the intended elimination of inconsistencies at the national level regarding, for example, tariff structures, capacity allocation rules, balancing arrangements and trading timetables, and security of supply measures. At present, such differences in market design lead to market segmentation, with some national markets remaining split into different local tariff or balancing areas. However, at the same time, the development of the European network codes will necessarily cause some friction to the existing national approaches. CONCLUSION The TEP marks the first attempt to at comprehensive regulation of the European downstream energy market. It is also the first legislative package to introduce some secondary legislative tools (in particular, the network codes) necessary for the effective implementation of that seemingly elusive goal of a completed internal energy market, thereby equipping itself with at least some flexibility for the design and implementation of the European energy target models.

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Whilst some aspects of the regulatory landscape seem to be work in progress and somewhat hesitant (for the most part, ACER’s competencies are considered to be advisory in nature), the effect of the European network codes will undoubtedly be a greater degree of market harmonisation, which in turn might result in better network and operational reliability. In response to the relatively slow attempts to implement the European target models for the electricity and gas markets and the fact that there are still considerable differences in particular in the design of members states’ electricity markets, some commentators have suggested that the European legislators ‘should propose one or several generic market designs’,25 the development and implementation of which should be entrusted to ACER. No doubt ACER’s role will grow over time; its legal framework appears to be designed to leave ACER some freedom to fully define and exercise its scope. In other areas, more work remains to be done. The Commission installed in 2014 set out four key objectives for its term until 2019, which focus on: (1) the creation of an Energy Union; (2) the diversification of energy sources; and (3) a reduced energy import dependency for the EU as a whole. The fourth objective is linked to the EU’s climate commitments and aims to make the EU a leader for renewable energy and the fight against global warming. The importance of the internal energy market and climate issues for the Commission is also reflected in the appointment of both a Commissioner for Climate Action and Energy (in the person of Miguel Arias Cañete) and a Vice-President of the Commission with a specific remit for the Energy Union (Maroš Šefčovič). As the Commission sets out to implement its ambitious work programme for the energy sector, some have called for a fourth energy package to put the Energy Union into practice and to address the dichotomy between national energy policies and European energy regulation. Whether or not such a package will be forthcoming, European energy law is an emerging force that will only continue to grow in importance over the next few years as it shapes the future of the energy markets.

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G. Zachmann, ‘Elements of Europe’s energy union’, bruegelpolicybrief (September 2014), available at www.bruegel.org/publications/publication-detail/publication/846-elements-of-europesenergy-union

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HOW TO IMPROVE REGULATION Thomas P. Triebs1

THE ISSUE Today, with little public ownership and liberalised markets, regulation invariably operates at arm’s length. Economists say that regulation sets high-powered incentives for firms, implying that firms are residual claimants to their effort.2 Effectively, regulation is less direct and less detailed than it used to be. Companies, not regulators, decide on the details of product offerings like price, quality or production technology. Economists generally welcome this development but policy-makers worry about losing control. Given asymmetric information about production possibilities and consumer preferences, economists argue that companies are in a better position to make detailed decisions on product offerings. Policy-makers often perceive firms’ discretion as leading to uncertainty about outcomes. To reduce uncertainty, in many instances regulators try to regain control and re-regulate various activities. Examples of regulations that are probably too detailed include varying levels of support for different renewable technologies, capacity markets or social tariffs. Given efforts to re-regulate, how can we further improve regulation without giving up the benefits of incentives?

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Thomas P. Triebs specialises in empirical work on production, productivity and management and applies productivity and efficiency measurement to issues on policy, management and regulation. His background combines economics, management and policy. He holds a PhD from Judge Business School, Cambridge and an MA (Econ) from Maastricht University. This chapter builds on the economic theory of regulation as detailed in, for instance, J.-J. Laffont and J. Tirole, A Theory of Incentives in Procurement and Regulation, 4th edn (MIT Press, 1999).

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THE COMPETITIVE BENCHMARK In any market, firms, pushed by consumers and competitors, decide on the success or failure of product propositions. But what sets competitive, unregulated markets apart from energy markets is that they provide products that are not essential (failure to deliver is tolerable) and goods are made available at terms that do not harm consumer welfare. Energy is different, because a failure to provide it is often not tolerable. This essential good characteristic tempts regulators to regulate details (and in the extreme, to revert to outright nationalisation). Further, market power and environmental externalities harm consumer welfare and require some form of regulation. Over the last decades various parts of the energy supply chain have moved closer to the competitive ideal. For instance, in many countries wholesale electricity prices are largely deregulated. Price setting is only constrained by general competition law and environmental regulation. Nevertheless, it is unlikely that energy markets will be fully competitive any time soon. But regulators should be careful not to impede any institutional or technical innovations that move energy markets closer to the competitive ideal. HOW DID WE GET HERE? To mitigate any potential harm to consumer welfare, energy markets have been regulated for many decades in developed countries. But whereas in the past regulation often implied tight control of companies’ decisions, during the 1980s and 90s, more and more decisions were left to the discretion of individual firms. One reason for this development was that whereas the original motivation for regulation (or nationalisation) was to contain market power, during the 1980s and 90s this changed and concern over government inability to regulate (due to asymmetric information or capture) and company inefficiency (due to poorly designed regulation) began to dominate. The consequence was an effort to privatise, to introduce competition where possible and to move from cost-plus to fixed-price regulatory contracts (that is, increase the power of incentives). Today, in some countries regulators and policy-makers are again tightening controls. Examples are technology-specific feed-in tariffs, capacity markets or the re-nationalisation of networks. Are there any good reasons to tighten controls again – that is, to reduce the power of incentives? THE COSTS AND BENEFITS OF INDIRECT CONTROL The tendency to tighten regulatory control suggests that regulation at arm’s length has disadvantages. What might these be? First, making regulated firms residual claimants to their effort by setting a price cap instead of setting a fixed and ‘fair’ rate of return might produce rents3

3

Rent is the amount of profit beyond that which the company requires to stay in business voluntarily.

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that are not politically feasible. There is empirical evidence that when firms are residual claimants they exert themselves to reduce the cost of delivering energy. For given output prices lower costs increase rent. When the regulator does not know the firm’s true minimum cost, such rents are effectively a ‘reward’ for effort. In competitive markets often the ‘reward’ is simply to stay in business. If firms believed that all efficiency increases were appropriated by regulators (and did not face the threat of exit) they would not exert any effort to increase efficiency in the first place. With strong incentives, companies might earn large profits but these are not per se objectionable because what matters is the total revenue requirement that customers (or taxpayers) need to finance. If that decreases, then society is better off. What matters is the cost and price performance of firms. To obtain the benefits of indirect control, society needs to tolerate rents and regulators need to be able to commit. Commitment is simply the ability to keep today’s promise. Second, when the firm faces uncertainty indirect regulation might not work. The reason is that with too much uncertainty companies might be unwilling to assume the associated financial risk and not provide the good in question at all. For instance, with high uncertainty the fixed-price contract discussed above might not be accepted by the firm and a cost-plus contract with a guaranteed rate of return is necessary. Examples are projects for nuclear new-build or large offshore wind parks suggesting that these technologies are not sufficiently mature and/or standardised for firms to be willing to assume the risk of construction. Direct control reduces uncertainty for the firm and the firm produces the good in question unless the rate of return is set too low. The latter condition is referred to as the participation constraint, that is, the firm has to be better off producing than not producing. Third, with regulation at arm’s length companies decide on important details like the technology mix and the future technology trajectory. If policy-makers or regulators have strong preferences for certain technologies, direct control is required, especially if the preferred (or socially optimal) technology mix/path is not profitable for private firms. Two common reasons why policy-makers prefer certain technologies are the reduction of pollution and the development of domestic skills and industries. When policy-makers are unable or unwilling to internalise pollution via the standard means of a tax or emissions trading they can procure technologies that pollute less using cost-plus contracts. When policy-makers wish to develop specific skills or industries that are not privately profitable they have to assume any extra costs, that is, transfer costs to customers or taxpayers. HOW TO IMPROVE REGULATION? Despite its potential disadvantages, as discussed above, indirect regulatory control has one important advantage. It provides incentives for firms to use their superior knowledge about their potential performance to operate more efficiently, in both the short and long term. Thus it brings us closer to the ideal of competition. Given this advantage how can regulators mitigate any shortcomings?

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First, as discussed above, the regulator needs to offer a reward to induce effort if the firm’s minimum cost is unknown. But the competitive ideal tells us that the reward needs to be neither large nor persistent. How can a regulator offering high-powered incentives make sure that the potential upside for firms is not excessive? The regulator should introduce competitive elements where feasible. Competition naturally constraints the reward firms earn for their efforts. For instance, today, electricity generation is highly competitive and no longer requires regulation. Many countries are now also experimenting with retail competition, and in the not-too-distant future technological change might allow competition between delivery networks, just like in the telecommunications industry. Where competition is currently not feasible, as in the case of networks, rents can be controlled (without destroying the incentive effects) using benchmarking (or yardstick competition). It mimics competition in the sense that only outperformance attracts special rewards and even these are temporary. Benchmarking as practised by many European network regulators sets price caps in relation to the best observed performance. This ensures that relatively inefficient firms have to improve their performance to earn a sufficient return and guarantees that the target is feasible, that is, that no firm is pushed into bankruptcy. In the US, this form of benchmarking is not common but regulators use profit sharing or incentive regulation schemes. Here the regulators set ex-ante sharing rules for outperformance on transparent and verifiable metrics like fuel rates. Second, when a firm is unwilling to accept a high-powered contract due to a project’s risk, the regulator could offer a cost-plus contract instead. However, instead of giving up the use of incentives the regulator could help reduce the firm’s uncertainty in the medium term. Often uncertainty stems from the immaturity of a production technology and invention or innovation is required to mature the technology. But a regulated firm under a cost-plus contract might not engage in R&D, because if successful it would lower the cost base on which it earns a regulated return. (In addition, the firm might not be able to appropriate any benefits from R&D.) In this case, the regulator should directly pay for the R&D activity and leave in place high-powered incentives for the non-R&D activities of the firm. Third, when private, profit-maximising firms do not employ the policymaker’s preferred technology, the regulator has to offer a cost-plus contract to procure the desired technology. Through the cost-plus contract the regulator can subsidise the part of the costs that a competitive firm cannot recoup. The subsidy and related inefficiencies make it important to argue carefully why a particular technology mix is required. If the problem is pollution, a tax or emissions trading are much better ways to solve it. In any case, a central planner is very unlikely to choose the best technology mix from a large number of demand- and supply-side options to tackle pollution. Similarly, if policy-makers absolutely need to maintain certain skills or industries, cost-plus contracts are the only choice and the likely inefficiencies are the necessary price to pay.

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CONCLUSION Energy markets are unlikely to attain the competitive ideal any time soon. Regulation of markets and firms is necessary but some forms of regulation mimic competition better than others. In particular, high-powered regulatory contracts have incentive properties similar to competition. But just like (imperfectly) competitive markets they allow transitory rents and do not provide goods if uncertainty is high or technologies are unproven. Policy-makers sometimes hope that using more direct forms of regulatory control can reduce rents and support specific technologies. I have argued that in many instances regulation can be improved without forsaking the incentive properties of indirect control. Indirect control is compatible with controlling rents and it is better to reduce uncertainty directly than to give up the use of incentives. It is, however, not possible to achieve certainty about the use of specific technologies without giving up the use of incentives. In the past the most beneficial technical improvements were the ones that were not foreseen or planned deliberately. It is not obvious why policy-makers should have preferences for specific technical solutions in the first place.

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DELIVERING ENERGY NETWORKS SECURITY: ECONOMICS, REGULATION AND POLICY Tooraj Jamasb1 and Rabindra Nepal2

INTRODUCTION In recent years, security of energy supplies has re-emerged as a major policy concern. At the same time, there is a growing concern with regard to the physical and cyber security of critical infrastructure of strategic importance such as telecommunications, water supplies, transport systems and energy supplies. Physical and virtual networks serve as the nervous system of critical infrastructures and, while vital for the functioning of these facilities, due to their geographic spread they are vulnerable to natural disasters and malicious threats. As the modern economy is increasingly dependent on reliable but increasingly complex network infrastructures, the vulnerability of these and the cost of potential failure are also increasing. This chapter focuses on the economics, regulation and policy aspect of the security of energy networks. DELIVERING ENERGY NETWORK SECURITY Economics of network security Energy networks are generally regarded as natural monopolies. This implies that the cost structure of these networks is such that their capital costs constitute a high portion of their total costs. This in turn results in declining average costs

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Tooraj Jamasb is Chair in Energy Economics at Durham University Business School and Codirector of Durham Energy Institute. Rabindra Nepal is a Lecturer in Economics at the CDU Business School, Charles Darwin University, Australia.

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as the scale increases. As a result, it is more cost-effective for a single network to serve the whole sector than for multiple competing firms. It then follows that in the absence of competitive markets these networks are, in the public interest, in public ownership or subject to economic regulation.3 In most European countries, prior to the 1990s the energy networks were in public ownership and overseen by the relevant ministries. In the USA, the major network utilities have traditionally been privately owned and regulated by Public Utility Commissions (PUCs) or the Federal Energy Regulatory Commission (FERC). In economic terms, the decision problem with regard to provision of network security can be framed as the level of precaution required to minimise the total cost of the expected value of damage of security-related incidents. The expected value of damage can be viewed as a decreasing function of the product of probability of an incident occurring multiplied by the value of damage from the incident. This damage must then be weighed against the cost of undertaking precautionary efforts to prevent the incident (as an increasing function of precaution). The economical point is then where the sum of total costs of expected damage and those of precautionary efforts are minimised. It is, however, possible to deviate from this minimum efficient cost level for security, social or other considerations. Incentive regulation for network security Since the 1990s, the economic regulation regimes in many countries have gradually shifted from cost-based regulation to incentive-based regulation models. Cost-based regulation covers the costs of a network utility plus a set rate of return. However, the incentive properties of this approach can, in theory and in practice, result in cost inefficiency and over-investments.4 Consequently, some sector regulators have adopted incentive-based regulation models that reward input cost efficiency or quantity and quality of outputs. The theoretical and methodological advances in recent decades have enabled the sector regulators to adopt innovative incentive-based models for economic regulation of network utilities. Incentive regulation can be facilitated by the use of efficiency and productivity analysis techniques for benchmarking of network utilities and to reward or penalise cost and quality of service efficiency performance.5 In the absence of market mechanisms in the network sector, benchmarking is used to mimic a competitive market situation and to reduce information asymmetry between the sector regulators and the regulated firms.6

3

4

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M. Armstrong, S. Cowan and S. J. Vickers, Regulatory Reform: Economic Analysis and British Experience (MIT Press, 1994). H. Averch and L. Johnson (1962), ‘Behavior of the firm under regulatory constraint’, American Economic Review 52(5), 1052–69. D. Giannakis, T. Jamasb and M. Pollitt, ‘Benchmarking and incentive regulation of quality of service: an application to the UK electricity distribution networks’, Energy Policy 33(17) (2005), 2256–71. See A. Shleifer, ‘A theory of yardstick competition’, The RAND Journal of Economics 16(3) (1985), 319–27; T. Jamasb and M. Pollitt, ‘Benchmarking and regulation: international electricity experience, utilities policy’, Utilities Policy 9(3) (2000), 107–30.

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The existing incentive-based regulation and utility benchmarking models can be adapted and modified to address energy networks’ security concerns.7 Within this approach, network security can be conveniently viewed as an extension of performance standards and economic regulation of quality of network services.8 Incentive regulation of network security can then either focus on network security inputs, that is, capital and operating costs and network security outputs or performance measures such as the number and frequency of long interruptions. This general framework can be used in both input-based and output-based regulation.9 The policy-makers and sector regulators have a few options at their disposal. They can treat the security costs as a pass-through item – the utility can invest an agreed-upon amount on security and recover this through its network charges. Alternatively, the regulator can treat the security costs as investment and allow the utility to earn a rate of return on these. Another option is that the regulator can subject the costs of security improvement to incentive regulation, that is, to offer economic incentives to achieve a desired security level. This can be done by including a new component Q* to the conventional price/revenue cap incentive model as in the equation below. Q* is the network security adjustment factor that reflects continuity of supply, for example in terms of long, unplanned supply interruptions. The allowed price (or revenue) path Pt of the company is then directly linked to network security performance where X is the efficiency improvement factor obtained from cost and service quality efficiency benchmarking and RPI is the retail price index.10 Pt = Pt-1 (1+ RPI – X+ Q*) Within the above approach, network security can be conveniently treated as an extension or aspect of quality of service. This is possible because the quality of network services is already subject to regulation in most countries as an incentivised output or through mandatory performance standards. Network security policy In addition to the economic regulation approach, policy-makers have another option to consider. They can view security of the network infrastructure as a strategic priority for national security. This view suggests that the security costs can be covered from the national security budget. The network security costs

7

T. Jamasb and R. Nepal, ‘Issues and options in the economic regulation of European network security’, Competition and Regulation in Network Industries 16(1) (2015), 2–22. 8 T. Jamasb, L. Orea and M. G. Pollitt, ‘Estimating marginal cost of quality improvements: the case of the UK electricity distribution companies’, Energy Economics 34(5) (2012), 1498–506. 9 C. Cambini, A. Croce and E. Fumagalli, ‘Output-based incentive regulation in electricity distribution: evidence from Italy’, Energy Economics 45 (2014), 205–16. 10 R. Nepal and T. Jamasb (2015), ‘Incentive regulation and utility benchmarking for electricity network security’, Economic Analysis and Policy 48(4), 117–27.

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can be imposed on network utilities and paid for by the taxpayer (as opposed to the energy rate payer) in line with other defence and security costs. This approach places the coverage of the costs beyond economic incentives. The socioeconomic costs of major power supply interruptions from accidental and malicious attacks are very high.11 Given the heightened expectation of security risk to the energy networks, there is broad agreement among the sector regulators and decision-makers that the security of these networks is a high priority and needs to be maintained. In the event of major supply disruptions, economic regulation can also help alleviate the effect of supply shortages and minimise the economic and welfare effect of these. Competitive wholesale and retail energy markets balance the short-term demand and the available supply through the price mechanism.12 However, contingency plans are needed for burden sharing in the event of medium- to long-term supply interruptions. The rational approach to burden sharing is to base these on social welfare and economic cost considerations. The decision-makers and regulators need to obtain estimates and decide on the appropriate level of investment in network security. These can be inferred from modelling the potential economic and welfare costs of lowprobability, high-impact incidents.13 The social welfare on households can be obtained from survey-based contingent valuation methods.14 For industrial and commercial users, this valuation can be based on modelling the cost of major interruptions to economic output taking into account the interdependencies among the different groups of users. It should be noted that the impacts of supply interruptions on individual industries can vary considerably in terms of their physical inoperability as opposed to economic cost due to loss of the output.15

11

R. Nepal and T. Jamasb, ‘Security of the European electricity systems: conceptualizing the assessment criteria and core indicators’, International Journal of Critical Infrastructure Protection 6(3–4) (2013), 182–96. 12 T. Jamasb and M. Pollitt, ‘Security of supply and regulation of energy networks’, Energy Policy 36(12) (2008), 4584–9. 13 See the following: R. Poudineh and T. Jamasb, ‘Electricity supply interruptions: sectoral interdependencies and the cost of energy not served’, OIES Paper: EL 12 (2015), Oxford Institute for Energy Studies, University of Oxford; R. S. Pindyck and N. Wang ‘The economic and policy consequences of catastrophes’, American Economic Journal: Economic Policy 5(4) (2013), 306–39; and M. Nooij, C. Koopmans and C. Bijvoet, ‘The value of supply security: the costs of power interruptions: economic input for damage reduction and investment in networks’, Energy Economics 29 (2007), 277–95. 14 See W. Yu, T. Jamasb and M. Pollitt (2009), ‘Willingness-to-pay for quality of service: an application to efficiency analysis of the UK electricity distribution utilities’, The Energy Journal 30(4) (2009), 1–48 and Ofgem, ‘Expectations of DNOs and willingness to pay for improvements in service’, Report prepared for Ofgem by Accent, Final Report (2008), Office of Gas and Electricity Markets, London, available at www.ofgem.gov.uk/ofgem-publications/47387/1704rep04final.pdf 15 See specifically Poudineh and Jamasb, ‘Electricity supply interruptions’.

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CONCLUSIONS Security of energy supply and infrastructure is a policy priority for most energy policy-makers and regulators in both the EU and the USA. A sound regulatory approach with regards to network security needs to provide sufficient incentives to improve security to prevent outages but also to allocate and manage the supply shortfall in the event of major supply failures. However, the regulation of network security can also be understood in its wider economic regulation and national policy context. The harmonisation of network security objectives and intensifying coordination among countries will be essential to deliver adequate supply security given its national importance and increasing international interdependencies.

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THE ROLE OF MARKETING IN DELIVERING ENERGY LAW AND POLICY Paul Haynes1

INTRODUCTION Delivering effective energy law and policy will require a framework appropriate to a variety of energy stakeholders. Examining marketing practice will provide crucial insights into many of the challenges posed by meeting the diverse demands of stakeholders. This is because marketing is concerned with examining the combination of strategies available to organisations in considering supply and demand objectives. Traditionally these strategies have been grouped into 4 Ps (Product, Price, Place and Promotion), which collectively constitute a marketing mix. Marketers decide what the company makes or supplies, how much it will cost to buy, where it can be purchased and how to communicate relevant information to potential customers about the product. The performance of a framework in providing appropriate incentives, or restrictions, will thus depend upon complex interdependencies between stakeholders, principally energy producers and energy consumers, determined by marketing decisions. Effective command and control instruments must have viable alternatives to the practices and technologies they prohibit, while any incentives presented by a policy must be attractive in order to have the desired consequences. Marketing studies such choices and incentives and provides insights that help to bridge the gap between the aspirations of different stakeholders related through these choices. The options that are assembled for potential consumers are shaped by supply and demand considerations and thus energy law and energy policy must

1

Paul Haynes is a Lecturer in Marketing in the School of Management, Royal Holloway, University of London. Paul’s research interests are in branding, sustainability, networks, technological innovation and complexity.

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have an impact on marketing decision-making to leverage their objectives, such as energy-related carbon emissions reduction. Businesses, as providers of much of the energy services and infrastructure, and as consumers or transformers of much of the energy used in the EU and US, will have a considerable impact on the success or failure of energy law and energy policy. Though the nature of the product, its price and place of sale are to some degree dynamic factors, the methods used to promote products or services provide many opportunities to meet multiple objectives of energy law and policy, due to their variety and adaptability. In many sectors in which near-identical products are sold, success or failure can be determined by promotional strategies. For most businesses, the importance of promotion through paid media means that marketing has become a near synonym for advertising. However, promotion includes communications, advertising, sponsorship and branding, each of which is a strategic option within a promotional mix. These options will be explored in the following section. PROMOTING CLEANER ENERGY OPTIONS Energy law and policy options relate to a variety of energy generation and consumption features (security of supply, access to energy, energy sustainability and so on). This chapter will focus primarily on the contribution of energy to climate change, or, more specifically, possible changes in energy generation and consumption able to serve climate change mitigation. There are two key strategies in mitigating climate change through energy use: substituting one energy source for a lower-emission alternative, such as renewable energy for fossil fuels, or reducing energy consumption as a whole, such as through energy-efficiency gains or energy-conservation practices. Marketing provides a framework through which energy service providers can determine their strategy in addressing one or other of these mitigation approaches and evaluate the promotional options applicable to each of these objectives. Research suggests that at present price is the main incentive able to stimulate changes in consumption.2 Energy prices are not, however, easily adjustable as an energy consumption mediator. There are a number of reasons for this: energy markets are competitive across the EU and US; political barriers exist, such as preventing energy poverty and the unpopularity of higher energy and fuel bills; the cost of emissions are uncertain and in any case excluded from the price of energy, that is, as externalities. Consequently there is considerable interest in changing generation and consumption habits on the basis of other incentives.3 In this regard, a common response is the view 2

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R. Wiser, M. Bolinger and E. Holt, ‘Customer choice and green power marketing: a critical review and analysis of experience to date’, Proceedings of the 2000 ACEEE’s Summer Study on Energy Efficiency in Buildings (Pacific Grove, CA, 2000), available at https://emp.lbl.gov/sites/all/files/ report-46072.pdf M. J. Polonsky, A. Vocino, S. L. Grau, R. Garma and A. S. Ferdous, ‘The impact of general and carbon-related environmental knowledge on attitudes and behaviour of US consumers’, Journal of Marketing Management 28(3–4) (2012), 238–63.

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that consumer values need to be changed. The argument implies that consumers need more information and education to be aware of the negative consequences of their actions and the need to alter their values to reflect sustainable living. These consumption changes will, in turn, provide incentives to businesses to provide sustainable choice for consumers. This approach has been taken by many campaigns and policy initiatives, but has failed to deliver the changes desired.4 Strategies based on persuading consumers to change their values meet with considerable resistance. Alternative approaches involve promoting products and services in ways that resonate with existing values.5 This chapter will examine the contribution of marketing, and in particular promotion, in meeting the objective of reducing the environmental impact of energy generation. CONSERVING ENERGY: REDUCING CONSUMPTION Energy conservation products or processes emerge within various sector of the economy. There are, however, marketing implications for the way that energy efficiency is framed and communicated. For example, energy-efficient products could be promoted using these features as indications of superior design in markets where design is a prime factor for consumers, rather than as environmental benefits. Other framing choices could be between guilt-free narratives (new appliances) or long-term cost savings (efficient light bulbs). Alternatively, commitments to energy-efficiency processes could be framed in terms of corporate social responsibility, with reputational advantages. For energy supply companies there are opportunities for promoting additional services such as energy monitoring technology or smart metering/grids. Providing bill comparison data and domestic energy efficiency support in intuitive and engaging ways, either directly or through third parties, are also areas in which marketing considerations might be relevant to meet emission reduction objectives. Additionally, communicating the virtues of reducing consumption requires the same emphasis on promotion as encouraging consumption, although campaigns designed to reduce energy are often seen as too generic. There is instead a need to focus on specific features of energy use or to implement specific energy-conservation practices.6 Finally, cost savings can trigger rebound effects, in which the money from energy savings is spent on additional goods and services, each of which has an emission cost.

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H. Cherrier, M. Szuba and N. Özçağlar-Toulouse, ‘Barriers to downward carbon emission: exploring sustainable consumption in the face of the glass floor’, Journal of Marketing Management 28(3–4) (2012), 397–419. D. B. Holt, ‘Constructing sustainable consumption from ethical values to the cultural transformation of unsustainable markets’, The ANNALS of the American Academy of Political and Social Science, 644(1) (2012), 236–55. Ibid., 236–55.

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BRANDING ENERGY: SUBSTITUTING FOSSIL FUELS In competitive energy markets, there is often a lack of transparency concerning energy costs and service qualities provided by energy companies. There is also uncertainty regarding future costs or other potential barriers to switching providers and other obstacles to price competition. As noted earlier, though price is a key factor, there are other incentives that influence consumer behaviour. In this context, branding can be used by energy service providers to promote cleaner energy. This can be done in two ways – branding energy providers or branding packages of energy. At present there are many energy companies generating only renewable energy, with benefits emphasised in their branding and other promotional materials. Renewable energy is not, however, the cheapest energy generation method, though it has a more favourable environmental impact than fossil fuel. Encouraging large energy providers to include renewable energy in their portfolio would be a powerful spur to investment, but at present most consumers choose the energy provider and consume the energy available without further differentiation. There is thus little incentive for energy suppliers to invest in more expensive (and potentially intermittent) energy sources. There are, however, no inherent barriers to energy providers selling a proportion of their renewable energy at a higher price as a method of making renewable energy more economically viable. Using branded energy packages as the basis for energy companies to differentiate their energy according to their emissions index provides an opportunity to encourage renewable energy generation on the basis of consumer demand. A transition in energy provision, afforded by substitution based on a package’s contribution to climate change emissions, could provide a marketing approach to emissions reductions. In conclusion, energy law and policy designed to address as complex a problem as emission reduction must work within a framework that presupposes existing energy-supply business strategy and energy consumption practice. Insights from contemporary marketing could thus ensure that energy policy and legislation meet a more favourable reception from stakeholders on which legislation and policy have most impact.

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A BRIEF HISTORY OF US ENERGY POLICY Daniel H. Cole1 and Peter Z. Grossman2

Before the 1970s, American energy policy was characterised by a few straightforward goals: keep the price of oil high enough so that small independent producers could make money; provide power for industry; electrify the hinterlands; and prove that nuclear energy could be harnessed for the benefit of humankind. But the 1973 Organization of Arab Petroleum Exporting Countries (OAPEC) oil embargo changed the way US policy-makers have thought about energy ever since. Since the embargo, they have sought a magical solution to the country’s energy dilemmas by achieving ‘energy independence’, a goal that in its most literal sense has been unattainable. Despite several major legislative initiatives passed by overwhelming majorities in Congress (see Table 11.1), American energy policy over the past forty years has been often incoherent and generally a failure, misdirecting billions of dollars in pursuit of a fantasy based on a misconception.3 The misconception is that America has been enduring a series of energy ‘crises’ (or one continuous crisis) for the past four decades and that these crises were due to a ‘dangerous’ dependence on foreign oil and to the ‘fact’ that the US would soon have exhausted all domestic supplies of oil and natural gas. This story had a kernel of truth in it: the US was (and is) dependent on a world oil market. But that dependence has not proven dangerous. America has a diverse list of suppliers and gets much of its crude oil from Canada and Mexico (and, increasingly,

1

2

3

Daniel H. Cole is a Professor of Law and Professor of Public and Environmental Affairs at Indiana University, where he also serves on the Affiliated Faculty of the Vincent and Elinor Ostrom Workshop in Political Theory and Policy Analysis. Peter Z. Grossman is the Clarence Efroymson Professor of Economics at Butler University, Indianapolis, IN. He is the author of several books on energy and energy policy. P. Z. Grossman, U.S. Energy Policy and the Pursuit of Failure (Cambridge University Press, 2013).

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Table 11.1 Important US energy legislation since 1973 Emergency Petroleum Allocation Act (1973) The Energy Policy and Conservation Act (1975) The National Energy Act (1978) Public Utility Regulatory Policies Act (1978) The Energy Security Act (1980) The Comprehensive Energy Policy Act of 1992 The Energy Policy Act of 2005 Energy Independence and Security Act (2007)

domestic hydraulic fracturing, or fracking). In the last forty years, nations in the Organization of Petroleum Exporting Countries (OPEC) have been far more dependent on selling oil than the US has been on buying it from them.4 Even the energy ‘crises’ to which policies responded were artificial in the sense that they were largely self-imposed. In 1973, there were shortages of oil but these were mostly due to US price controls on oil, and later to quantity controls, that led to queues for petrol and the curtailment of supplies of oil for other purposes for many consumers. After controls were lifted in the 1980s the shortages disappeared, but there were still disruptions in the world oil market that caused occasional price spikes that dismayed consumers at times as much as had the shortages. As a result of both shortages and price spikes, consumers, who are of course also voters, have demanded that the government ‘do something’ on energy.5 Typically, policy-makers have responded with a great sense of urgency, fearing that a weak response would have political costs.6 Successive ‘crises’ produced policies that have authorised, as President Jimmy Carter noted in a speech, ‘illconsidered last minute crash programs’.7 Many of the energy laws enacted ‘in the midst of a crisis probably should not have been . . . and would not have been except for the urgency of the moment’.8 These crash programmes characteristically offered ‘solutions’ to America’s energy dilemmas. So, for example, in 1980 Congress overwhelmingly passed a bill that was intended to replace most US oil and natural gas imports with synthetic oil and gas derived primarily from coal. In 2007 Congress again acted to replace 20 per cent of all transportation fuel with ethanol, mostly derived from cellulosic feedstock. On each occasion, Congress established ambitious

4 5

6 7

8

Ibid. P. Z. Grossman, ‘The logic of deflective action: US energy shocks and the US policy process’, Journal of Public Policy 32 (2012), 33–51. R. Eyestone, From Social Issues to Public Policy (Wiley, 1978). J. Carter, ‘Address to the nation, National Energy Plan’ (1977), available at www.presidency. ucsb.edu Eyestone, Social Issues to Public Policy, p. 155.

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deadlines for achieving the goals – lending a superficial resemblance of the programmes to the one that had put Americans on the moon in the 1960s. But the energy programmes were not just technological demonstrations as the moon landing had been. They were intended to be marketplace winners. That supposition, however, was based on wishful thinking and political calculation more than a realistic appraisal of evidence. Although both synthetic fuel from coal and cellulosic ethanol had been demonstrated as feasible from a technological point of view, neither has ever been remotely cost-competitive with the resources they were meant to replace. The synthetic fuels goal was criticised at the time of its passage by five different agencies of the government as overly optimistic. The enormous ethanol mandate was also criticised by experts who saw the objective as outside the bounds of feasibility, especially in the given time frame. Synthetic fuels and ethanol are not the only possible ‘solutions’ that have had political support over the years. Various legislators, presidents and government officials have sought large-scale funding for, among other things, breeder reactors, nuclear fusion, solar energy, a hydrogen fuel-cell ‘freedom car’ and many other as-yet-unrealised technological panaceas. Policy-makers have been stymied, moreover, by conflicting ends and means. American voters have demanded a solution that would provide super-abundant quantities of domestic energy at relatively low prices. Even had the fuel-replacement programmes been successful, the energy they provided would not have come ‘cheap’. Nevertheless, technological panaceas continue to have political traction because in a crisis atmosphere the expectation is that oil and natural gas prices will rise continuously and fears of shortages are ubiquitous.9 Under those assumptions, synfuels or cellulosic ethanol promise to be less costly. But, of course, assumptions of continuously increasing prices of oil and gas never hold. Lost amid the voter demands that policy-makers ‘do something’ was any rationale for the government to enter energy markets so aggressively in the first place. That rationale, specifically stated by successive administrations, was that government should only intervene in markets where there was an explicit market failure that it would be able to correct.10 But typically the market failure in energy is never unambiguously stated. Sometimes it is said that the failure is due to OPEC. OPEC has indeed exercised market power at times, but it has never been demonstrated that US policy has ever corrected that failure; market forces, moreover, have substantially limited OPEC’s ability to control the price of oil. Alternatively, energy market failure is said to be the result of the market’s failure to realise certain ‘facts’, such as dwindling reserves of oil and gas, which policy-makers want to address. Energy companies and capital markets show an apparent unwillingness to invest in new technologies that are ‘going to be needed’ after fossil fuels are no longer available – passing up the prospect of great (future) profits. But in general, policy-makers are the ones who have failed to interpret the future correctly, not market participants. Indeed, no 9 10

Grossman, U.S. Energy Policy. Ibid.

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event labelled an ‘energy crisis’ in the US has ever been solved by policy; again, all have been resolved (albeit sometimes painfully) by market forces. Policy-makers have identified one type of actual market failure related to energy: externalities. Pollution imposed by energy consumption led to the passage of the Clean Air Act of 1970 and its 1990 amendments. The legislation led to noticeable improvement in US air quality and created a successful trading market in sulphur dioxide emissions permits. Carbon dioxide (CO2), which is emitted by all combustible fuels and which poses a threat to the world’s climate, will likely remain an externality problem for the foreseeable future. But mandating certain energy technologies such as wind and solar energy will not reduce CO2 emissions by nearly as much people think. Intermittency of the wind and sun means that typically fossil fuels need to be burned for back-up. And mandates may make matters worse; the 2007 ethanol mandate, for example, thought initially to be a way to reduce emissions, may actually increase them. Even the most enduring US energy policies have often required some rationalisation other than energy consumption and production. For example, Corporate Average Fuel Economy (CAFE) standards, first enshrined into law with the passage in 1975 of the Energy Policy and Conservation Act, continue to be the way regulators pursue greater fuel economy. CAFE standards have been criticised because fuel savings would likely have been greater and at a lower social cost if instead of CAFE there had been a significant increase in taxes on petrol.11 Petrol tax proposals have been unacceptable politically, however, and CAFE standards today are positioned as a matter of environmental policy more than one of energy policy. Does the failure to date of US energy policy mean that the best energy policy is no policy? It seems possible that effective policy could be achieved if it were to emphasise more modest goals.12 First, the narrative of dangerous dependency with the illusory goal of energy independence must be abandoned, along with commercialisation efforts intended to achieve it. The government should focus on energy infrastructure, the electric grid and the thousands of miles of pipelines that are government’s responsibility; institutions, the regulatory regime for energy production and consumption; research and development programmes, with assurance of continuity of promising ideas; and information gathering and dissemination. In all of these areas, government has a major role to play. Too bad policy-makers are often distracted by a belief that a magic bullet will be found that will solve the nation’s energy difficulties for all time.

11

A. N. Kliet, ‘Impacts of long-range increases in the fuel economy (CAFE) standards’, Economic Inquiry 42 (2004), 279–94. 12 Grossman, U.S. Energy Policy.

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APPLYING INNOVATION POLICY TO THE US ENERGY/CLIMATE CHALLENGE William B. Bonvillian1

The policy concept in the United States to price carbon in order to avoid the approaching climate shift came from the toolkit of its dominant economic theory: neoclassical economics.2 Neoclassical doctrine is organised around the concept of maximising allocation efficiency, where pricing signals – from interest rates, currency supply, monetary policy, taxes and pricing mechanisms – are the preferred tools. Given this centrality of allocation efficiency, markets are all important, and market distortions and interventions are to be avoided whenever possible. On the other hand, market distortions are admittedly pervasive, and much of neoclassical theory deals with correcting market failures through such means as providing public goods, offsetting externalities, upholding information transparency, promoting competition and encouraging new entrants despite economies of scale. Neoclassical economics has used these constructs of market failure and offsetting externalities to pursue climate policy. Economic actors are assumed to pursue their rational self-interest;3 this means that their economic activities can be measured. The field, therefore, can accordingly be measurement-based. Carbon prices – including the pricing approach proposed in the US of capping total carbon emissions and allowing trading for a declining base of emissions 1

2

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William B. Bonvillian is Director of the Massachusetts Institute of Technology’s Washington Office and teaches innovation policy on the adjunct faculty of Georgetown University and Johns Hopkins School of Advanced International Studies. He co-authored (with Charles Weiss) the books Technological Innovation for Legacy Sectors (Oxford University Press, 2015) and Structuring an Energy Technology Revolution (MIT Press, 2009), and has written numerous articles on energy and innovation policy (see www.bonvillian.org). Discussed in R. D. Atkinson and D. Hackler, ‘Economic doctrines and approaches to climate change policy’, Information and Innovation Technology Foundation (2010), available at www. itif.org/files/2010-econ-climate-change.pdf A growing behavioural economics literature recognises some of the issues in this assumption. See, for example, J. Fox, ‘From “economic man” to behavioral economics’, Harvard Business Review (May 2015), 75–85.

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permits (‘cap and trade’) – can fit within this construct. But if a factor cannot be measured and analysed within a manageable number of variables, it is exogenous to neoclassical economics: outside the measurable box and so outside the system. Complex social systems, for example, fall outside its reach. Similarly, neoclassical economics has had great difficulty in addressing innovation systems, which are, of course, highly complex, with multitudes of actors and therefore variables that are not widely understood or necessarily measurable. Cap and trade, because it fits squarely within the neoclassical constructs of allocative efficiency, market failure and offsetting externalities, was a solution set to climate change imbedded in neoclassical economics. Innovation-oriented policies for climate, because of their too-often unmeasurable variables, were not well understood in the neoclassical context – they are exogenous. The neoclassical toolkit has made major contributions in recent decades to environmental progress in the US. The accomplishments include, most notably, the acid rain provisions of the Clean Air Act Amendments of 19904 where a cap-and-trade system efficiently controlled sulphur dioxide power plant emissions. Other examples include a trading system under the Montreal Protocol5 for chlorofluorocarbons (CFCs) to control ozone layer depletion and nitrogen oxides trading to limit US east coast smog. These trading systems helped emitters find and adopt flexible, low-cost compliance strategies; they also encouraged prompt deployment of technological solutions. In all these cases, however, the needed technology innovations were readily at hand. Progress on climate change, however, requires dramatic innovation advances, particularly in energy.6 While we can now see the outlines of the long series of technology pathways that will be required, most of these technologies require significant additional advance before they will be ready for deployment at scale. For example, we still don’t know the optimal technology solutions required for a transport transformation – these may involve evolving electric, hybrid or biofuel vehicles, or a combination of all three. Each of these technology paths requires significant technology progress, from dramatic battery or fuel cell improvements to new biofuels; each must also go through dramatic cost-reduction improvements and each requires major new supporting infrastructure. Even where a technology pathway has appeared relatively clear, such as with carbon capture and sequestration for the multitude of coal-fired power plants, there are many years of well-monitored demonstrations at scale, so optimal operating practices and efficiencies can be thoroughly understood, plus major cost reductions required, before the deployment box can be checked.7 4

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The Clean Air Act Amendments of 1990, 104 Stat. 2468, P.L. 101–549, available at www.wilderness.net/NWPS/documents/publiclaws/PDF/101-549.pdf United Nations Environment Programme, Ozone Secretariat, The Montreal Protocol, text as amended available at http://ozone.unep.org/new_site/en/Treaties/treaties_decisions-hb.php?sec_ id=5; description available at http://ozone.unep.org/new_site/en/montreal_protocol.php This discussion draws on C. Weiss and W. B. Bonvillian, Structuring an Energy Technology Revolution (MIT Press, 2009); W. B. Bonvillian, ‘Time for Plan B for climate’, Issues in Science and Technology 27(2) (2011), 55–6. MIT, ‘The future of coal’, MITEI Report (2007), available at http://web.mit.edu/coal

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The complexity of the technology development challenge, including the scale of worldwide deployment, is profound, far more complicated than acid rain or CFC controls that proved so adaptable to emissions trading regimes understood by neoclassical economics. While the technology development challenge for climate may not be the most difficult we have faced, the technology implementation task is daunting. It involves transforming a major world economic sector fundamental to basic human needs, equivalent to at least 10 per cent of the world economy, with at least $15 trillion in imbedded infrastructure and investment, demanding numerous but complementary technology pathways, to be implemented over a multi-decade period. The US has succeeded in remarkable single-thrust technology projects achievable within a decade – the Apollo or Manhattan projects are touchstones – but has never tried anything as complex as an energy technology transformation. The sheer complexity of this technology task has led to dissonance between underlying economic ideologies. The neoclassical economic focus on allocation efficiency has been running for years into an innovation brick wall for climate because the technological solutions are not readily at hand, as they were with earlier environmental problems like acid rain. This technology challenge has presented industries faced with carbon prices with what many have viewed as a ‘mission impossible’, multiplying their political resistance.8 Neoclassical economics, like classical economics before it, has had a great deal of trouble developing a theory of economic growth. Robert Solow won the Nobel Prize in 1987 for explaining to his neoclassical colleagues that well over half of economic growth was tied to technological and related innovation.9 But he had trouble fitting his breakthrough theory into the neoclassical framework, concluding it was exogenous to neoclassical economics – a complex system that was outside the neoclassical box. While economists led by Paul Romer,10 Richard Nelson,11 Robert Lucas12 and others have subsequently worked to develop the concepts to wrestle technological innovation into the neoclassical box – to make it endogenous – this ‘new growth theory’13 is still an ongoing project because neoclassical economics has had such trouble coping with complex systems. It continues to try to treat growth as arising largely through allocative efficiency.

8

Of course, technology readiness is not the only cause of industry resistance. See, for example, N. Oreskes and E. M. Conway, Merchants of Doubt (Bloomsbury Press, 2009). 9 R. M. Solow, Growth Theory, An Exposition, 2nd edn (Oxford University Press, 2000), pp. ix–xxvi (Nobel Prize Lecture, 8 December 1987). 10 P. Romer, ‘Endogenous technological change’, Journal of Political Economy 98(5) (1990), 72–102. 11 R. R. Nelson and N. Rosenberg, ‘Technical innovation and national systems’, in R. R. Nelson (ed.), National Innovation Systems: A Comparative Analysis (Oxford University Press, 1993), pp. 3–21. 12 R. E. Lucas, Jr, ‘On the mechanics of economic development’, Journal of Monetary Economics 22(1) (1988), 3–42. 13 Solow summarises some of the issues in new growth theory in Growth Theory, An Exposition.

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Climate change, despite the neoclassical approach, is not only a problem of market allocation but a profound challenge to innovation systems, so is a symptom of the same problem. Because the US political system in 2010 spit out and rejected the neoclassical economics approach – a price on carbon through a cap-and-trade scheme14 imposed economy-wide – it may be time to look more systematically at innovation policy in the context of the climate technology challenge. The climate issue has now exposed the policy battle lines between economic doctrinal ideologies – neoclassical economic policy versus innovation policy. It is not that neoclassical economic tools will not be needed, but rather that innovation policy may be a prerequisite to applying them. US policy-makers have assumed for fifteen years that putting a price on carbon would be the strategy for addressing climate change. Remarkably, they have never assembled a systematic back-up plan to carbon pricing. Innovation policy offers such an approach, and we are starting to see its elements. On the ‘front-end’ of the US energy innovation system new R&D institutions have been formed within the Department of Energy (DOE) to better translate research into actual technology advance, including: • Energy Frontier Research Centers (EFRCs)15 provide $3 million to $5 million a year to competitively selected university and laboratory teams working on basic research problems, tied to breakthrough advances in energy technologies. Over thirty are now operating. • Energy innovation ‘Hubs’16 in solar, advanced nuclear, batteries, critical materials and buildings. Whereas EFRCs are searching for new energy opportunities in the basic research space, the Hubs work to push emerging energy advances at a larger scale towards commercialisation. Reflecting their scaling role, the five Hubs each receive around $20 million in annual funding. • The Advanced Research Projects Agency-Energy (ARPA-E),17 funded at around $300 million a year, is modelled on DARPA. It has adopted

14

The American Clean Energy and Security Act of 2009, 111th Cong., 1st Sess., H.R. 2454 (Waxman-Markey Bill) passed the House of Representatives on 26 June 2009 on a 219–212 vote. The Senate version of the legislation, however, did not pass. See the American Power Act of 2010 (the Kerry-Lieberman Bill), which became S. 1733, 111th Cong., 2nd Sess., released 12 May 2010. Summarised at World Resources Institute, Summary of the American Power Act, June 2010, available at http://pdf.wri.org/wri_summary_american_power_act_2010-06-07.pdf. This legislation in turn descended from three earlier versions of the Climate Stewardship Act introduced in 2003 (S. 139), 2005 (S. 1151) and 2007 (S. 280) by Senators Lieberman and McCain. 15 Department of Energy (hereafter DOE), Office of Science, ‘Energy Frontier Research Centers’, available at http://science.energy.gov/bes/efrc 16 DOE, ‘Energy Innovation Hubs’, available at http://energy.gov/science-innovation/innovation/ hubs; and http://energy.gov/articles/what-are-energy-innovation-hubs 17 W. B. Bonvillian and R. Van Atta, ‘ARPA-E and DARPA, applying the DARPA model to energy innovation’, Journal of Technology Transfer 36(5) (2011), 469–513.

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DARPA’s ‘right-left’ model of seeking particular technology advances on the right side of the innovation pipeline and then looking on the left side for revolutionary breakthroughs to get there, and DARPA’s ‘hybrid’ model of building research groups around smaller companies and university researchers to ease technology transition. Its projects aim at accelerating innovation, moving from ideas to proofof-concept or prototype in three to five years. It is working in what it calls the ‘white space’ of technology opportunities, higher-risk projects that could be transformational in which little work has previously been undertaken. • The SunShot Initiative18 in the DOE’s Energy Efficiency and Renewable Energy office (EERE) with around $70 to $100 million in annual R&D to promote technology and process advances to make solar energy cost-competitive with fossil fuels by 2020. • The Clean Energy Manufacturing Initiative19 in EERE aims at applied technology advances to drive down production costs for new energy technologies to make them competitive, and to improve overall industrial efficiency. The programme has set up three advanced manufacturing institutes, industry-university collaborations as testbeds for power electronics, advanced composites and ‘smart’ manufacturing, with around $70 million in federal funds each over five years and cost-shared by industry and states. On the back end of the US energy innovation system, scaffolding support is needed to bring new technologies towards implementation and deployment. The programmes and incentives include: • tax incentives for new energy technologies20 • DOE financing for energy technologies through loan guarantees21 • government procurement, particularly through the Department of Defense (DOD) when its missions require energy advances22

18

DOE, Office of Energy Efficiency and Renewable Energy, ‘SunShot Initiative’, available at http:// energy.gov/eere/sunshot/sunshot-initiative 19 DOE, Office of Energy Efficiency and Renewable Energy, ‘Clean Energy Manufacturing Initiative’, available at http://energy.gov/eere/cemi/clean-energy-manufacturing-initiative 20 Congressional Research Service, ‘Federal renewable energy R&D funding history: a comparison with funding for nuclear energy, fossil energy and efficiency’ R&D (7 March 2012), available at www.fas.org/sgp/crs/misc/RS22858.pdf. See also MIT Energy Initiative, ‘The future of solar energy’ (May 2015), 209–29 (efficiency issues with current US tax subsidy for solar), available at http://mitei.mit.edu/system/files/MIT%20Future%20of%20Solar%20Energy%20Study_compressed.pdf 21 DOE, Loan Programs Office, available at http://energy.gov/lpo/loan-programs-office 22 See, generally, on the DOD’s role, J. Alic, D. Sarewitz, C. Weiss and W. Bonvillian, ‘A new strategy for energy innovation’, Nature 466 (2010), 316–17; W. B. Bonvillian, ‘Forum: DOD’s role in energy innovation’, Issues in Science and Technology 31(2) (2015), 10–14.

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• existing federal regulatory authority, for reduced emissions and energy consumption from power plants,23 automobiles and trucks,24 and appliances.25 • regulatory authority and incentives at the state level. States and regions in the US can amount to nation-sized economies and some have taken leadership in pressing for new-energy technologies, particularly California26 and the north-east. Some three-fifths of the states, for example, have renewable portfolio standards requiring power producers to provide a set minimum share of their electricity from renewable resources.27 None of these programmes is operating at the scale of investment and support required for an energy transformation28 and both front and back ends of the innovation system remain subject to the ups and downs of the political process. However, the outline of a much stronger energy innovation system is starting to unfold. Cap and trade is strong on ‘demand pull’ but short on ‘technology push’. Both will likely be needed, but they do not have to operate in parallel; progress on the latter may be a requirement for implementation of the former because it is an enabler. An amalgam of policies in the US that could comprise a back-up plan on climate is emerging. The plan includes technology push mechanisms that have been strengthened in the past decade, with a focus on both front and back ends of the innovation system. The plan relies for needed demand pull on current regulatory tools and incentives that are less economically efficient than cap and

23

Environmental Protection Agency, ‘Carbon pollution standards’, available at www2.epa.gov/ carbon-pollution-standards/what-epa-doing 24 Environmental Protection Agency, ‘EPA and NHTSA set standards to reduce greenhouse gases and improve fuel economy for model years 2017–2025 cars and light trucks’, available at www.epa.gov/otaq/climate/documents/420f12051.pdf 25 DOE, ‘Energy efficiency and renewable energy, appliance and equipment standards program’, available at http://energy.gov/eere/buildings/appliance-and-equipment-standards-program 26 See, for example, ‘CA energy efficiency strategic plan, January 2011 update’, available at www. energy.ca.gov/ab758/documents/CAEnergyEfficiencyStrategicPlan_Jan2011.pdf 27 DOE, Energy Information Administration, ‘Most states have renewable portfolio standards’ (2012), available at www.eia.gov/todayinenergy/detail.cfm?id=4850#; National Renewable Energy Laboratory, State and Local Governments, ‘Renewable portfolio standards’ (2013), available at www.nrel.gov/tech_deployment/state_local_governments/basics_portfolio_standards.html 28 See, for example, G. F. Nemet and D. M. Kammen. ‘U.S. energy R&D: declining investment, increasing need, and the feasibility of expansion’, Energy Policy 35 (2007), 746–55; Breakthrough Institute, Brookings Institution, World Resources Institute, ‘Beyond boom and bust’, Report (12 April 2012), 12–21, available at http://thebreakthrough.org/blog/Beyond_Boom_ and_Bust.pdf; International Energy Agency, ‘Energy technology perspectives 2008: scenarios and strategies to 2050’ (6 June 2008), available at http://www.iea.org/media/etp/etp2008.pdf

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trade but will allow for interim progress. In addition, more innovation system elements will need to evolve; for example, there is a significant gap in the system for scale-up financing for production of new energy technologies.29 This evolving innovation system, however, appears more palatable politically because it applies a series of more manageable policy bricks that can be put in place by many different actors, unlike the far-reaching, economy-wide single economic construct of cap and trade.

29

E. Reynolds, H. Semel and J. Lawrence, ‘Learning by building’, in R. Locke and R. Wellhausen, Production in the Innovation Economy (MIT Press, 2014); R. Lester and D. Hart, Unlocking Energy Innovation (MIT Press, 2012).

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NATIONAL SCIENTIFIC LABORATORIES AS AN ENERGY POLICY VEHICLE: THE UNITED STATES’ EXPERIENCE William F. Fox1

INTRODUCTION Until World War II, the United States government (the ‘federal’ government) engaged in very little scientific or technical research. The United States Navy conducted some research on naval ordnance and armaments, the United States Army did some experimentation with the technology of flight and aerodynamics. But until 1941, the government was content to leave virtually all scientific and technical research to the vagaries of the private sector. Shortly after the war began, the Princeton University scientist Albert Einstein sent a personal letter to President Franklin Roosevelt urging the government to launch a massive programme on atomic fission and weaponry in the fear that Nazi Germany might win the race for the atom bomb. Roosevelt moved quickly to establish the Manhattan Project which, just a few years later, produced plutonium and uranium bombs that were dropped on Hiroshima and Nagasaki, Japan. The two bombs brought the war to an end and created a strong interest, both in the United States and abroad, to develop atomic energy for peaceful uses. One of the strongest advocates for peaceful uses of nuclear energy was then-General and later President Dwight Eisenhower, who gave a major speech to the United Nations shortly after being elected in 1953 in which he described the ‘Atoms for Peace’ plan. In the early 1950s, the government began funding

1

Professor William F. Fox has recently retired from more than forty-two years of full-time teaching and practice. His most recent academic affiliation was the School of Law, Pennsylvania State University. He continues in part-time teaching at the School of Transnational Law, Peking University (Shenzhen campus) and is an Honorary Fellow of the Centre for Energy, Petroleum and Mining Law and Policy at the University of Dundee.

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non-military uses for nuclear energy that has blossomed in the twenty-first century in large-scale research on a host of energy and environmental issues through a network of national scientific laboratories that are engaged in some of the most profound and dramatic energy research in the world. THE NATIONAL SCIENTIFIC LABORATORY SYSTEM Under the supervision of the federal government’s Department of Energy (DOE), the United States has established seventeen laboratories virtually all of which have a strong commitment to energy and environmental research.2 The DOE maintains three separate groups of laboratories. There are ten laboratories operating under the DOE’s Office of Science3 and a further seven under the aegis of the DOE but not within the Office of Science.4 The collective research programme for the laboratories is vast and comprehensive. Scientists affiliated with the National Laboratory System have been awarded eighty Nobel prizes. Apart from the laboratories themselves, the Office of Science, through grants and loan guarantees to private-sector (principally university-affiliated) groups, funds approximately 80 per cent of basic scientific research in the United States. The diffuse and varied activities and programmes of the laboratories are beyond the scope of this chapter, but a good snapshot of the work of all the laboratories can be gleaned from a close look at just one – the National Renewable Energy Laboratory (NREL) in Golden, Colorado. THE NATIONAL RENEWABLE ENERGY LABORATORY The NREL is a relative newcomer to the system of national scientific laboratories.5 It was created by Congress in 2002 and is devoted solely to renewable energy and energy efficiency and conservation issues. Its current

2

3

4

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Most of the basic information presented in this chapter is taken from the DOE’s website at www. energy.gov/science-innovation/national-labs While not within the scope of this chapter, each of the laboratories engages in research directly or indirectly related to energy policy. The parenthetical next to each laboratory briefly describes some of that laboratory’s energy research. In alphabetical order, they are: the Ames Laboratory (condensed matter physics), the Argonne National Laboratory (particle physics and nuclear physics), the Brookhaven National Laboratory (climate change science), the Fermi National Accelerator Laboratory (accelerator physics), the Lawrence Berkeley National Laboratory (environmental subsurface science), the Oak Ridge National Laboratory (plasma and fusion research), the Pacific Northwest National Laboratory (applied nuclear science), the Princeton Plasma Physics Laboratory (plasma and fusion), the SLAC National Accelerator Laboratory (condensed matter) and the Thomas Jefferson National Accelerator Facility (nuclear). The Idaho National Laboratory (integration of renewable energy sources), the National Energy Technology Laboratory (coal, oil and natural gas), the National Renewable Energy Laboratory (see the remainder of this chapter), the Savannah River National Laboratory (nuclear and hydrogen production and storage), the Lawrence Livermore National Laboratory (physics and materials), the Los Alamos National Laboratory (energy storage, fuel cells and photovoltaics) and the Sandia National Laboratory (nuclear, transportation and energy security). Virtually all of the information in this chapter has been taken directly from the NREL’s website at www.nrel.gov

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annual budget is $380 million and it has a permanent staff of more than 1,700 employees and an additional complement of more than 600 visiting researchers and interns. NERL conducts research and analysis in a large number of areas including biomass, geothermal, energy efficiency and conservation (concentrating mainly on building efficiency and conservation), hydrogen and fuel cells, water power, transportation and, of course, wind and solar power. Within the NREL exist three remarkable subsections: the National Bioenergy Center, the National Center for Photovoltaics and the National Wind Technology Center. While most of the other scientific laboratories are administered under the DOE’s Office of Science, the NREL is administered by a separate DOE entity: the Office of Energy Efficiency and Renewable Energy. By way of carrying out its mission, the NREL is organised around four broad concepts with a number of specific areas within each concept: 1. Energy Efficiency • residential buildings • commercial buildings • personal and commercial vehicles 2. Renewable Energy • solar • wind • biomass • hydrogen • geothermal • water 3. Systems Integration • grid infrastructure • distributed energy interconnection • battery and thermal storage • transportation 4. Market Focus • private industry • federal agencies • state and local government • international THE NREL AND THE PRIVATE SECTOR Programmes developed by the US government almost always require a very large role for the private sector. Readers from outside the United States are often puzzled when they learn that the United States now has a number of prisons and jails run by private companies. It is no different in energy policy. The national scientific laboratories are ostensibly within the orbit of the federal government but the day-to-day management of the laboratories is always in the hands of the private sector. For more than forty years, the University of

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California managed one of the pre-eminent laboratories in Los Alamos, New Mexico. After uncovering a number of instances of mismanagement by the University, the DOE shifted management of the laboratory to a newly formed company –Los Alamos National Security LLC, which is a consortium made up of the University of California, Bechtel National, Babcock and Wilcox, and the URS Corporation. The NREL is no exception; it is managed by a limited liability company called Alliance for Sustainable Energy, which is a joint venture between Battelle Corporation and the MRI Global company. While the NREL conducts and sponsors a certain amount of basic scientific research, the bulk of its work is directed, once again, towards the private sector by way of technology transfer. There are essentially three main conduits for technology transfer: commercialisation programmes that include the following: the Clean Energy Alliance (working with US business incubators to foster clean-energy development); the Commercialisation Assistance Programme (assisting emerging companies in overcoming technical barriers to progress and innovation); the Energy Innovation Portal (providing one-stop shopping for clean-energy technologies that are available for licensing from the DOE); the Industry Growth Forum (a vehicle that permits clean-energy entrepreneurs to present their ideas to an expert panel of energy executives and investors); and the Innovation and Entrepreneurship Center which develops links between innovators and the financial community. The NREL also engages in Technology Partnership Agreements that provide scientific and technical expertise and advice to private-sector companies with the companies themselves expected to provide all the financial resources for the enterprise. These agreements are essentially short-term joint ventures between the NREL and private-sector entities. The NREL has a full-blown system of licensing agreements. These permit a private-sector entity to license a particular innovation or technology initially developed by the NREL to pursue commercial uses for the technology. The agreements normally take the form of either exclusive or non-exclusive patent licensing agreements or a research license agreement.6 One of the recent initiatives at the NREL is the Energy Systems Integration Facility, a component of the NREL located on the NREL campus and utilising both government and private-sector contributions. Working directly with companies such as General Motors, Solelectria and Toyota, the Facility is currently working on such diverse projects as grid integration of advanced solar inverters; operating microgrids that produce power when the main grid is down; and improving automotive fuel cells and battery technologies. THE NREL’S INTERNATIONAL PROGRAMMES The NREL has a vigorous international outreach component. It engages in both bilateral and multilateral international partnerships as well as developing assessment and measurement tools that are shared with the international 6

See www.nrel.gov/about/mission-programs.html

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energy community. For example, it has a bilateral agreement with China that includes policy analysis, technical exchanges on grid integration and standards, testing and certification programmes. A separate initiative has grown out of a US-China agreement on biofuel chemical conversion. The NREL has developed a series of high-resolution maps and data sets of solar and wind energy for a number of developing countries in cooperation with the United Nations Environmental Program (UNEP). In an attempt to promote international energy technology transparency, the NREL has created ‘Open EI’ – a programme to encourage data- and research-sharing for, among many other things, energy access and energy poverty. CONCLUSION Elsewhere in the world, the bulk of energy research and development appears to be in the hands of the various national governments. The United States has taken an entirely different path with its scientific laboratories, whose central mission is to initiate important research on renewable energy technology but to get that data as quickly as possible into the hands of the US private business and educational sectors. Indeed, a great deal of the original research grows out of express partnerships between the laboratories and individual companies. There is an ongoing debate in the United States as to whether this is the best path towards energy innovation because it relies on the individual laboratories to make decisions on which research and development paths to pursue. Some commentators, remembering how Bill Gates and his partners developed the basic computer operating system (DOS) in a garage in Albuquerque, New Mexico, believe that the better approach to energy innovation is to let a million ideas bloom in garages all over the United States, not merely within the national scientific laboratories. While it must be conceded that the national scientific laboratory may not be a perfect vehicle for promoting green energy technologies, every reader should nonetheless agree that it is an interesting approach to the problem.

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DELIVERING ENERGY POLICY IN THE US: THE ROLE OF TAXES Roberta F. Mann1

In recent years, national energy policy has largely been financed through the tax system. Unique among developed nations, the United States uses an almost exclusively incentive-based energy policy. At both the national and subnational levels, US governments provide preferential tax treatment to energy developers and users. Governments can influence energy choices by imposing a penalty on ‘bad’ choices, by directly sponsoring ‘good’ choices via government grants or payments or indirectly by reducing the tax impact of ‘good’ choices. This chapter will first explain how the United States uses tax incentives to mould energy policy and will then examine the evolution of US energy policy through the tax system from the earliest days of oil and gas exploration to today’s focus on renewable energy, ending with consideration of how the United States might use tax policy to deal with the issue of climate change. DEFINING TAX EXPENDITURES To understand how the United States uses tax policy to deliver energy policy, one must understand the concept of ‘tax expenditures’. Energy tax expenditures are tax provisions that reduce the cost of taxes for taxpayers who produce, consume or conserve energy in specific ways sanctioned by the Internal Revenue Code (IRC). Congress requires annual publication of the

1

Roberta Mann is the Mr & Mrs L. L. Stewart Professor of Business Law at the University of Oregon School of Law, where she teaches Federal Income Tax, Business Tax and Tax Policy. Before teaching, she served on the staff of the Joint Committee on Taxation of the United States Congress and at the Office of Chief Counsel, Internal Revenue Service. Her scholarship focuses on the interaction between tax policy and the environment.

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‘tax expenditure budget’, which tracks transfers of funds through the tax system. Congress needs to track tax expenditures because benefits received by a taxpayer through a special departure from a ‘normal’ income tax system are economically equivalent to a direct transfer of government funds to that taxpayer.2 There are four ways that an industry or activity can receive preferential tax treatment: • The income from the activity can be excluded from gross income. • The income from the activity can be taxed at a lower rate than ordinary income. • Expenses from the activity can reduce income more, or more quickly, than expenses from other activities. • Expenses from the activity may be eligible for a tax credit – that is, a direct reduction in tax liability. The tax expenditure budget determines the revenue loss associated with each tax expenditure and lists it under the category where it would fall if it were part of the government’s spending budget. Energy tax expenditures include the production tax credit (PTC) for wind energy,3 expensing of intangible drilling costs (IDCs)4 and the tax credit for investment in clean coal facilities.5 The United States uses tax expenditures to deliver energy policy for several reasons. First, from a political standpoint, tax expenditures are tax cuts, and politicians love to deliver tax cuts. Second, the tax legislative process is less burdensome than the budget legislative process. Tax legislation only passes through two Congressional committees, while budget legislation must pass through at least four Congressional committees. Finally, tax expenditures are not transparent, other than to their beneficiaries. At least until the recent past, the rent seeking for tax expenditures has not been as competitive as the rent seeking under the federal budget.6 THE PROBLEM WITH TAX EXPENDITURES To obtain the benefit of a tax expenditure, a taxpayer must engage in the specified activity. If the taxpayer engaged in the activity regardless of the availability of the tax expenditure, then the taxpayer would receive a windfall and the government would have wasted its money. Tax expenditures are therefore inefficient. The government defines the specified activity, for example, developing wind energy. Thus, the government is selecting the

2

3 4 5 6

Congressional Budget and Impoundment Control Act of 1974, Pub. L. No. 93-344, 88 Stat. 297 (1974); see, for example, Joint Committee on Taxation, ‘Estimates of federal tax expenditures for fiscal years 2006–2010’, JCS-2-06 (2006). IRC Sec. 45(a) and Sec. 45(c)(1)(A) (2012). IRC Sec. 263(c) (2012). IRC Sec. 48A and Sec. 48B (2012). E. A. Zelinsky, ‘Do tax expenditures create framing effects? Volunteer firefighters, property tax exemptions, and the paradox of tax expenditure analysis’, Virginia Tax Review 24 (2005), 797, 826.

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technology and thereby ‘picking winners’. Whether picking winners is a problem depends on the goal the government is trying to achieve. If the goal is to reduce carbon emissions, then it would be more efficient to simply tax carbon emissions, applying a penalty rather than an incentive. In reacting to the penalty, the market would pick the most efficient technology, be it wind energy or conservation. Moreover, the particular design of the tax incentive can also lead to inefficiencies. In the case of the investment tax credit (ITC) or PTC for renewable energy, because the credits are not directly transferable, a developer without sufficient tax liability to use the credits must enter into complex transactions with ‘tax equity investors’ who seek credits to offset tax liability.7 These transactions come with significant transaction costs and may ultimately result in imposing high costs of capital on energy developers. HISTORY OF US ENERGY TAX POLICY: OIL AND GAS The United States first used energy tax policy to support the nascent oil and gas industry in the early part of the twentieth century. The two original energy tax expenditures were percentage depletion and the deduction for intangible drilling costs (IDCs). Percentage depletion allows the oil producer to deduct a fixed percentage of the gross value of annual production. Unlike cost depletion, in which total tax benefits are limited to the taxpayer’s investment in the property, cumulative percentage-depletion deductions can exceed the original investment costs. IDCs may be deducted all at once, although without the special tax provision those type of expenses would have to be recovered over the life of the investment. IDCs typically include labour, fuel, hauling, power, materials, supplies, tool rental, repairs of drilling equipment and other costs incidental to and necessary for drilling and equipping productive wells. In addition, the costs associated with a nonproductive well, or ‘dry hole’, may also be deducted as incurred. The economic impact of these tax incentives on the oil and gas industry have been significant. A 1955 study by the Treasury Department found that percentage depletion reduced the taxable gross income of the petroleum industry as a whole by approximately 25.3 per cent.8 One scholar concluded that the IDC deduction alone reduced the marginal tax rate of oil and gas companies by half.9 Oil and gas companies have long enjoyed lower effective tax rates than most other industries.10

7

See Revenue Procedures 2007–65, 2007–2 C.B. 967; see also Revenue Procedure 2001–28, C.B. 38 (explaining the partnership flip structure used with PTCs and the sale-leaseback structure used with ITCs). 8 US Treasury Department, Statistics of corporation mineral depletion deductions and related allowances, 1950, 1951, 1952, 29 (1955), 37–40, available via the online library of the US Treasury Department at www.treasury.gov/Pages/default.aspx 9 M. L. Hymel, ‘Environmental tax policy in the United States: a “bit” of history’, Arizona Journal of Environmental Law and Policy 3 (2013), 157, 173. 10 US General Accounting Office, ‘Tax policy: additional petroleum production tax incentives are of questionable merit’, GAO/GGD-90-75 (1990), 42, available at www.gao.gov/assets/150/149358.pdf

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THE SHIFT TO RENEWABLE ENERGY The Energy Policy Act of 200511 signalled a shift in the direction of US energy policy. While still supporting fossil fuels with percentage depletion and other longstanding tax incentives, Congress created a panoply of incentives for renewable energy and conservation. Congress targeted electricity production from renewable energy, including wind, solar, biomass, geothermal and municipal solid waste. It also targeted homeowners with tax credits for purchasing energy-efficient windows and heat pumps, and car buyers with incentives for purchasing hybrid and electric vehicles. Table 14.1 illustrates the shift in tax expenditures from fossil fuels to renewable energy.12 Table 14.1 Tax expenditures for fossil fuels, renewables and efficiency: 2009 dollars Billions of dollars 1977

1981

1985

1989

1993

1997

2001

2005

2007

2009

6.16

10.58

6.32

0.64

1.55

2.73

3.16

2.76

7.37

2.60

Renewables

0.73

1.16

+

+

0.13

0.12

0.33

1.66

9.00

Efficiency

1.54

0.57

+

+

+

0.42

0.50

Fossil Fuels

Source: CRS calculations using JCT and OMB tax expenditure estimates. Notes: Tax expenditures beyond 2009 are estimates and do not reflect legislation enacted after September 30, 2009. In cells containing “+’’ estimated tax expenditures were less than $50 million. Values are adjusted to 2009 dollars using the OMB’s GDP price index.

The PTC for wind, originally enacted in 1992, was enhanced and became one of the most significant energy tax incentives. The PTC is calculated by multiplying the credit amount by the amount of electricity generated. Therefore, the more energy generated by the qualifying technology, the larger the tax benefits. If the public policy goal is to increase the supply of renewable energy, the PTC is optimal because it provides continuing incentives to produce renewable energy. The PTC is paid each year during the credit period, generally ten years. Unfortunately, the wind PTC, unlike the oil and gas tax incentives, has always been temporary. Congress has extended the wind PTC eight times since 1992, and four of the extensions were retroactive. In each of those years with retroactive extensions, wind energy additions slowed significantly compared to the years when the PTC was in effect. The wind PTC expired again at the end of 2014.13 Figure 14.1 illustrates the impact of the wind PTC.14 11

H.R. 6, 109th Congress (1st Session 2005) (enacted as Energy Policy Act of 2005, Pub. L. No. 109-58). 12 M. F. Sherlock, ‘Energy tax policy: historical perspectives on and current status of energy tax expenditures’, Congressional Research Service, R41227 (2010), 29. 13 Tax Increase Prevention Act of 2014, H.R. 5771, 113th Congress Sec. 155 (2nd Session 2014). 14 US Government Accountability Office, ‘Wind energy: additional actions could help ensure effective use of federal financial support’, GAO-13-136 (2013), 8.

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Figure 14.1 Impact of the wind PTC

TAXES ON ENERGY While incentives dominate US energy tax policy, the United States does impose a few taxes on energy. Taxes imposed on energy generally go into designated funds. For example, coal extraction is subject to the black lung excise tax, which goes into the Black Lung Disability Trust Fund, the purpose of which is to compensate coal miners who have contracted black lung disease.15 Oil companies also pay an excise tax on oil produced in or imported to the United States, which goes into the Oil Spill Recovery Fund.16 Like many other countries, the United States imposes a gas tax, but unlike other countries, the revenues must go to the Highway Trust Fund for building roads and other transportation infrastructure. US tax on petrol is also dramatically lower than in other countries, currently $0.184 per gallon, in comparison to the UK, where it is $3.95 per gallon. The Highway Trust Fund is currently in danger of running out of money, and transportation safety is suffering; it seems unlikely, however, that Congress will raise the tax.17

15

RC Sec. 4121 and Sec. 9501 (2012). Oil Pollution Act of 1990, 33 USC Sec. 2701 et seq. (1990). 17 See J. Thorndike, ‘The gas tax doesn’t work because politicians broke it’, Forbes (24 October 2013), available at www.forbes.com/sites/taxanalysts/2013/10/24/the-gas-tax-doesnt-workbecause-politicians-broke-it 16

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CARBON TAXES IN THE UNITED STATES Scholars agree that a national carbon tax would be the most efficient and effective way of shaping energy policy to reduce greenhouse gas (GHG) emissions.18 Rather than the government picking winners by incentivising certain types of fuel, the market would select the most efficient alternatives. However, the political climate in the United States is not conducive to carbon pricing. The municipalities of San Francisco, California19 and Boulder, Colorado20 are the only places in the United States with a carbon tax or fee. California has implemented a carbon trading system,21 and several Northeastern states have a regional GHG trading system.22 CONCLUSION The United States takes a unique approach to energy policy by focusing almost entirely on tax incentives. This approach has provided some benefits and has increased the availability of renewable energy. However, this approach is probably inefficient and unworkable in the long run. It is unlikely to provide the GHG reductions necessary to slow climate change.

18

See, for example, R. F. Mann, ‘The case for the carbon tax: how to overcome politics and find our green destiny’, Environmental Law Reporter 39(2) (2009), 10118. 19 ‘S.F. Bay Area passes carbon tax’, Environmental Leader (22 May 2008), available at www. environmentalleader.com/2008/05/22/sf-bay-area-passes-carbon-tax 20 J. Sumner, L. Bird and H. Smith (2009), ‘Carbon taxes: a review of experience and policy design considerations’, National Renewable Energy Laboratory Technical Report, NREL/TP-6A247312, 14. 21 California Global Warming Solutions Act of 2006, Cal. Assembly Bill 32, Cal. Health and Safety Code, Div. 25.5, Sec. 38500 et seq. (2006). 22 See Regional Greenhouse Gas Initiative, available at www.rggi.org/rggi (the Regional Greenhouse Gas Initiative (RGGI) is a cooperative effort among nine Northeastern states to reduce GHG emissions).

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DELIVERING THE WIND: DECONSTRUCTING RENEWABLE ENERGY SUCCESS IN TEXAS Monty Humble1

Despite a well-earned reputation for antediluvian attitudes toward US federal environmental policies,2 Texas leads the United States in installed windgeneration capacity. Texas wind installations comprise almost one-fourth of total installed wind capacity in the United States,3 and would rank sixth in the world4 if, as Texans are fond of claiming, Texas were a sovereign nation.5 Four interacting policy choices largely explain the success of wind development in Texas: the decision in 1935 by investor-owned utilities in Texas to take action to avoid regulation by the Federal Power Commission; the 1999 deregulation of bulk power generation and retail electric service; the inclusion of renewable energy-generation projects to the economic development programme in 2001; and the 2005 direction from the Texas legislature to the Texas Public Utility Commission to facilitate the construction of high-voltage transmission lines to provide robust transmission connections to less populated, but wind resource

1

2

3

4 5

Monty Humble is an Adjunct Professor at the University of Texas School of Law, teaching courses in Renewable Energy Policy and Renewable Project Development. He practised law for thirtytwo years before founding his own renewable energy development company. The Texas Attorney General has brought eighteen lawsuits challenging federal environmental regulations during the Obama administration. See www.texastribune.org/2015/03/26/texas-vs-federalgovernment. Texas was recently ranked thirty-fourth among the fifty states in policy support for clean energy. See http://cleanedge.com/reports/2015-US-Clean-Tech-Leadership-Index US Department of Energy, Energy Efficiency and Renewable Energy, available at http://apps2. eere.energy.gov/wind/windexchange/wind_installed_capacity.asp See http://en.wikipedia.org/wiki/Wind_power_by_country Texas was a sovereign country from 1836 to 1845, when it became a part of the United States pursuant to a joint resolution of the United States Congress. See https://history.state.gov/milestones/1830-1860/texas-annexation

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rich, areas of the state. While not part of a single, unified approach intended to encourage the exploitation of wind resources, the consequence, whether intended or not, has been the rapid development of a thriving wind-generation industry. These four policy choices have combined with a tradition6 of robust support for landowner rights to own and develop energy resources on and under their land to foster development of wind resources without the more common policy mechanisms of direct subsidies, feed-in tariffs, carbon pricing or a strong renewable portfolio standard.7 The private utility companies in Texas chose to cut their interconnections to the rest of the United States on 26 August 1935, in response to the enactment of the Federal Power Act, in order to avoid becoming subject to the jurisdiction of the Federal Power Commission (now the Federal Energy Regulatory Commission).8 This decision, whatever its original motive,9 has allowed Texas more or less unfettered control over the portion of the electric system serving approximately 75 per cent of the state’s utility customers.10 This control has allowed the Texas legislature and Public Utility Commission to develop a series of policies related to high-voltage transmission that have not been possible, or have only come after substantial litigation in the balance of the United States.11 The anomalous status of the Texas electric grid might have remained a historical curiosity12 but for the decision by the Texas legislature to adopt deregulation of its electric markets in 1999.13 The deregulation legislation had five main features: a requirement that existing vertically integrated utilities separate their generation and retail customer units from their transmission and distribution units; an open-access approach to transmission interconnections 6

For example, Houston Texas Central Railroad Company v. W.A. East, 98 Tex. 146, 81 S.W. 279 (1904). 7 Texas actually has a renewable portfolio standard, however the goals in the standard were long ago made irrelevant by the rapid development of wind-generation capacity well in excess of the goal set for 2025. Texas Utility Code, Sec. 39.904. 8 West Texas Utilities Company v. Texas Electric Service Company 470 F. Supp. 798, 808 (N. D. Tex. 1979). 9 R. Cudahy, ‘The second Battle of the Alamo: the midnight connection’, Natural Resources and Environment 10(1) (1995), 56–61, 85–7, for a recounting of the story and subsequent struggles to maintain non-jurisdictional status by an incredulous Washington, DC-based lawyer. 10 The major portion of Texas is served by an electric grid operated by the Electric Reliability Council of Texas (ERCOT), a quasi-public entity that evolved from a voluntary series of interconnections among the utilities in Texas. Portions of the eastern, northern and far western parts of the state are served by utilities that are interconnected with the rest of the United States, thus subjecting them to the jurisdiction of the Federal Energy Regulatory Commission. 11 J. Tomich, ‘“Very real” tension between grid operators, state regulators on display in Ark. siting case’, Energywire (14 February 2014), available at www.eenews.net/stories/1059994595 (Arkansas administrative law judge ordered utility to build a transmission line through neighbouring state.); Illinois Commerce Commission v. Federal Energy Regulatory Commission (7th Cir. 2014). G. Maser, ‘It’s electric, but FERC’s cost–causation boogie-woogie fails to justify socialized costs for renewable transmission’, Georgetown Law Journal 100 (2012), 1829–54. 12 J. Fleisher, ‘ERCOT’s jurisdictional status: a legal history and contemporary appraisal’, Texas Journal of Oil, Gas and Energy Law 3(1) (2008), 5–21. 13 Chapter 39, Texas Utility Code.

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for generation units; wholesale and retail competition; a uniform transmission tariff underwritten by a charge to load for transmission; and an energy-only market structure that eliminated the competitive advantage for dispatchable generation. These elements interacted with a weak renewable portfolio standard and the state’s laissez-faire approach to land use regulation to produce an explosion of windgeneration development. Under Texas law, the only official approvals required for construction of a wind-generation project are an interconnection study, which is focused on potential harm to the transmission system, not on potential congestion or impact on other generation units, and registration of the wind project as a power generator. Furthermore, the paucity of federally owned land in the state virtually eliminates any need to obtain federal approval for a new wind-generation project.14 As a result, there are few tools for those opposed to development of a new wind-generation project to exploit in order to delay or halt a wind development.15 Furthermore, the initial wind projects in Texas were located in arid portions of the state that have traditionally offered limited opportunities for agriculture. The landowners were more than willing to tolerate wind turbines in exchange for royalty payments from the wind projects that in many cases produced annual income far in excess of the value of the land for any other use. The early years of the wind boom in Texas were also propelled by an increase in the price of natural gas, which indirectly sets the price of electricity in the deregulated Texas market.16 As natural gas prices climbed through 2008, reaching a peak of over $13/mcf, electricity prices in the real-time market approached $100/MWh. Coupled with the federal production tax credit of $20/MWh, wind generation was highly profitable. The state legislature added additional incentives for wind farm construction including exemptions from the 6.75 per cent state sales tax and property tax abatements that can provide benefits of up to 10 per cent of the cost of a wind project as a part of an economic development package enacted to counter the effects of the 2000–1 recession following the bursting of the internet stock bubble. Renewable energy generation at the time was barely beginning in Texas, so the impetus behind the legislation is not clear. It is not unreasonable to speculate 14

The absence of federal action eliminates the need for an environmental impact statement under the National Environmental Policy Act. Federal jurisdiction can come into play if waters of the United States are affected by the project, and the presence of endangered species, or impacts on migratory birds or eagles can also result in federal jurisdiction. Wind projects also require permits from the Federal Aviation Administration, which consults with the Department of Defense and the National Oceanic and Atmospheric Administration before issuing permits. 15 Texas courts have also been unsympathetic to challenges by surrounding landowners based upon aesthetic considerations. Rankin v. FPL Energy, LLC 266 SW3d 506 (Tex. App., 2008). 16 The system operator uses a security-constrained dispatch algorithm that dispatches the least-cost units that can operate without causing damage to the transmission system first. In practice, wind, solar and nuclear units are dispatched first; then, until recently, coal-fired units were dispatched before natural gas units. As a result, natural gas is the fuel used by the generation units that are the last to be dispatched, which establish the price for all electricity sold in the system in the realtime market for the time interval in question.

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that Texas-based Enron’s then recent purchase of Zond’s wind turbine generator manufacturing business may have had some impact on the decision. As might be expected, the unregulated construction of wind projects produced its own set of challenges. More wind-generation units were built than the ERCOT transmission system was capable of accommodating during peak wind hours, resulting in curtailment orders to wind generators and significant losses to the owners of wind projects. One large project owner even went so far as to build a private transmission line stretching approximately 250 miles from its project to a substation near San Antonio, Texas to facilitate delivery of its power.17 Wind developers in Texas now faced a conundrum. Under traditional utility regulation principles, construction of new utility property must be justified in advance as serving the public convenience and necessity.18 However, the wind developers needed transmission service where there were few users of electricity, and they could not secure financing to build new wind projects without transmission service already available. Thus, willing transmission utilities could not secure assurance from the Public Utility Commission of Texas that a new transmission line would be entitled to reimbursement from ERCOT for its costs. Furthermore, the three-year time-scale for building a wind project in Texas did not match well with the roughly five-year time-scale for designing, siting and constructing transmission lines.19 The Texas legislature responded in 2005 with an innovative solution. It directed the Public Utility Commission to identify areas of the state that would be most attractive for development of wind projects and to direct the transmission utilities to construct the necessary transmission lines. The cost (ultimately over $7 billion) was to be paid for by all ERCOT ratepayers with the costs allocated according to MWh consumed. As a part of the legislation, the legislature made a pre-emptive finding that the transmission lines to be designated by the Public Utility Commission would serve the public convenience and necessity, relieving the Public Utility Commission of the need to make such a determination. The Public Utility Commission under the direction of its chairman, Barry Smitherman, drove the process to completion despite significant opposition from industrial electric customers and entrenched fossil fuel interests. Rather than designate areas to be served, the Commission invited wind developers to propose areas where they were prepared to build new wind farms and were prepared to make significant deposits, subject to forfeiture if the projects were not completed, to obtain new transmission service. Based upon the concentration of proposed projects, the Commission designated four areas of the state to receive new transmission service, and additional in-fill upgrades to eliminate bottlenecks preventing delivery of wind power to the load centres of the state. The Public Utility Commission ultimately designated four areas of the state as ‘competitive renewable energy zones’ (CREZ) and directed the system operator 17

E. O’Grady, ‘FPL builds private transmission line in Texas’, Reuters (26 October 2009), available at www.reuters.com/article/2009/10/26/utilities-wind-texas-idUSN2620354820091026 18 Tex. Util. Code, Sec. 37.05 19 B. Diffen, ‘Competitive renewable energy zones: how the Texas wind industry is cracking the chicken & egg problem’, Rocky Mountain Mineral Law Foundation Journal 46(1) (2009), 47–98.

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to design high-voltage 345 kV transmission system extensions to provide electric service to the zones. At the same time, the Public Utility Commission invited parties who were interested in providing transmission service to propose to construct the new lines, and selected the winning proposals based upon both cost and the rate of return proposed by the bidders. In the process, the Public Utility Commission granted certificates to several new entrants into the Texas utility market, and allowed one niche utility company to significantly expand its service area. Prior to these decisions, the Texas electric utility market had been virtually closed to new entrants, with only one new transmission and distribution utility being granted a certificate of convenience and necessity in the thirty-year history of state-level electric utility regulation. At the end of 2013, the 3,600 right of way miles of new 345 kV transmission lines were energised, positioning Texas to grow from roughly 11,000 MW of installed wind capacity as of the end of 2013 to a projected 20,000 MW of installed wind capacity in 2017. As of September 2015, Texas had over 16,000 MW of installed wind capacity,20 with another 10,000 MW of projects either in construction or having signed transmission interconnection agreements.21 Ironically, the author of the legislation that directed the Texas Public Utility Commission to create the CREZ transmission improvements in 2005 introduced a bill in the Texas legislature in 2015 to eliminate the authority of the Public Utility Commission to continue to expand transmission capacity to serve renewable energy projects. However, as a result of strong opposition from landowners who hope to benefit from wind royalties and wind developers, the legislation failed, and on 1 June 2015, the Texas legislature adjourned its biennial 140-day session, ending the efforts of opponents of wind generation in Texas to repeal the CREZ legislation. CONCLUSION The massive wind development boom in Texas was the result of a combination of unintended consequences, conscious decisions and unforeseen events. Certainly, the executives of the Texas investor-owned utilities could not have anticipated that their decisions to sever their interconnections with the rest of the Unites States would facilitate construction of low-cost, independently owned wind generation that would cannibalise their future coal generation fleets. The legislators who voted to add a weak renewable portfolio standard to the bill deregulating the electric utility industry in Texas probably had no idea that they were voting to enable the growth of the Texas wind industry from zero to over 16,000 MW in sixteen years. Certainly the author of the CREZ enabling legislation has now made a futile attempt to put the genie back in the bottle. Nevertheless, with strong support from landowners and local public officials in western Texas, the wind industry continues to grow apace.

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US Department of Energy WINDExchange website, available at http://apps2.eere.energy.gov/ wind/windexchange/wind_installed_capacity.asp 21 ERCOT Capacity, Demand and Reserves Report, May 2015. Available at www.ercot.com/content/gridinfo/resource/2015/adequacy/cdr/CapacityDemandandReserveReport-May2015.xls

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SOLAR RIGHTS IN THE UNITED STATES Sara C. Bronin1

INTRODUCTION Solar rights are legal rights needed to ensure that a piece of land has access to sunlight. These rights may be of interest to property owners seeking to undertake a variety of activities: farming, lighting and clothes drying, to name a few. But perhaps the most economically significant purpose for which solar rights may be utilised is for that of solar collectors. Such devices are used to harness the rays of the sun and transform them into thermal, chemical or electrical energy. In an era of increasing deployment of solar collectors across the globe, the fair and efficient allocation of solar rights is of increasing importance. This chapter will focus on solar rights in the United States. It will address how solar rights are currently allocated and will suggest the need to formulate solar rights that will deliver more optimal policy results in the future.2 CURRENT MEANS OF ALLOCATING SOLAR RIGHTS In the United States today, there are three primary methods of allocating solar rights: express agreements, governmental allocations and court assignments.

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Sara C. Bronin is Professor of Law at the University of Connecticut School of Law. Her scholarly research examines property, land use, historic preservation, green building and renewable energy law. In addition to her teaching responsibilities, she currently serves as Faculty Director for the university’s Center for Energy and Environmental Law. An attorney and architect, Professor Bronin has also served as an expert witness and as a consultant to cities, public agencies and private firms. Much of this chapter draws from two related articles I authored a few years ago, ‘Solar rights’ and ‘Modern lights,’ which were two of the first comprehensive treatments of solar rights in the legal literature in decades. S. C. Bronin, ‘Modern lights’, Colorado Law Review 80(4) (2010), 881; S. C. Bronin, ‘Solar rights’, Boston University Law Review 89(4) (2009), 1217 (reprinted in P. E. Salkin (ed.), Zoning and Planning Law Handbook (Thomson West, 2010); reprinted in K. K. DuVivier, Renewable Energy Reader (Carolina Academic Press, 2011)).

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Each of these methods attempts to account for the natural path of sunlight – which runs over one parcel to get to another – and to resolve actual or potential disputes among neighbours. Before describing each of these methods in greater detail, it is important to establish the legal framework within which they operate. In the United States, there is no national solar rights regime. Rather, the fifty states may choose to articulate the right to access sunlight, through legislatures, courts and political subdivisions.3 Few states have adopted a statewide solar regime through their legislatures or expressly authorised political subdivisions to do so. Few courts have opined on the creation of solar rights. And few political subdivisions (such as cities and counties) have passed local rules establishing solar rights. The various articulations of solar rights thus form a patchwork, leading to inconsistencies from jurisdiction to jurisdiction. Moreover, there are many jurisdictions where solar rights are either hardly or not at all considered. With that background in mind, we now turn to the three methods of allocating solar rights. The first is through express agreements: arrangements between private parties who have bargained to establish solar rights. They may take the form of an access easement across the parcel of a neighbour, a covenant restricting the use of land, or a landlord-tenant arrangement. Such arrangements may be perpetual or finite in term; they may be assignable or not. The biggest benefit of an express agreement is that the parties subject to it have created a solar right by allocating associated burdens in the way they deem most suitable. From that perspective, the express agreement is a fair method. Unfortunately, not all jurisdictions explicitly allow for solar rights to be created by express agreements between private parties. Parties may, however, conceptually extend existing statutory provisions or common law authorising easements, covenants and tenancies to the solar context. Note, however, that if key parties do not agree to create a solar right, it will not be created. Moreover, even where rights are created through express agreements, they come in so many customised forms that their effectiveness may be difficult to track. The second means of creating solar rights is through governmental allocation, namely awards of solar permits or the enforcement of local solar zoning ordinances. Three states have established solar permitting regimes, which require applicants to apply to a public body if they want to protect their future utilisation of sunlight for some beneficial use.4 The award of a permit prevents neighbouring property owners in the path of the sun from blocking the solar access of the permit holder. In addition, in the United 3

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Native American tribes, which have their own federally recognised tribal governments, and the territories (such as Puerto Rico) may also choose to articulate solar rights regimes. New Mexico, Wisconsin and Wyoming are the three states that have statewide solar permitting rules. However, Wisconsin and Wyoming delegate their power to approve solar permits to localities. See New Mexico Statutes and Annotations Secs 47-3-1 to 47-3-5; Wisconsin Statutes and Annotations Sec. 66.0403; Wyoming Statutes and Annotations Sec. 34-22-103. Various cities, including Portland, OR, have established solar permitting regimes. Portland, OR, City Code & Charter Sec. 3.111.050.

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States, political subdivisions are empowered by the respective states to create zoning rules: regulatory schemes specifying where certain land uses may occur, usually in the context of a local comprehensive plan. Several states allow localities to zone for solar access,5 and a handful of cities have developed full solar zoning regimes.6 The biggest benefit of governmental allocations is that the regime is set forth in advance, improving predictability and uniform application. However, the costs of obtaining and applying for permits may be high for individual applicants. The third means of creating solar rights is through court assignment of such rights. Private parties have attempted to persuade judges to create solar rights through theories of private nuisance, prescriptive easement or implied easement. Courts in the United States have generally rejected these theories. In contrast, the English ‘ancient lights’ rule allows for parties to establish a prescriptive easement in solar access after twenty years.7 American courts rejected this rule starting in colonial times, because they felt that adopting it would unduly limit growth in emerging cities and towns. These days, the biggest disadvantage for American applicants seeking to persuade courts to create solar rights is cost: litigation is time-consuming and expensive, and given judicial precedent unlikely to yield positive results. FUTURE MEANS OF DELIVERING SOLAR RIGHTS As the preceding section described, the United States lacks a uniform approach to solar rights. Different state and local jurisdictions have experimented with different legal regimes, and private parties have also tried to adapt existing law to advance their own solar rights choices. That more attention has not been paid to developing consistent, universal best practices with regard to solar rights may be surprising for two reasons. First, sunlight is an increasingly valuable resource given the rapidly expanding market for solar collectors. Where access to sunlight is not well articulated, economic value might

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Arizona, Connecticut, Indiana, Iowa, Minnesota, Nebraska, New York, Oregon, Tennessee, Washington, Wisconsin and Wyoming are among the states that expressly authorise localities to regular solar energy. See Arizona Revised Statutes Annotated Sec. 9-462.01(A)(3); Colorado Revised Statutes Sec. 31-23-301; Connecticut General Statutes Annotated Sec. 8-2(a); Indiana Code Annotated Sec. 36-7-2-2 and 36-7-2-8; Iowa Code Annotated Sec. 335.5 and Sec. 414.3; Minnesota Statutes Annotated Sec. 394.25(2) and Sec. 462.357(1); Nebraska Revised Statutes Sec. 66-913; New York General City Law Sec. 20(24); New York Town Law Sec. 263; New York Village Law Sec. 7-704; Oregon Revised Statutes Annotated Secs 215.044, 227.190 and 227.290(2); Tennessee Code Annotated Sec. 13-7-101; Washington Revised Code Annotated Sec. 36.70.560; Wisconsin Statutes and Annotations Sec. 62.23(7)(c); Wyoming Statutes and Annotations Sec. 34-22-105(a). The most prominent of these cities is Boulder, CO. See Boulder, CO, Revised Code Sec. 9-9-17(d) (1); City of Boulder, ‘Solar access guide or solar shadow analysis’ (2006), available at www-static. bouldercolorado.gov/docs/PDS/forms/815_Solar_Access_Brochure.pdf. The English ‘ancient lights’ rule dates back to the sixteenth century. See Prescription Act, 1832, 2 & 3 Will., 4, C. 71, Sec. 3 (Eng.) (codifying this rule by establishing a permanent easement for property owners whose uninterrupted access to light lasts for twenty years).

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not be maximised. Second, solar energy is highly subsidised by public entities, through grants, tax credits, low-interest loans and special financing methods. Without appropriate and consistent solar rights rules, the value of these public incentives may be jeopardised. A more deliberate and clear approach to solar rights is advisable. The appropriate jurisdiction to articulate solar rights is state governments, which are the jurisdictions that typically allocate property rights in the United States. First, state legislatures should explicitly authorise solar easements, solar covenants and landlord-tenant arrangements that provide for solar rights. The authorisation of such express agreements would ensure that private parties feel more secure bargaining with each other to allocate rights into the future. Second, state legislatures must allocate rights through permitting regimes, which would allow property owners to apply ex ante, and should explicitly allow localities to consider solar rights in their zoning ordinances. Adopting public processes and criteria for the allocation of solar rights may reduce the burdens of cost and time on individual property owners seeking to invest in solar energy. A thumb on the scales might be placed in favour of solar energy by providing that the initial entitlement be placed with the solar rights seeker, and not with the person or entity seeking to stop him or her, and by prioritising energy first among various uses of sunlight (farming, lighting and clothes drying, for example). Third, state legislatures might establish scenarios in which courts may find solar rights are established through nuisance, prescriptive easements and implied easement theories. A small handful of states have already begun to do this, particularly in the situation where blocking a solar collector is a nuisance, and more should follow suit.8 With more explicit rules allocating solar rights, more people may be willing to invest in solar energy. This may particularly be true in urban areas where neighbouring property owners are located closer to each other than in rural areas and thus have a greater likelihood of blocking the other’s sunlight.

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California is one of those states. See California Public Resources Code Secs 25980–6 (naming as a public nuisance any tree or shrub which, between the hours of 10 a.m. and 2 p.m., shades more than 10 per cent of the area around a previously installed solar collector).

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THE US–CHINA CLIMATE AGREEMENT: A NEW DIRECTION Edward Flippen1

The Kyoto Protocol is an international treaty that commits countries to fight global warming by reducing greenhouse gas concentrations in the atmosphere to ‘a level that would prevent dangerous anthropogenic interference with the climate system’.2 The Kyoto Protocol was adopted in Kyoto, Japan, on 11 December 1997 by the Conference of the Parties to the United Nations Framework Convention on Climate Change (COP) and entered into force on 16 February 2005. The detailed rules for the implementation of the Kyoto Protocol were adopted at the Seventh Session of the COP in Marrakesh, Morocco, in 2001. These rules are more commonly referred to as the ‘Marrakesh Accords’ and their first commitment period started in 2008 and ended in 2012.3 In general, the Marrakesh Accords examined types of land use including forest management, cropland management and grazing land management in order to assess their greenhouse gas emission impacts and explore ways to account for and neutralise those impacts.4 The Kyoto Protocol is seen as an important first step towards global emission reduction and the stabilisation of greenhouse gas emissions. Furthermore, it provides a framework for future international agreements on climate change. Despite the possible benefits of

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Edward Flippen is a lawyer and lecturer in energy regulation and policy at the University of Virginia School of Law and Queen Mary University of London. United Nations Framework Convention On Climate Change (1997). Kyoto Protocol to the United Nations Framework Convention on Climate Change Article 2 adopted at COP3 in Kyoto, Japan, on 11 December 1997, available at http://unfccc.int/essential_background/convention/ background/items/1353.php United Nations Framework Convention On Climate Change (n. d.). Kyoto Protocol Essential Background Information, available at http://unfccc.int/kyoto_protocol/items/2830.php United Nations Framework Convention On Climate Change (n. d.). Marrakesh Accords and COP 7, available at http://unfccc.int/land_use_and_climate_change/lulucf/items/3063.php

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the Kyoto Protocol, China, India and the United States would not make a binding commitment and, until November 2014, all three countries signalled that they would not ratify any treaty that would require them to reduce CO2 emissions.5 During President Obama’s first official state visit to China in November 2014, he and his Chinese counterpart, Xi Jinping, agreed for the first time on the need to take concrete steps to reduce carbon emissions. Specifically, China agreed to reduce its levels of carbon emissions by 2030 through a variety of actions, including delivering 20 per cent of its energy from renewables. In return, by 2030 the US would cut carbon emissions by 30 per cent from their 2005 level. The United States Chamber of Commerce expressed concerns over the Obama–Xi Jinping environmental agreement. The Chamber was concerned that the agreement would cost the US economy between $40 and $52 billion per year and possibly cost 224,000 jobs each year until 2030.6 China, on the other hand, will not be obligated to take even the simplest steps to reduce carbon emissions for the next sixteen years. Without any concrete obligations, it is likely that China will make considerable efforts to increase its growth through the construction of coal-generating plants which until recently were being built at the rate of approximately one per week. Of equal concern is the fact that the United States will have no way of knowing whether China has taken any action to reduce carbon emissions at the end of sixteen years. Furthermore, the agreement does not have any means of enforcement in the event that China fails to live up to its obligations. A Washington Post syndicated columnist summed up the agreement in a recent column when he wrote ‘[It] sounds like the most one-sided deal since Manhattan sold for $24 in 1626’.7 While a ‘one-sided’ deal is real possibility, the Obama–Xi Jinping environmental agreement also presents opportunities for positive change. First, China and the United States have begun a dialogue about reducing carbon emissions, something that had not happened before President Obama’s visit. Second, further discussions by the respective government officials could have positive environmental impacts. For example, the United States and China could reach agreements on ‘best practices’ in areas such as the construction of sustainable housing; appliance, heating and air conditioning system efficiencies (HVAC); and automobile efficiency standards. The parties could mutually encourage the manufacture of ‘smart’ meters that interact with household appliances, HVAC and security systems which could be accessible from mobile phones. Most importantly, there is potential for mutual collaboration on fossil

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Kyoto Protocol (n.d.), available at http://en.wikipedia.org/wiki/Kyoto_Protocol C. Isidore, ‘Obama’s China climate deal: job killer or worth the cost?’ CNN Money (12 November 2014), available at http://money.cnn.com/2014/11/12/news/economy/climatechange-deal-costs C. Krauthammer, ‘The climate pact swindle’, The Washington Post (20 November 2014), available at www.washingtonpost.com/opinions/charles-krauthammer-the-climate-pact-swindle/2014/11/20/f78f6474-70e9-11e4-8808-afaa1e3a33ef_story.html

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fuel generating plant efficiency and improvements in energy storage which is critical to keeping electricity flowing during wind and solar generating power unit down times. Not only could consensus on these and other ‘best practices’ lead to positive environmental impacts, but they could also have significant economic benefits. For example, White House officials estimate that new efficiency standards for appliances, improved mileage rules for car manufacturers and similar efforts could save the United States billions of dollars.8 If these types of changes were implemented in the United States and China, these talks could lead to financial savings in excess of a trillion dollars and untold climate benefits. Third, and possibly most important, talks could potentially improve relations between Chinese authorities and US companies attempting to compete with the Chinese for the country’s flourishing nuclear power business. As The Wall Street Journal reported on 15 December 2014, seventy-one nuclear reactors are under construction globally, and twenty-six of those reactors are under construction in China.9 Chinese companies want that business. However, US corporations can provide extensive, unparalleled nuclear experience currently unavailable to Chinese companies. Surely talks between the United States and China could lead to a fair and competitive market that would benefit all of the parties involved. In fact, talks that improve the workings of the nuclear industry in China could even cause a shift away from coal as the base load energy of choice. These talks are important because since 1900, CO2 concentrations have increased from 300 parts per billion to 400 parts per billion, a 33 per cent increase above their prior 800,000-year high in just over 100 years.10 CO2 lifetime in the atmosphere is not short, and approximately one-third of CO2 is still in the atmosphere after 100 years. Generally speaking, the current high CO2 concentrations are due in large measure to the astonishing economic growth in the developed nations. In 2010, CO2 emissions in the United States were 5.4 billion tons while China’s and India’s were 8.3 and 2 billion tons respectively.11 In 2014, CO2 emissions hit 40 billion tons, 65 per cent above the 1990 levels.12

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H. Zichal, ‘Historical energy efficiency rules would save consumers money and cut carbon emissions’, The White House Blog (29 August 2013), available at www.whitehouse.gov/ blog/2013/08/29/historic-energy-efficiency-rules-would-save-consumers-money-and-cut-carbonemissions; B. Walsh, ‘White House to toughen fuel standards for heavy-duty vehicles’, Time (18 February 2014), available at from http://science.time.com/2014/02/18/white-house-totoughen-fuel-standards-for-heavy-duty-vehicles 9 B. Spegele, ‘China wants “Made in China” nuclear reactors’, The Wall Street Journal (15 December 2014), available at www.wsj.com/articles/china-moves-to-keep-nuclear-worklocal-1418669373 10 R. Kunzig, ‘Climate milestone: Earth’s CO2 level passes 400 PPM’, National Geographic News (9 May 2013), available at http://news.nationalgeographic.com/news/energy/2013/05/130510earth-co2-milestone-400-ppm 11 H. Williams Moore, ‘China, America and climate change’, Richmond Times Dispatch (3 January 2015), available at www.richmond.com/opinion/their-opinion/article_5a0e65f9-3d79-5c41adc6-ad00f77f9e96.html 12 M. McGrath, ‘China’s per capita carbon emissions overtake EU’s’, BBC News (21 September 2014), available at www.bbc.com/news/science-environment-29239194

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China, India and the United States currently account for over 45 per cent of total anthropogenic CO2 emissions. These numbers indicate that an agreement to reduce greenhouse gas emissions among China, India and the United States would be instrumental in significantly reducing worldwide greenhouse gas emissions. Furthermore, talks between China and the United States, such as those initiated by President Obama in 2014, could be a good starting point towards substantial environmental improvements. In February 1972, President Nixon arrived in China on an official state visit, the first such visit by a US president since the formation of the People’s Republic of China in 1949. During the trip, President Nixon and China’s Premier, Zhou Enina, unexpectedly agreed to the establishment of a permanent US trade mission in China. As the saying goes, the rest is history. Today the US and China engage in billions of dollars in trade and China is the United States’ largest creditor, holding over a trillion dollars in US Treasury securities. It is clear that both China and the United States’ economic strengths and weaknesses are now inextricably tied to one another. Once again China and the United States have the opportunity to enter new territory and forge a productive relationship that could create meaningful environmental change. The Obama–Xi Jinping agreement could be the first step towards collaboration in areas such as sustainable housing construction, manufacturing, electric and gas generation, and other processes that would inure to the benefit of the world at large. President Obama’s November 2014 visit to China could open the door to beneficial reductions in carbon emissions just as President Nixon’s visit in February 1972 opened the door to beneficial trade. And the outcomes of Obama’s visit could be just as unimaginable now as the outcomes of President Nixon’s visit was then. At a minimum, it is a new direction towards achieving stabilisation of future greenhouse gas emissions.

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GOING GREEN: THE UNITED STATES DEPARTMENT OF DEFENSE AND ENERGY SECURITY Alexios Antypas1

INTRODUCTION Over the course of the wars in Iraq and Afghanistan, in which the United States suffered great losses and incurred high costs to supply its forces with oil,2 the US military has developed a doctrine, policy and institutional frameworks, and organisational cultural changes in order to begin to break its dependence on oil through energy efficiency, switching to alternative energy sources and new technologies.3 Military leaders have put increasing importance on climate change and energy security for both military and national security reasons, and have recognised the relationship that exists between

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Alexios Antypas is an Associate Professor in the Department of Environmental Sciences and Policy at Central European University and Director of the Center for Environment and Security. He specialises in the field of environmental policy and governance, and has published widely on environmental policy issues, including climate change policy and politics, multi-level governance in the European Union, environmental security, renewable energy policy, corporate social and environmental responsibility, and conservation and communities, among other topics. He has served as a consultant to the European Union, the Organization for Economic Cooperation and Development, the United Nations Environment Programme, the United Nations Development Programme, the World Health Organization, the Regional Center for Central and Eastern Europe, the Hungarian Ministry of Environment and the US Forest Service. Center for Naval Analyses Military Advisory Board, ‘Powering America’s defense’ (2009), available at www.cna.org/sites/default/files/Powering%20Americas%20Defense.pdf Department of Defense, ‘Energy for the warfighter: operational energy strategy’ (2011), available at http://azsolarsummit.org/sites/default/files/uploads/oes_report_to_congress-2.pdf

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those issues in official doctrine4 and through think tanks with close ties to the military.5 MILITARY USE OF ENERGY The US military is the world’s greatest single consumer of energy, using more energy for its operations and facilities than any other organisation in the world (and more than 100 nations).6 Eighty per cent of the energy used by the federal government is used by the Department of Defense (DOD)7 and the DOD, like other governmental organisations, is now subject to national legislation mandating improvements in energy performance under the Energy Independence and Security Act of 2007. On installations, electricity represents 49 per cent of total energy consumed, while natural gas accounts for another 32 per cent.8 Combining facilities and operational energy, oil accounted for 77 per cent of all energy used by the military in 2010, and 78 per cent of its expenditure on energy. Electricity accounted for 12 per cent of consumption and 16.8 per cent of expenditures, and natural gas 8 per cent of consumption and 3.8 per cent of expenditure.9 In 2013 operational energy accounted for 70 per cent of all energy consumed by the military and 78 per cent of its energy costs,10 and within the area of operational energy, jet fuel accounted for 81 per cent of all energy consumed in 2010.11 Thus, in order to break the dependence on oil and achieve significant financial savings, the military has begun to focus on deriving electricity from renewables for its installations and replacing oil-based fuels for aircraft and other large platforms such as ships. THE DOD PERSPECTIVE ON ENERGY SECURITY The DOD has defined energy security as ‘having assured access to reliable supplies of energy and the ability to protect and deliver sufficient energy to meet

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Department of Defense, ‘Quadrennial defense review’ (2010), available at www.defense.gov/ QDR/QDR%20as%20of%2029JAN10%201600.pdf 5 Center for Naval Analyses Military Advisory Board, ‘Powering America’s Defense’ and ‘National security and the accelerating risks of climate change’ (2014), available at www.cna.org/sites/ default/files/MAB_2014.pdf 6 J. Warner and P. W. Singer, ‘Fueling the “balance”: a defense energy strategy primer’, Brookings Institution (2009), available at www.brookings.edu/~/media/research/files/papers/2009/8/ defense-strategy-singer/08_defense_strategy_singer.pdf 7 S. Closson, ‘The military and energy: moving the United States beyond oil’, Energy Policy 61 (2013), 306–16. 8 Department of Defense, Fiscal Year 2013 Operational Energy Annual Report (2014), available at http://energy.defense.gov/Portals/25/Documents/Reports/FY13%20OE%20Annual%20 Report.pdf 9 K. Sohbet, ‘DoD energy use in 2010’, Energy Blog (25 October 2011), available at http://energy. blognotions.com/2011/10/25/dod-energy-use-in-2010 10 Department of Defense, Fiscal Year 2013 Operational Energy Annual Report (2014), available at http://energy.defense.gov/Portals/25/Documents/Reports/FY13%20OE%20Annual%20Report.pdf 11 Department of Defense, Annual Energy Management Report (2011), available at www.acq.osd. mil/ie/energy/library/FY.2011.AEMR.PDF

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operational needs’.12 However, underlying the military’s concern with its own energy supplies lies a more strategic conceptualisation of the role of energy in US national security. As its role is constitutionally determined to be nonpolitical, the DOD is careful to limit expressing policy preferences outside the directly military domain. However, a network of think tanks closely associated with the military is able to express views and analysis through the retired senior officers that reflect and shape the thinking of active duty colleagues. One such organisation, the Center for Naval Analyses (CNA), issued a report in 2009 which detailed the arguments for enhancing US national security by transitioning to alternatives to oil, arguing that the DOD’s energy security priorities cannot be separated from broader issues of national security tied to energy: U.S. dependence on oil weakens international leverage, undermines foreign policy objectives, and entangles America with unstable or hostile regimes.13 [T]he U.S. has . . . dedicated an enormous military presence to ensure the unimpeded flow of oil – in the Persian Gulf and all across the globe. Our Commanders-in-Chief chose this mission not because they want America to be the world’s oil police; they did so because America’s thirst for oil leaves little choice.14 LINKAGE TO CLIMATE CHANGE The military considers climate change to be a major concern for national security, and its energy policies and programmes integrate climate change considerations at the strategic level. Every four years the DOD publishes the Quadrennial Defense Review (QDR), which is the most important publicly available document describing US military doctrine. The 2010 QDR expressed the military’s view of the risks of climate change and its link to energy security: Climate change and energy are two key issues that will play a significant role in shaping the future security environment. Although they produce distinct types of challenges, climate change, energy security, and economic stability are inextricably linked.15 While climate change alone does not cause conflict, it may act as an accelerant of instability or conflict, placing a burden to respond on civilian institutions and militaries around the world . . . DoD will need to adjust to the impacts of climate change on our facilities and military capabilities . . . [and] . . . foster efforts to assess, adapt to, and mitigate the impacts of climate change.16

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Department of Defense, Quadrennial Defense Review (2010), available at www.defense.gov/ QDR/QDR%20as%20of%2029JAN10%201600.pdf 13 Center for Naval Analyses Military Advisory Board, ‘Powering America’s defense’, 1. 14 Ibid., 7. 15 Department of Defense, Quadrennial Defense Review, p. 84. 16 Ibid., pp. 85–6.

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In response to the threat of climate change, the Center for Climate and Security (CCS), whose advisory board is composed primarily of retired senior military officers, was established to explore the national security implications of climate change and to participate in the policy process on climate change in ways that the DOD cannot. In its first policy brief on the relationship between national security and climate change the CCS called the US response to the risk of climate change ‘feeble’, stating that ‘climate change is a serious threat to the United States and the world. Military leaders understand it, the national security community understand it, and it’s time our civilian leaders responded accordingly.’17 INSTITUTIONAL AND POLICY FRAMEWORK The 2009 Defense Reauthorisation Bill created the office of Director of Operational Energy Plans and Programs (DOEPP), a position that was first obstructed by the Bush administration but finally established by the Obama administration. The DOEPP led in crafting a department-wide Operational Energy Strategy in 201118 and framing the 16 April 2014 directive on ‘DOD Energy Policy’19 which, for the first time, applies a common policy across all branches of the military and in both areas of energy policy. Each service of the military has also developed its own energy strategy20 and the DOD now seeks to comply with the Energy Independence and Security Act of 2007 and President Obama’s 2009 Executive Order to promote energy conservation across federal agencies. HEADLINE ACHIEVEMENTS The transition to renewable, on-base sources of electricity, development of new operational energy technologies, and testing and development of alternatives to oil for large platforms such as ships and aircraft is occurring rapidly across the branches of the US military. The number of energy projects in the military number in the dozens but several ambitious projects launched since 2012 stand out. The US Air Force has tested three possible alternative fuels to replace petroleum products to power its aircraft. Alcohol-to-jet (ATJ) fuel is derived from cellulose from biomass and was successfully tested in an A-10 Thunderbolt ground support aircraft in 2012, with the aircraft reportedly performing

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F. Femia, C. Parthermore and C. E. Werrell, ‘The inadequate response of the US to a major security threat: climate change’ Center for Climate and Security (2011), available at https://climateandsecurity.files.wordpress.com/2012/04/the-inadequate-us-response-to-a-major-securitythreat-climate-change_briefer-02.pdf 18 Department of Defense, ‘Energy for the warfighter: operational energy strategy’ (2011), available at http://azsolarsummit.org/sites/default/files/uploads/oes_report_to_congress-2.pdf 19 Department of Defense Directive 4180.01. DOD Energy Policy (16 April 2014), available at www.dtic.mil/whs/directives/corres/pdf/418001_2014.pdf 20 The Air Force Strategic Energy Plan of 2013, available at www.safie.hq.af.mil/shared/media/document/AFD-130325-124.pdf; The Army Operational Energy Policy of 2013, available at http:// usarmy.vo.llnwd.net/e2/c/downloads/295964.pdf; The Navy Strategy For Renewable Energy of 2012, available at http://greenfleet.dodlive.mil/files/2013/01/DASN_EnergyStratPlan_Final_ v3.pdf; US Marine Corps Order 3900.19, ‘Applying energy performance metrics and measures in requirements, development and acquisition decision-making’ (2013), available at www.hqmc. marines.mil/Portals/160/MCO%203900_19.pdf

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normally.21 The Air Force is also developing hydrogenated renewable jet fuels (HRJs) from plant and animals fats as well as synthetic kerosene.22 In the meantime, the Navy is in the process of developing what it calls the ‘Great Green Fleet’, a project involving an aircraft carrier fleet based around the USS Nimitz in which the ships and aircraft are powered by alternative energy sources and employing the greatest feasible degree of energy efficiency. The Great Green Fleet is a demonstration project currently under development and expected to be deployed to sea in 2016.23 The US Army Office of Energy Initiatives has been established as a permanent office with a mandate to transform installation energy, primarily through on-site renewable energy sources. The DOD is investing $7 billion in new renewable-energy projects eventually involving up to 16 million acres of land.24 The Army is particularly interested in protecting its facilities from disruptions in the supply of energy, and therefore aims to decouple facilities from the electricity grid to the greatest extent possible. CONCLUSIONS The leadership of the US military has become highly sensitised to issues of energy security and climate change over the course of the wars in the Middle East and is in the process of transforming its own energy systems. Military leaders have deep concerns about US dependence on oil and seek to put the DOD in a position of leadership in transforming US energy systems both through leading by example and through investing in new technologies that can spread to civilian uses. When it comes to energy and climate change, the US military’s positions align very closely with those of domestic liberal political forces, and countries such as Germany which are undertaking a rapid transformation of their energy systems. The DOD has not yet set a target date by which it intends to decouple from petroleum, but analysts in the Washington think tank circle have raised the prospect of a post-petroleum military by 2040.25 While the DOD is not a partisan political actor and thus tries to keep a distance from highly contested policy debates which do not directly affect it, the military’s lead in energy innovation may prove pivotal in a future US energy transformation.

21

Ecoseed, ‘US Air Force completes first test flight run on alcohol based jet fuel’ (12 July 2012), available at http://oilprice.com/Alternative-Energy/Biofuels/US-Air-Force-Completes-First-TestFlight-Run-on-New-Alcohol-Based-Jet-Fuel.html 22 K. Blakeley, ‘Department of Defense alternative fuels: policy, initiatives and legislative activities’ (Congressional Research Service, 2012), available at www.fas.org/sgp/crs/natsec/R42859.pdf 23 J. Dowling, ‘Improving energy security with the Great Green Fleet: the case for transitioning from ethanol to drop-in renewable fuels’, Journal of Energy and Environmental Law (Winter 2013), 82–106. For updated information, see the Navy’s website for this project at http://greenfleet.dodlive.mil/energy/great-green-fleet. 24 American Council on Renewable Energy, ‘Renewable energy for military installations’ (2014), available at www.acore.org/files/pdfs/Renewable-Energy-for-Military-Installations.pdf 25 C. Parthermore and J. Nagl, ‘Fueling the future forces: preparing the Department of Defense for a post-petroleum era’, Center for a New American Security (2010), available at www.cnas.org/files/ documents/publications/CNAS_Fueling%20the%20Future%20Force_NaglParthemore.pdf

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US CONJUNCTIVE WATER MANAGEMENT AND SUSTAINABLE ENERGY DEVELOPMENT Jason B. Aamodt1

Water and energy are braided together in the fabric of sustainable development (SD) and numerous scholars are addressing the issue.2 The United States Congress recognises the relationship with its ongoing consideration of the Energy 1

2

Jason B. Aamodt serves as the Assistant Dean for the University of Tulsa, College of Law, and focuses his research on sustainable development, energy justice and indigenous rights. In addition to managing a cutting-edge online law degree programme, he is the founding member of the Indian and Environmental Law Center, which, among other things, certified the first geographically defined toxic tort class action in Oklahoma, created a new cause of action in Indian accounting cases and obtained a National Law Journal Top-25 verdict in 2013. See, for example, B. Walsh, S. Murray and D. T. J. O’Sullivan, ‘The water energy nexus, an ISO50001 water case study and the need for a water value system’, Water Resources and Industry 10 (2015), 15–28; P. Reig, T. Luo and J. N. Proctor, ‘Global shale gas development: water availability and business risks’, World Resources Institute (2014), available at www.wri.org/sites/default/files/wri14_ report_shalegas.pdf; K. Hussey and J. Pittock, ‘The energy–water nexus: managing the links between energy and water for a sustainable future’, Ecology and Society 17(1) (2012), 31; International Energy Agency, World Energy Outlook (2012), available at www.worldenergyoutlook.org/media/weowebsite/2012/WEO_2012_Water_Excerpt.pdf, p. 501; N. Carter, ‘Energy’s water demand: trends, vulnerabilities, and management’, Congressional Research Service, CRS Report for Congress (2010), available at https://fas.org/sgp/crs/misc/R41507.pdf; J. Macknick, R. Newmark, G. Heath and K. C. Hallett, ‘A review of operational water consumption and withdrawal factors for electricity generating technologies’, National Renewable Energy Laboratory, Technical Report NREL/TP-6A20-50900 (2011); E. Mielke, L. Diaz Anadon and V. Narayanamurti, ‘Water consumption of energy resource extraction, processing and conversion, a review of the literature for estimates of water intensity of energy-resource extraction, processing to fuels, and conversion to electricity’, Energy Technology Innovation Policy Discussion Paper No. 2010-15 (2010), available at http://belfercenter.ksg.harvard. edu/files/ETIP-DP-2010-15-final-4.pdf; B. Sovacool, ‘Running on empty: the electricity–water nexus and the U.S. electric utility sector’, Energy Law Journal 30(1) (2009), 11–51, at 18; US Department of Energy, ‘Energy demands on water resources: report to congress on the interdependency of energy and water’ (2006), available at www.sandia.gov/energy-water/docs/121-RptToCongress-EWwEIAcomments-FINAL.pdf

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and Water Research Integration Act.3 The International Energy Agency (IEA) dedicated a chapter to the issue in the World Energy Outlook.4 UNESCO links water and energy security, among other issues.5 The framework of industry discussion addresses both the ‘energy intensity’ of water supplies6 and the ‘water intensity’ of energy supplies.7 Increasing energy needs are facing water scarcity. Energy development is the fastest growing use of water in the United States.8 The United Nations predicts that by 2050 water use worldwide will increase fourfold for manufacturing and 1.4 times for thermal electricity generation. Forty per cent of the world’s population will be living in areas of severe water stress; 20 per cent of the world’s aquifers will be overdrafted.9 With these concerns in mind, this chapter first outlines the status of water and energy as distinct and important aspects of the Sustainable Development Goals (SDGs) and then traces the various ways in which water and energy are in fact connected, providing basic figures of water use for energy production. The last section of the chapter focuses on emerging US conjunctive water management policies and their relationship to energy development. WATER AND ENERGY The energy and water quotients of SD were an important part of the Brundtland Commission’s Report in 1987.10 In turn, Agenda 21 noted, ‘These interactive processes [of population growth and increased consumption] affect the use of land, water, air, energy and other resources.’11 While the Millennium Declaration and the Millennium Development Goals failed to address energy use explicitly, subsequent UN declarations12 focusing on ‘Sustainable Energy

3

See, for example, Energy and Water Research Integration Act of 2014; 113th Congress H.R. 5189, which was introduced to Congress in 2010 & 2012. 4 International Energy Agency, World Energy Outlook, p. 501. 5 United Nations, ‘Managing water under uncertainty and risk’, The United Nations World Water Development Report 4, vol. 1 (2012), available at http://unesdoc.unesco.org/ images/0021/002156/215644e.pdf 6 D. Larson, C. Lee, J. J. Lee and S. Tellinghuisen, ‘California’s energy–water nexus: water use in electricity generation’, Southwest Hydrology 6(5) (2007), 20–2. 7 E. Williams and J. Simmons, ‘Water in the energy industry. An introduction’ (2013), available at www.bp.com/content/dam/bp/pdf/sustainability/group-reports/BP-ESC-water-handbook.pdf 8 As of 2010. Carter, ‘Energy’s water demand’. 9 United Nations, ‘Water and energy’, The United Nations World Water Development Report 2014, vol. 1 (2014), available at http://unesdoc.unesco.org/images/0022/002257/225741e.pdf 10 United Nations, ‘Report of the World Commission on Environment and Development: our common future’ (1987), para 60, available at www.un-documents.net/our-common-future.pdf (‘The ultimate limits to global development are perhaps determined by the availability of energy resources and by the biosphere’s capacity to absorb the by-products of energy use.’). 11 United Nations, Agenda 21 (1992), Sec. 5.3, available at https://sustainabledevelopment.un.org/ content/documents/Agenda21.pdf 12 United Nations, ‘International year of sustainable energy for all’, UN Res. 65/151 (2011); United Nations, ‘Decade of sustainable energy for all’ (2014), available at www.se4all.org/decade

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for All’ shaped the SDGs, which now explicitly recognise energy’s role (SDG No. 7) and seek the ‘sustainable management of water’ (SDG No. 6).13 A Harvard study14 and US Department of Energy research15 have estimated that energy development accounts for 27 per cent of all water consumed in the US, outside the agricultural sector. More recently, the International Energy Agency (IEA) has estimated that industrial development in all its forms accounts for 19 per cent of the worldwide consumption of water.16 The various ways that water is consumed in energy production17 is beyond the scope of this chapter, but it is notable that unconventional shale gas is increasingly important to energy security in the US.18 However, a ‘lack of water availability could curtail shale development in many places around the world’.19 The IEA reports that water availability threatens energy development in the US as well as in China.20 EMERGING WATER AND ENERGY POLICY Conjunctive water management is the process of coordinating the withdrawal and consumption of surface and groundwater resources. Despite the obvious gap in logic, many legal regimes in the US manage surface and groundwater separately. For instance aquifers in Oklahoma have suffered irreversible decline where withdrawals exceeded the aquifer’s ability to recharge, such as the Ogallala Aquifer; decline in the groundwater level has resulted in the loss of the natural flow of streams, such as the Beaver River in the Oklahoma panhandle.21 Increasingly, however, conjunctive water management systems are employed in the US. The following describes three approaches from New Mexico, Colorado and a unique aquifer in Oklahoma. These are energy-rich states, where water shortages might impede future energy development. In New Mexico, faced with over-allocated water resources, the City of Albuquerque obtained new water permits through conditions imposed by the State

13

United Nations, Open Working Group proposal for Sustainable Development Goals (2014), available at https://sustainabledevelopment.un.org/content/documents/1579SDGs% 20Proposal.pdf 14 Mielke et al., ‘Water consumption of energy resource extraction’, 5. 15 US Department of Energy, ‘Energy demands on water resources’. 16 International Energy Agency, World Energy Outlook, p. 503. 17 This paper focuses on the use of water to produce energy – ‘water for energy’. Ibid., p. 503. 18 International Energy Agency, World Energy Outlook, 23–4 (indicating that unconventional oil and gas production may make the US net energy positive by 2020, though the long-term impact of recent Saudi-led oil price depressions is presently unclear). 19 Reig et al., ‘Global shale gas development’, 6. 20 International Energy Agency, World Energy Outlook, p. 501. 21 Jacobs Ranch v. Smith, 2006 OK 34, Sec. 12, 148 P.3d 842.

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Engineer.22 The conditions included storage of water resources in an aquifer, and acquiring and retiring existing permits to reduce over-allocation.23 While the New Mexico Attorney General later ruled that retiring certain permits violated notions of due process,24 the overarching scheme is a good example of conjunctive water management. A more modern implementation can be seen in the recent Taos Pueblo water settlement, where aquifer storage and inter-basin transfers are timed to reduce shortages, while meeting cultural, environmental and economic needs.25 In Colorado, conjunctive water management is the norm, encompassing not only stream and groundwater, but also precipitation.26 An example is the case of Cache La Poudre Water Users Ass’n v. Glacier View Meadows,27 where a new condominium was able to obtain new water rights by retiring older permits from a stream that was already over-allocated. Managing withdrawals through a connected alluvial aquifer at once increased water availability in the stream and provided for new development. At one Oklahoma aquifer that uniquely applies conjunctive water management rules, the Arbuckle Simpson Aquifer, no groundwater withdrawal may cause significant reductions in regional spring or stream flow.28 The Oklahoma Water Resources Board established a biologically based metric that permits withdrawal and consumptive uses of the water resource, while protecting against significant flow reductions. Conjunctive management is increasing the quantity of water available for development in that region, while sustaining the resource for the future.29 In light of increasing energy needs and impending water scarcity, conjunctive water management policies are a key component to continued energy development in the US. Conjunctive water management may be particularly important to the development of unconventional shale gas resources which are dependent upon water availability, and which are in many cases located in water-scarce areas.

22

In New Mexico, the State Engineer is responsible for managing water resources and, among other things, issuing and enforcing permits and their conditions. 23 See City of Albuquerque v. Reynolds, 379 P.2d 73 (N.M. 1962). 24 New Mexico Attorney General No. 94-07 (23 December 1994). 25 Abeyta Water Rights Adjudication (2012), available at www.ose.state.nm.us/Legal/settlements/ Taos/documents/2012_12_12_Abeyta%20Settlement%20Agreement.pdf 26 D. Wolfe, quoted in J. Grantham, Synopsis of Colorado Water Law (Colorado Division of Water Resources, revised ed. 2011), available at http://hermes.cde.state.co.us/drupal/islandora/object/ co:7296/datastream/OBJ/view 27 550 P.d 288 (Colo. 1976). 28 OAC 785:30-3-5 (f), available at www.owrb.ok.gov/util/rules/pdf_rul/current/Ch30.pdf 29 The Arbuckle-Simpson Hydrology Study, available at www.owrb.ok.gov/studies/groundwater/ arbuckle_simpson/arbuckle_study.php

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DELIVERING NEW POLITY: PAVING THE WAY FOR THE EUROPEAN ENERGY UNION Elina Brutschin1

The new European Commission (2014–19) under the leadership of Jean-Claude Juncker lists among its top ten priorities the creation of the Energy Union through pooling resources, combining infrastructures and uniting negotiating power visà-vis third countries.2 The importance of this goal is further emphasised through the appointment of Maroš Šefčovič as one of the Vice-Presidents and the Commissioner for Energy Union3 and by having half of the Commissioners as part of the project team entitled ‘A Resilient Energy Union with a Forward-Looking Climate Change Policy’4. The idea of creating a European Energy Union, given the history of disconnected energy policies of the member states, is certainly ambitious and apart from some indicators in a newspaper article5 by the current European Council president, Donald Tusk, and a few proposals by think tanks, it is not clear what the specifics of such a union could be. In this chapter I will 1

2

3

4

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Dr Elina Brutschin earned a PhD from the University of Konstanz, Germany, writing on the liberalisation of the European gas market. Besides her expertise in energy matters, she focuses on Eastern European studies. She is currently working on a publication depicting the history of the European gas market and the role of the European Commission as a policy entrepreneur. J.-C. Juncker, ‘A new start for Europe: my agenda for jobs, growth, fairness and democratic change’, Opening Statement in the European Parliament Plenary Session, Strasbourg, 15 July 2014, available at http://ec.europa.eu/priorities/docs/pg_en.pdf#page=6 ‘The Commission’s structure’, European Commission homepage, available at http://ec.europa.eu/ about/structure/index_en.htm#te A. Hedberg, ‘Energy and climate – what is the new European commission thinking?’, EPC Commentary, 30 September 2014, available at www.epc.eu/pub_details?cat_id=4&pub_id=4859. D. Tusk, ‘A united Europe can end Russia’s energy stranglehold’, The Financial Times (21 April 2014), available at www.ft.com/intl/cms/s/0/91508464-c661-11e3-ba0e-00144feabdc0.html#axzz 3OzqDHfFJ

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briefly discuss the history of attempts to harmonise and Europeanise energy policies and suggest how the European Energy Union could be delivered in each of the areas emphasised by the new European Commission. POOLING RESOURCES Even though pooling resources in the energy sector lies at the heart of the European project through the creation of the European Steel and Coal Community (1951) and Euratom (1957), only the Lisbon Treaty (2009) entails a specific article (Article 194) that delineates the responsibilities of the Union in the energy sector.6 Nonetheless, Article 194 does not represent any extension of the existing legal practices. Among the major recent activities within the energy sector have been the directives and regulations targeted at the liberalisation of electricity and gas markets7 in order to harmonise and integrate the European markets. Some progress has been achieved but observers agree that especially within the retail markets there are significant differences that might create obstacles to the creation of the Energy Union.8 Consequently, some think tanks are calling for a fourth energy package to ensure better enforcement of the liberalisation policies.9 There are, however, also policy proposals which go beyond the incremental approach and call for a comprehensive restructuring of European energy governance. One of the radical solutions would be the creation of a new European Energy Treaty as, for example, suggested by the influential think tank ‘Notre Europe’.10 Such a treaty could unite the existing patchwork of legislation and would not be bound to a certain energy source (as it is for example with Euratom) but would have the flexibility to include new energy sources depending on technological advances. Given the experience of the Lisbon Treaty, even under the current securitisation of the European gas market caused by the crisis in Ukraine, such a treaty is highly unrealistic. Instead of enforcing top-down governance, the European Union could improve the coordination of the existing regional bottom-up initiatives11 such as the North Seas Countries’ Offshore Grid Initiative (Benelux countries,

6

The Lisbon Treaty (Lisbon Treaty Online), available at www.lisbon-treaty.org/wcm/the-lisbontreaty/treaty-on-the-functioning-of-the-european-union-and-comments/part-3-union-policiesand-internal-actions/title-xxi-energy/485-article-194.html 7 For the gas market: 98/30/EC, 2003/55/EC and 2009/73/EC. For the electricity market: 96/92/ EC, 2003/54/EC, 2009/72/EC. 8 S. Benedettini and C. Stagnaro, ‘Failure to liberalise energy retail markets jeopardizes energy union’, EnergyPost.eu, available at www.energypost.eu/failure-liberalise-energy-retail-marketsjeopardizes-energy-union 9 C. Billingham (ed.), ‘Solidarity: towards 2030 ambitions in energy policy’, Feps-Europe (2014), available at www.feps-europe.eu/en/publications/details/272 10 S. Andoura, L. Hancher and M. Van der Woude, ‘Towards a European Energy Community: a policy proposal’, Notre Europe (March 2010), available at www.eng.notre-europe.eu/0112155-Towards-a-European-Energy-Community-A-Policy-Proposal.html 11 J. de Jong and C. Egenhofer, ‘Exploring a regional approach to EU energy policies’, Centre for European Policy Studies (2014), available at www.ceps.eu/book/exploring-regional-approacheu-energy-policies

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France, Germany, Ireland, Sweden and the United Kingdom)12 or the Pentalateral Energy Forum (Benelux counties, Germany and France).13 Regional harmonisation will decrease the number of heterogeneous units at the European level and will make the coordination and the achievement of other goals much easier. Moreover, the research suggests that bottom-up governance approaches display higher rates of implementation and compliance when compared to topdown approaches.14 IMPROVING THE INFRASTRUCTURE The key to a successful Energy Union will be the European Commission’s initiatives to improve the infrastructure and to provide regulatory security to incentivise cross-border infrastructure investments. There have been some regulatory activities regarding the common security standards, but the biggest problem remains the investment gap. The Gas Security Regulation (994/2010) imposes a number of important obligations on the member states, which might create favourable conditions in relation to improving the infrastructure.15 The member states are required to create a common indicator to measure threats to gas security and to create socalled Preventive Action Plans in order to propose investments in new critical infrastructure. The evolution of the gas security policies is further supported by the Gas Coordination Group, which meets four times a year. The proper implementation of regulations forces further harmonisation and will enable better assessment of the critical infrastructure projects that should be supported by all member states. The investment gap was addressed through the creation of a programme entitled ‘Connecting Europe Facility’ which has a budget of €5.85 billion for the trans-European infrastructure (for the period 2014–20). Nonetheless, given that many of the cross-border projects are of a long-term nature, a permanent European Energy Fund would represent a more appropriate solution and would give a clear and credible signal to investors to support new projects and new technologies. There are, for instance, discussions around the so-called European supergrid16 to connect southern solar, western wave and northern wind and hydro energy. This project, however, progresses incrementally not only because of lack of investment and regulatory uncertainty but also because of many data

12

The political declaration is available at www.benelux.int/files/2714/0921/0355/Political_declaration_on_the_North_Seas_Countries_Offshore_Grid_Initiative.pdf 13 The political declaration is available at www.benelux.int/files/9513/9565/0634/PoliticalDeclarat ionOfThePentalateralEnergyForum_2013-EN.pdf 14 E. Ostrom and others, ‘Revisiting the commons: local lessons, global challenges’, Science 284 (1999), 278–82. 15 ‘Secure gas supplies’, European Commission (2015), available at http://ec.europa.eu/energy/en/ topics/imports-and-secure-supplies/secure-gas-supplies 16 D. Jefferies, ‘Do we need to build a European supergrid to secure our energy supply?’, The Guardian (19 June 2014), available at www.theguardian.com/big-energy-debate/europeansupergrid-secure-energy-supply

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privacy concerns that were voiced by European citizens over smart meters. In this area it is crucial that the European Commission takes the data privacy concerns and the data protection laws of the member states into consideration but more importantly that it continues with public information campaigns. Public acceptance of new technologies is a crucial element in delivering a comprehensive Energy Union concept. UNITING NEGOTIATING POWER In order to enable the European Union to speak with one voice in energy matters, and specifically on gas issues, some observers suggest creating a Gas Purchasing Group (suggested by ‘Notre Europe’) or a Gas Supply Agency (suggested by Donald Tusk). The idea behind this is that member states would be asked to negotiate jointly regarding any future gas contracts. That member states would agree to such a radical change is highly unrealistic. Even with environmental issues, where there is generally more agreement across the member states, the EU rarely speaks with one voice at the international level. A more realistic way to unite the negotiating powers would be through harmonising interests, which could only be achieved through a better trans-European infrastructure and more interdependencies within the European market.

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ANTITRUST ENFORCEMENT IN THE EU ENERGY SECTOR Kim Talus1

INTRODUCTION The downstream energy sector can be, and is, regulated through both the sector-specific regulatory framework and the application of general antitrust law. This is the case in both the United States and the European Union. However, the precise impact and the relationship of these two separate but interrelated regimes differ in the US and the EU. When compared to the US, the importance and the effect of the antitrust enforcement is much more direct and central in the EU. The approach in the US was discussed by the US Supreme Court in the ‘Trinko’ case (Verizon Communications, Inc. v. Law Offices of Curtis V. Trinko, L.L.P., 540 U.S. 398) where the Supreme Court noted that When there exists a regulatory structure designed to deter and remedy anti-competitive harm, the additional benefit to competition provided by antitrust enforcement will tend to be small, and it will be less plausible that the antitrust laws contemplate such additional scrutiny. As such, the approach in the US is to give preference to the sector-specific regulation. The role of antitrust law is not to second-guess the approach of the legislator, reflected in the sector-specific regulatory framework, but to focus mainly on areas and questions not directly regulated through the energy regulation. 1

Kim Talus is a Professor of European Energy Law at UEF Law School (University of Eastern Finland) and a Professor of Energy Law at the University of Helsinki. He is also the editor-in-chief of OGEL and an expert member (electricity) at the Finnish Market Court.

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The approach in the EU is quite the opposite from that in the US.2 In the EU the increasingly powerful and intrusive application of general antitrust law, or competition law, has often meant that the solutions and approaches of the sector-specific regulatory framework are circumvented through the strategic application of antitrust law by the European Commission.3 This chapter will discuss and explain why the approach on each side of the Atlantic differs so significantly. THE ROLE OF ANTITRUST LAW IN THE EU On an ideological level, it is easy to agree with the US Supreme Court that ‘when there exists a regulatory structure designed to deter and remedy anticompetitive harm, the additional benefit to competition provided by antitrust enforcement will tend to be small’.4 However, there are both economic and practical arguments in favour of EU competition law enforcement in situations where the market is already regulated through sector-specific regulation, such as in case of EU energy markets. First, under the hierarchy of norms in the EU, the Treaty law, somewhat akin to a national constitution, is the highest authority in the EU. The legal basis for sector-specific regulation is provided in the Treaty on the Functioning of the European Union (TFEU). As such, sector-specific regulation cannot conflict with Treaty law. Where such a conflict takes place, Treaty law prevails as the hierarchically superior source of law. Unlike sector-specific regulation, general EU competition law is Treaty-based law. Articles 101 and 102 of TFEU provide for rules on cartels and abuse of dominant position. Therefore, due to this hierarchical structure in the EU, the general competition law will always be applicable and prevails over the sector-specific regulatory framework and can override the regulatory choices made by the legislator. Second, sanctions for anticompetitive conduct are normally more effective under general EU competition law. As has been seen after the E.ON seals case with the sanction of €38 million for a broken seal,5 the threat of competition 2

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Case T-271/03, Deutsche Telekom v. Commission (2008) ECR II-477, Paras 121 and 122. For comparisons between the approaches in the EU and US, see Nicolas Petit, ‘Circumscribing the scope of EC competition law in network industries ? A comparative approach to the US Supreme Court ruling in the Trinko case’, Utilities Law Review 13(6) (2004), 185–91 and Giorgio Monti, ‘Managing the intersection of utilities regulation and EC competition law’, Competition Law Review 2 (2008), 123–45; K. Talus, ‘Just what is the scope of the essential facilities doctrine in the energy sector: Third Party Access-friendly interpretation in the EU v. contractual freedom in the US’, Common Market Law Review 48(5) (2011), 1571–97. For a detailed discussion, see Talus, ‘Just what is the scope?’ or K. Talus, Vertical Natural Gas Transportation Capacity, Upstream Commodity Contracts and EU Competition Law (Kluwer Law International, 2011). Verizon Communications, Inc. v. Law Offices of Curtis V. Trinko, L.L.P., 540 U.S. 398. Commission Press Release, ‘Antitrust: Commission imposes €38 million fine on E.ON for breach of a seal during an inspection’ (IP/08/108) 30 January 2008, available at http://europa.eu/rapid/ press-release_IP-08-108_en.htm?locale=en

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law sanctions have been enough for companies to agree to significant commitments in form of structural remedies.6 Third, the possibility of applying general competition law when national regulatory authorities have failed to act or when national governments make attempts to shield their national champions is of great significance.7 Also, due to factors like the strategic value of energy or connections between the government and energy companies, the negotiations at EU level are often difficult and the efforts to create an internal energy market or efficiently functioning markets may be distorted by short-term national interests or even the short-term political ambitions of the government in power. In these situations, the European Commission can, and arguably should, act through general competition law in order to correct the failures and shortcomings of the sector-specific regulatory regime. The other option for the Commission in this situation, to ensure the effective and uniform application of the sector-specific regulatory framework for energy throughout the EU, is to initiate infringement proceedings. Through this mechanism, the European Commission initiates an administrative procedure where it informs the EU member state that it is violating its obligations as an EU member state (for example, failure to implement the sector-specific regulatory regime or lack of enforcement of this regime) under Article 258 TFEU. However, due to the long duration of this procedure and the judicial stage that follows under Article 260 TFEU, this alternative is not as efficient as direct action through competition law by the European Commission. These differences in the approaches between the US and EU have their origin in the particularities of the EU. While the US approach is in many ways more logical, there are certain benefits in the EU approach. These include efficiency gains from the direct application of Treaty law by the European Commission. However, with benefits come certain risks. Some of these will be highlighted next. PROS AND CONS OF THE EU APPROACH The European Commission has intensified its efforts to create a change on the back of general competition law, together with its efforts on the regulatory front. Starting from destination clauses and downstream contracts, the focus of the Commission has moved towards more complex issues such as ownership unbundling and major capacity releases. A line of cases that followed the sector inquiry of 20078 suggests that while the approach of the sector-specific regulation is still reflected in competition law enforcement, the tools available

6 7

8

Such as in Case COMP/39.402 – RWE Gas Foreclosure. The reference is to cases like E.ON/Ruhrgas merger. See, in particular, OFGEM Letter to the Commission Vice President Loyola de Palacio (Ref: cm73-03cfl), 18 February 2003. Inquiry pursuant to Article 17 of Regulation (EC) no. 1/2003 into the European gas and electricity sectors (Final Report) (COM/2006/851 final), 10 January 2007.

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to the Commission under general competition law can be very powerful. This was, in particular, the case in E.ON,9 RWE10 and ENI.11 In these cases, the end result went considerably further than the sector-specific regulation. Similarly, the GDF Suez12 and E.ON13 decisions and the 50 per cent capacity releases are a significant step forward in promoting access to networks which will in turn help delivering greater competition. The most recent ongoing stage in the enforcement of EU competition law in the energy sector has been the case against the Russian energy giant Gazprom. In this case, the Commission suspects that: (1) Gazprom may have divided gas markets by hindering the free flow of gas across member states; (2) Gazprom may have prevented the diversification of the supply of gas; and (3) Gazprom may have imposed unfair prices on its customers by linking the price of gas to oil prices.14 While the approach in the EU has in many ways delivered significant results, one may wonder about the ability of competition law authorities to consider the complexities of energy markets, energy policies and energy market regulation.15 This is, in particular, a risk in markets and sectors where the link between upstream and downstream is direct, such as the EU gas markets. Here, both the sector-specific regulatory framework and the antitrust enforcement should consider the legitimate expectations of the economic actors along the entire value chain. It seems that the sector-specific regulatory framework in the EU is slowly moving in this direction.16 It is now crucial that the antitrust enforcement follows.

9

Decisions COMP/B-/39.388 and 39.389. Case COMP/39.402 – RWE Gas Foreclosure. 11 COMP/39.315 – ENI. 12 COMP/39.316 – GDF foreclosure. 13 COMP/39.317 E.On gas foreclosure. 14 Case 39816 – Upstream gas supplies in Central and Eastern Europe. See also Antitrust: Commission opens proceedings against Gazprom (IP/12/937), 4 September. For some discussion, see K. Talus, EU Energy Law and Policy: a Critical Account (Oxford University Press, 2013). 15 For a discussion on the differences in markets and their regulation in the US, EU and Asia-Pacific, see K. Talus, ‘United States natural gas markets, contracts and risks: what lessons for the European Union and Asia-Pacific natural gas markets?’, Energy Policy 74 (2014), 28–34. 16 This is reflected in the Commission Regulation (EU) No 984/2013 of 14 October 2013 establishing a Network Code on Capacity Allocation Mechanisms in Gas Transmission Systems and supplementing Regulation (EC) No 715/2009 (OJ L 273/5, 15 October 2013) where the capacity products for gas transportation seem to reflect the need to use long-term contracts in the upstream. For background and rationale for long-term gas contracts, see K. Talus, ‘Long-term natural gas contracts and antitrust law in the European Union and the United States’, Journal of World Energy Law and Business 4(3) (2011), 260–315. 10

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DELIVERING ENERGY POLICY IN THE EU: SOME THOUGHTS ON THE ROLE OF CONSUMERS Emanuela Michetti1

The relationship between energy policy and energy consumers in the European Union is twofold: on the one side consumers are supposed to be the main beneficiaries of the three-pillar policy for increased competition, sustainability and security of supply,2 while on the other they are expected to contribute to the implementation of such policy. For instance, consumers can exploit the potential of the new smart meter technology installed in their houses to gather immediate information about their consumption, and accordingly manage their demand to reduce bills and save energy. Moreover, they can shop around for the most convenient retail offer, taking full advantage of the liberalised markets, while in practice enhancing the competition among suppliers with their choices. However, the extent to which consumers can contribute to the implementation of the EU energy policy might be challenged by inadequate consumer engagement. In fact, consumers don’t seem to have completely abandoned their historical passive role.

1

2

Dr Emanuela Michetti has a Masters degree in Economics and a PhD in Law and Economics from the University of Siena, Italy. She is an economist specialising in regulation, competition and consumer protection in network industries, in particular energy and transport. She has over ten years of experience combining academic and industry positions. She has been Visiting Lecturer at the Riga Graduate School of Law since 2012, and currently works in a regulatory authority of the United Kingdom. European Commission (2007), ‘Communication from the Commission to the European Council and the European Parliament: an energy policy for Europe, COM(2007) 1 final, not published in the Official Journal but available at http://eur-lex.europa.eu/legal-content/EN/TXT/PDF/?uri=CE LEX:52007DC0001&from=EN

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The European Agency for the Cooperation of Energy Regulators3 has recently painted a worrying picture on the low levels of consumer engagement: ‘The majority of electricity and gas household consumers do not participate actively in the market by exercising choice among available suppliers, as well as among different prices and product offerings’.4 In 2013 the average switching rate (one possible indicator of consumer engagement) across the EU28 countries was around 6 per cent per year for both electricity and gas.5 While it is obvious that switching is not able to solve wider market malfunctions, it is also indisputable that low switching levels translate into little pressure on suppliers to compete on prices and service quality.6 Moreover, the low switching rates clash with the figures showing that in the majority of member states consumers could actually save on bills by switching from the incumbent offers to alternative offers. The amount of potential savings per year significantly varies for households across the EU7 but in general this may be seen as a confirmation of the fact that, as demonstrated by recent research, money is sometimes left on the table.8 Why aren’t consumers responding to a greater extent to the opportunities of a liberalised market? National regulators are nowadays dealing with the same puzzle, and in many cases they are responding with empowerment initiatives. Indeed only the empowered consumer – ‘a consumer with accurate information and the confidence that comes from effective and solid rights’9 – has the ability to search (filling the information gaps) and make sound choices, sending relevant signals to the suppliers and fostering competition.10 However, recent developments have shed more light on the behaviour of consumers featured by bounded rationality11 and other biases, suggesting that regulators cannot always rely on consumers’ ability to make the right decision based on the available information. For example, consumer engagement is sometimes prevented by too much or unclear information. In 2013 the energy regulator in the UK, the Office of

3

The Agency was established in 2010 to complement and coordinate the work of national energy regulators in view of the completion of the single EU energy market. It is located in Ljubljana, Slovenia. 4 Agency for the Cooperation of Energy Regulators and Council of European Energy Regulators, Annual Report on the Results of Monitoring the Internal Electricity and Natural Gas Markets in 2013 (Publication Office of the European Union, 2014). 5 Ibid., p. 69. 6 Citizens Advice, Consumer Challenges 2015 (Citizens Advice, 2015). 7 From €16 in Greece to €378 in Germany for electricity, and from €38 in Romania to €355 in Germany for gas. Agency for the Cooperation of Energy Regulators and Council of European Energy Regulators, Annual Report. 8 C. Waddams (2014), ‘Consumer involvement: frontier or smokescreen?’, Network Industries Quarterly 16(1), 3–5. 9 ICF GHK (2012), ‘Empowered consumers and growth: literature review’, Report prepared for the Department for Business, Innovation and Skills of the UK. 10 Ibid., ii. 11 H. A. Simon, ‘Theories of bounded rationality’, in C. B. McGuire and R. Radner (eds), Decision and Organization: A Volume in Honor of Jacob Marschak (North-Holland, 1972), Chapter 8.

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Gas and Electricity Markets (OFGEM), started a Retail Market Reform with the intention to reduce the unnecessary complexity of the market. In that year, prior to the reform’s remedies coming into force, 54 per cent of consumers could understand tariffs ‘not very much’ or even ‘not at all’.12 The reform aimed at making retail prices ‘simpler, clearer, fairer’ and convincing consumers to shop around for energy, as they normally do for many other goods.13 Further interesting research insights show that sometimes informed consumers are too risk-averse,14 or simply prefer spending their free time in activities other than searching for alternative energy offers.15 Other consumers simply decide that it is not worth their while switching supplier, based on the consideration of the potential gains:16 the expected gains indeed seem to be the most important reason for switching,17 and this is confirmed by the evidence showing that switching rates are positively related to price differentials across member states.18 Another relevant issue is consumers’ lack of trust in the suppliers and in the market. In some cases low trust levels are the result of negative switching experiences: while the majority of consumers are better off after switching, some consumers are equally well-off and some others are even worse off after switching.19 The low level of trust is among the factors that in June 2014 led OFGEM to refer the retail energy market to the national competition authority for investigation, reporting ‘evidence that customer activity in the market is low, and trust is low, which is preventing the process of competition from working effectively’.20 In 2014, 44 per cent of UK household customers distrusted energy companies and did not see them as open and transparent in dealing with consumers.21 Unsurprisingly, in the same period, of all regulated industries, energy got the highest number of calls per day to the Citizens Advice consumer service, with the most common topic of enquiry being billing errors.22 Energy consumption is a complex matter. More effort is required to understand what regulation can do to mitigate the risk of inadequate consumer engagement, and reinforce the role of consumers in the implementation of the EU energy policy. Three elements seem to be key in this regard.

12

Office of Gas and Electricity Markets, Decision to Make a Market Investigation Reference in Respect of the Supply and Acquisition of Energy in Great Britain (OFGEM, 2014). 13 Office of Gas and Electricity Markets, Retail Market Reform – Implementation of Simpler Tariffs Choice and Clearer Information (OFGEM, 2013). 14 Competition and Markets Authority, Summary of Hearing with Centre for Competition Policy (CCP) of the University of East Anglia (CMA, 2015). 15 Ibid., p. 4. 16 Competition and Markets Authority, Summary of Hearing with Professor Stephen Littlechild (CMA, 2015). 17 Competition and Markets Authority, Summary of Hearing with Centre for Competition Policy. 18 Agency for the Cooperation of Energy Regulators and Council of European Energy Regulators, Annual Report. 19 Competition and Markets Authority, Summary of Hearing with Centre for Competition Policy. 20 Office of Gas and Electricity Markets, Decision to Make a Market Investigation Reference. 21 Ibid., p. 17. 22 Citizens Advice, Consumer Challenges 2015. Data from Q3 2014–15.

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First, it seems unlikely that consumers who don’t feel protected, or don’t trust the market, can easily abandon their inertia. Some interesting insights into consumer trust are provided by the Belgian experience. In December 2014 a decision was taken to extend the regulatory mechanism called the filet de sécurité (safety net) for three more years, namely from January 2015 to December 2017. The safety net regulation was introduced for the first time in January 2013, following a period of price freeze. It provides for a stricter control on the supply contracts with variable prices, with indexations allowed only four times per year and only if based on clear and approved parameters.23 The decision to extend the validity of the mechanism was fully supported by both the national energy regulator24 and the national bank.25 According to the two sponsors, the safety net contributed to increase trust and transparency in energy markets, while having no negative impact on the level of competition: on the contrary, ‘the evolution in the market, the switching and the concentration index (HHI) demonstrate that competition in Belgian markets is much stronger nowadays’.26 The Belgian case highlights the possibility for market functioning to improve as a result of increased transparency in the formation of retail prices. The rationale for regulatory intervention here is the risk of consumer detriment in the liberalised market, and the objective is to stimulate a virtuous circle of trust, engagement and enhanced competition. A similar point of view on the need for consumer protection in liberalised markets is shared by the national energy regulator in Italy, where a standard offer price ensures protection to household consumers at risk of detriment, while the empowerment process takes place.27 The standard price is based on market conditions, and therefore does not distort the competition among suppliers.28 Secondly, empowerment initiatives nowadays can benefit from the insights provided by behavioural studies.29 These offer the possibility to better understand consumer biases (in some cases leading to accept sub-optimal outcomes), complement substantive and traditional regulatory actions to create a more

23

Commission de Régulation de l’Electricité et du Gaz, Lignes Directrices Relatives au Gel Temporaire des Indexations des Contrats Variables du Gaz et d’Electricité, (R)120322CDC-1147 (CREG, 2012). 24 Commission de Régulation de l’Electricité et du Gaz, Rapport Relatif au Mécanisme du Filet de Sécurité, (RA) 140626-CDC-1341 (CREG, 2014). 25 Banque Nationale de Belgique, Rapport d’Evaluation du Mécanisme du Filet de Sécurité des Prix de Détail du Gaz et d’Electricité (BNB, 2014). 26 Our translation from French. Commission de Régulation de l’Electricité et du Gaz, Rapport Relatif au Mécanisme du Filet de Sécurité. 27 In 2013, one out of every seven household consumers that had signed a contract with a new supplier decided to reapply for the standard offer price. Autorità per l’Energia Elettrica il Gas ed il Sistema Idrico, Monitoraggio Retail – Rapporto Annuale 2012 e 2013, 42/2015/1/COM (AEEG, 2015). 28 Agency for the Cooperation of Energy Regulators and Council of European Energy Regulators, Annual Report. 29 House of Lords Science and Technology Select Committee, Behaviour Change, HL Paper 179 (SOL, 2011).

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responsive demand,30 and, finally, fine-tune policy intervention. For instance, empowerment initiatives aiming at a change in behaviour and energy savings can be designed more effectively by taking into account the fact that energy consumption, as was found, profoundly varies among the people living in the same household, and that behaviour changes are more easily achieved within the same social group or neighbourhood.31 Finally, the role of consumers as implementers must be considered in conjunction with the issue of vulnerability (officially among the instances of the European Union since the Third Energy Package). The recent perspective contests that vulnerable customers are such because they objectively and permanently belong to a particular social category.32 On the contrary, vulnerability can derive from both individual characteristics and external (market) circumstances, and in any case ‘can manifest itself in a number of ways, such as struggling to manage energy bills, having less choice available, or less ability to make effective choices’.33 Vulnerability might considerably limit the ability of a consumer to engage with the market, therefore it is essential to develop a deeper understanding of the real extent and nature of this issue and address it at EU level.

30

M. G. Pollitt and I. Shaorshadze (2011), ‘The role of behavioural economics in energy and climate policy’, EPRG Working Paper 1130 and Cambridge Working Paper in Economics 1165 (2011), available at www.repository.cam.ac.uk/bitstream/handle/1810/242021/cwpe1165.pdf;js essionid=F01651901A385C501DD1D67EF995E3C0?sequence=1 31 A. Mengolini and J. Vasiljevska, The Social Dimension of Smart Grids, Report EU 26161 (Joint Research Centre of the European Commission, 2013). 32 European Consumer Consultative Group, Opinion on Consumers and Vulnerability (ECCG, 2013); S. M. Baker, J. W. Gentry and T. L. Rittenburg, ‘Building understanding in the domain of consumer vulnerability’, Journal of Macromarketing 25(2) (2005), 128–39. 33 Office of Gas and Energy Markets, Consumer Vulnerability Strategy (OFGEM, 2013).

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THE GROWING IMPACT OF FREE MOVEMENT PROVISIONS IN THE EU ENERGY MARKET Sirja-Leena Penttinen1

INTRODUCTION The very first Treaty framework within what is known today as the European Union was on the subject of energy products. In the 1950s, the European energy sector was seen as an area in which common policies needed to be developed. This was reflected to some extent in the establishment of two founding treaties covering certain aspects of the energy sector. The (now expired) Treaty of Paris, signed in 1951, founded the European Coal and Steel Community. This Treaty was the main tool in ensuring peace and reconstructing postwar Europe by establishing free movement of coal and steel as well as enabling free access to the sources of production of these main energy products. The Euratom Treaty, signed in 1957, founded the European Atomic Energy Community. The Euratom Treaty was initially created to coordinate the member states’ research programmes for the peaceful use of nuclear energy in postwar Europe. Despite the fact that the first treaties regulated the peaceful exploitation of these vital energy sources, the more general instrument for achieving European economic integration, the Treaty establishing the European Economic Community contained not a single word on energy policy. Besides the peace-driven purpose of the very first founding treaties, economic integration was seen as the way to promote (welfare) growth in Europe and the establishment of free movement provisions in particular played a crucial role in this context. 1

Sirja-Leena Penttinen is lecturer in European law at UEF Law School. She is a member of the Centre of Climate Change, Energy and Environmental Law at University of Eastern Finland.

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This chapter provides a short overview of the application and impact of the free movement provisions in the EU energy sector – one of the most important economic sectors of the EU. The next section sets out the most relevant free movement provision in the energy field, and is followed by an overview of the role and impact of free movement law in the energy sector. The final section offers some concluding remarks. FREE MOVEMENT PROVISIONS IN THE ENERGY SECTOR The free movement provisions are provided in the Treaty on the Functioning of the European Union (TFEU) according to which goods, services, persons and capital can move freely in an EU-wide single market area without internal borders. The Court of Justice of the European Union (hereafter referred to as the Court) has held in several occasions in its case law that energy products, such as electricity and gas, are to be treated as goods falling under the scope of free movement provisions on goods.2 According to Articles 34 and 35 of TFEU, quantitative restrictions on import and export trade and all measures having equivalent effect3 shall be prohibited between member states. These articles enable the free movement of energy products within the EU internal market. It should, however, be noted that the cases in which the Court held that energy products fall under the scope of the free movement of goods provisions date back to before the adoption of any of the secondary energy market legislation. Following the different stages of the unbundling requirements,4 it could be argued that energy products are no longer to be treated only as goods. The separate treatment of the commodity itself and the network services could lead to parallel application of the provisions on free movement of goods and services.5 The Court has not, however, taken any stand as to whether the interpretation should be modified to fit the current development phase of EU energy law. From the perspective of free movement law, it is important to note that energy sector transactions involve both commodity movement and capital movement. These movements take place both within the EU and between the EU and third countries. Whereas the other fundamental freedoms are limited only to the intra-EU context, the free movement of capital does not relate only

2

3

4 5

6/64 Costa v. Enel (1964) ECR 585; C-393/92 Almelo (1994) ECR I-1477; C-157/94 Commission v. Netherlands (1997) ECR I-5699; C-159/94 Commission v. Italy (1997) ECR I-5793; C-158/94 Commission v. France (1997) ECR I-5819. The Court has defined the concept of measures having equivalent effect in its case law, according to which ‘[a]ll trading rules enacted by Member States which are capable of hindering, directly or indirectly, actually or potentially, intra-[EU] trade are to be considered as measures having an effect equivalent to quantitative restrictions’ 8/74 Dassonville (1974) ECR 837, para. 5. The movement has taken place from account to ownership unbundling. Similarly, M. M. Roggenkamp and F. Boisseleau, ‘The liberalisation of the EU electricity market and the role of power exchanges’, in M. M. Roggenkamp and F. Boisseleau (eds), The Regulation of Power Exchanges in Europe (Intersentia, 2005), p. 5.

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to the abolition of all restrictions on capital and payments6 between member states: different kinds of capital movements between member states and third countries also fall under the scope of free movement of capital.7 THE GROWING IMPACT OF FREE MOVEMENT LAW IN THE EU ENERGY SECTOR First of all, it should be noted that the scope of free movement law primarily encompasses member states and their actions by comparison with competition law provision which is instead applied to market players. In addition, Treaty provisions on free movement apply only as long as the EU has not used its competence under Treaty articles and has adopted exhaustive harmonisation at the EU level.8 Furthermore, free movement provisions, namely articles on import and export restrictions, apply only to barriers of trade that are not covered by any other Treaty provisions. Barriers resulting from customs duties, taxation or state aid are covered by the respective Treaty articles which constitute lex specialis for those fields.9 Given that the member states are the addressees of the Treaty articles on free movement, very little action was taken in relation to the energy sector at EU level prior to the 1980s even though the realisation of free movement of goods was at heart of the deepening market integration. The energy sector was held to belong strictly to the domain of state sovereignty which complicated the application of free movement rules.10 Energy markets were, to a large extent, characterised by the presence of either state monopolies or national companies with special privileges and close ties to the government controlling the markets.11 Consequently, the role of the state has been at issue since energy was first brought up in discussions in the context of market integration. 6

The Court has held that movements of capital within the meaning of Article 63(1) TFEU include, in particular, (1) direct investments, which enables the shareholder through the holding of shares to participate effectively in the management and control of an undertaking and (2) ‘portfolio’ investments which are characterised as investments in the form of the acquisitions of shares on the capital market solely with the intention of making a financial investment without any intention to influence in the management and control of an undertaking. See, for example, C-282/04 and C-283/04 Commission v. Netherlands (2006) ECR I-9141. 7 After amendments made by the Maastricht Treaty in 1992. 8 See, for example, the recent cases C-573/12 Ålands Vindkraft, judgment of 1 July 2014, not yet reported; C-204 to C-208/12 Essent Belgium, judgment of 11 September 2014, not yet reported. The first energy-related harmonisation measures had no precise legal basis relating to energy. This was not an issue in the early stages as many of the measures were often adopted either under the general harmonisation article (Article 100a EC) or under the environmental competences of the EU – i.e., what is now Article 192(1) TFEU. 9 See, for example, C-313/05 Brzeziński v. Dyrektor Izby Celnej w Warszawie (2007) ECR I-513, Para. 50; C-228/98 Dounias (2000) ECR I-577, Para. 39 and C-383/01 De Danske Bilimportører (2003) ECR I-6065, Para. 32. 10 It was clear from the beginning that energy differs from all other economic sectors due to its vital importance to society in general. This was also noted by the Court in case 72/83 Campus Oil (1984) ECR 2727, Para. 34. 11 For a comprehensive overview, see K. Talus, EU Energy Law and Policy: A Critical Account (Oxford University Press, 2013), pp. 269–86.

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While the functioning of the energy markets in the context of the marketdriven approach has relied to a great extent on the provisions of competition law, free movement provisions have had less impact. This follows naturally from choices made in the past: due to the sector’s special ‘national interest’ nature, it was easier to seek to accomplish the opening of the market on the basis of competition law provisions than on the basis of those relating to free movement, since the former did not interfere directly with issues of state sovereignty. However, the impetus provided by the general Single Market Programme12 also increased the focus on energy. National energy companies were no longer able to rely on the public service obligation provisions (now contained in Article 106 TFEU) and could therefore be exempted from the application of free movement provisions or the general provisions of competition law. In the 1990s the Commission brought infringement proceedings before the Court, claiming that the exclusive rights enjoyed by national champions were contrary to Treaty provisions on the free movement of goods and freedom of establishment and could not be justified on the grounds of public service obligations under what is now Article 106(2) TFEU.13 These were the first free movement related energy cases after Campus Oil and Commission v. Greece,14 which concerned the issue of security of supply. The liberalisation process followed this, relying on secondary legislation. Since then, the process of opening up the markets has relied more on secondary legislation as well as competition law provisions.15 The First Energy Package at the end of the 1990s only introduced the idea of opening up the EU-wide energy market, but the Second Energy Package of 2003 accelerated the move towards a more market-based approach with the help of competition law. The hype surrounding the concept of a market-driven energy sector continued, leaving less room for the application of free movement provisions. Despite the development of sector-specific regulation, it soon became clear that an approach based solely on the market could not fully deliver what was needed. Accordingly, from as early as the Third Energy Package (2007–9) a gradual move began from a purely market-based mechanism towards a mixed regime in which the role of the state and public sector actors is increasingly significant.16 This can 12

The so-called Single Market Programme was launched in the 1980s and included a set of different measures with the view of the completion of the Single Market by 1992. 13 C-157/94 Commission v. Netherlands (1997) ECR I-5699, C-159/94; Commission v. Italy (1997) ECR I-5793; C-158/94 Commission v. France (1997) ECR I-5819. For more on this issue, see S-L. Penttinen, ‘The role of the Court of Justice of the European Union in the energy market liberalization’, in K. Talus (ed.), Research Handbook on International Energy Law (Edward Elgar Publishing, 2014), pp. 251–3. 14 72/83 Campus Oil (1984) ECR 2727; C-347/88 Commission v. Greece (1990) ECR I-4747. 15 An illustration of this is the case COMP/39.351 – Svenska Kraftnät. As the Commission noted, the restrictions on transmission capacities to neighbouring countries could have been assessed under both EU competition law provisions and the free movement provisions (restriction of export trade between member states). As EU competition law can be applied effectively and directly by the Commission, the case focused on violation of Article 102 TFEU (abuse of dominant position) and did not involve any application of free movement provisions. 16 See also European Commission Press Release, 13 November 2008, MEMO/08/743.

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be seen in many areas. It is especially clear in respect of energy (infrastructure) investments as well as in the (desired) increase in renewable energy production.17 However, given the current state of EU energy law where the role of the member states is becoming more supervisory in nature, the Court has received references for preliminary rulings in which the emphasis has been on free movement law rather than competition law.18 These cases have raised the question of whether the secondary law provisions conform to the Treaty articles on free movement. In very recent energy-related judgments the Court has emphasised that the field has not been exhaustively harmonised, which has left room for the application of free movement provisions. Due to the current development phase of EU energy law, it might be reasonable to argue that questions relating to free movement law will increasingly come to the fore, together with questions on the relationships between different market players. CONCLUSION Despite the influential status that free movement provisions have in EU law generally, their impact in the energy sector has been less significant compared to some other economic areas. The main reason for this has been the member states themselves. If market liberalisation in the EU has been struggling due to the reluctance of member states to open their national markets because of fears over national productivity and jobs, the issue is even more acute in a sensitive sector such as energy. Even though the energy market liberalisation has relied heavily on sectorspecific and competition law provision, the increasing need for state control has recently caused cases to be brought before the Court that relate to free movement law. The increasing role of the state does not, however, mean a return to the old pre-liberalisation state of play but instead presents a sort of halfway house situation. This could lead to the re-emergence of free movement law in the energy sector.

17

K. Talus, ‘European Union energy: new role for states and markets’, in A. Belyi and K. Talus (eds), States and Markets in Hydrocarbon Sectors (Palgrave, 2015). 18 See, for example, C-573/12 Ålands Vindkraft, judgment of 1 July 2014, not yet reported; C-204 to C-208/12 Essent Belgium, judgment of 11 September 2014, not yet reported.

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ENERGY, EXTERNALITIES AND THE NEED TO REVISIT DEUTSCHE BAHN: A PROPOSAL TO REVERSE THE EUROPEAN STANCE ON EU STATE AID LAW AND INTERNATIONAL AVIATION Geert van Calster1

In this chapter an argument is outlined that calls upon the Court of Justice of the European Union (CJEU) to reverse its finding in Deutsche Bahn (DB), Case T-351/02.2 Reversal would move the EU towards better internalisation of negative environmental externalities of fossil fuels, and would, I argue, be in line with the EU Treaty. RELEVANT SECONDARY EU LAW AND THE EC’S STATE AID DECISION In DB, the German national railway challenged the Commission’s decision with respect to DB’s complaint that the German exemption from excise duties of aviation fuel led to an unlawful distortion of competition between low-cost airlines and DB’s high-speed trains. The German exemption was carried out in implementation of Directive 92/81 on the harmonisation of the structures of excise duties on mineral oils.3 Under Article 8(1) of the Directive, member states are to be exempt from the harmonised excise duty on, inter alia, ‘mineral oils supplied for use as fuels for the purpose of air navigation other than private pleasure flying’. 1 2

3

Geert van Calster is a Professor in the University of Leuven and Member of the Brussels Bar. Case T-351/02, Deutsche Bahn AG v. Commission of the European Communities (2006) ECR II-1047. OJ (1992) L316/12.

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The Directive was replaced by Directive 2003/96 restructuring the Union framework for the taxation of energy products and electricity,4 which overall leads to a much better integration of environmental concerns in national energy taxation. It does, however, contain a similar proviso with respect to international aviation in Article 14(9)b. Directive 92/81, in Article 8(7), signalled that the exemption may be unwarranted from an environmental point of view: No later than 31 December 1997 the Council shall review the exemptions provided for in paragraphs 1 (b) and 2 (b), on the basis of a report by the Commission and taking account of the external costs entailed in such means of transport and the implications for the environment and shall decide unanimously, on a proposal from the Commission, whether to abolish or modify those exemptions. The exemption provision in the Directive is a direct response to Article 24 of the 1944 Chicago Convention on international civil aviation, which states: Fuel, lubricating oils, spare parts, regular equipment and aircraft stores on board on aircraft of a contracting State, on arrival in the territory of another contracting State and retained on board on leaving the territory of that State shall be exempt from customs duty, inspection fees or similar national or local duties and charges. The International Civil Aviation Organization (ICAO) later5 declared that the exemption also applies to fuel reloading, rather than just to fuel already on board. The exemption included in the Directive is a direct result of the member states wanting to implement the ICAO provision, bearing in mind that were they not to, this would raise international competitiveness concerns (with third states exempting their airlines from duty while the EU might not).6 Sweden had earlier attempted to limit the implications of the Directive by suggesting that the Directive only harmonised taxation triggered by fuel consumption, as opposed to relevant Swedish environmental taxes which taxed the fuel’s environmental externalities in particular CO2 and nitric oxide. The Court disagreed and confirmed Article 8(1)’s direct effect under the Van Gend & Loos criteria.7 No doubt it was influenced by the very fact that the Directive’s review clause appreciates the negative impact the Directive may have on environmental protection. In other words, environmental protection was on the radar of the Directive (even if it utterly ignored it), contrary to the Swedish argument that 4 5

6 7

OJ (2003) L283/51. Resolution of 14 December 1993 Doc 8632- C/968, available at www.icao.int/publications/ Documents/8632_2ed_en.pdf or http://goo.gl/hKqi8E Report from the Commission (on Article 8(1) of Directive 92/81), COM (96) 549, p. 9. Case C-347/97 Braathens Sverige AB v. Riksskatteverket (1999) ECR I-3419: ‘The obligation imposed by Article 8(1)(b) of Directive 92/81 to exempt from the harmonised excise duty mineral oils supplied for use as fuel for the purpose of air navigation other than private pleasure flying may be relied on by individuals in proceedings before national courts in order to contest national rules that are incompatible with that obligation.’

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the environment was out of the Directive’s scope and hence that the member states could not be restricted in regulating the fuel’s environmental impacts. DB’s state aid complaint was rejected by the Commission on the basis that Germany’s exemption was a direct implementation of EU secondary law. The Court then rejected all of DB’s grounds for judicial review and upheld the Commission’s decision. A review of all the arguments for the rejection of DB’s claim is beyond the scope of this chapter, but the most relevant are reviewed in my suggestions below. REVISITING THE ISSUES: A BRIEF OUTLINE OF THE ARGUMENTS International law and the EU Directive DB argued, among other things, that ICAO’s 1944 provisions are lex prior under the rules of the Vienna Convention and were superseded by the subsequent EEC Treaty. And that at the very least for relations between the member states, prior public international law ought not to have an impact. The Court dismissed the pleas brought on the basis of public international law. It held that the EC’s state aid decision was not based on public international law. Rather, the EC had referred to ICAO’s provisions as context, not as content. With respect, however, judicial economy ought not to stand in the way of substantive legality. If there is serious argument as to the incompatibility of public international law with later, or indeed earlier, EU law, then the Court ought to entertain it. Otherwise one risks having illegal EU law being maintained simply on the basis of procedural considerations. The principle of equal treatment – seen in the light of externalities DB argued that the tax exemption for aviation fuel based on Article 8(1)(b) leads to unequal treatment between it and the airlines operating on German domestic routes. Given that the applicant and the airlines offer, on German domestic routes, a service which, in the eyes of users, is substitutable, they are in a comparable situation. Difference in treatment is not objectively justified. The Court rejected comparability of situations on the basis that the situation of air transport undertakings is clearly different from that of rail transport undertakings. As regards their operational characteristics, their costs structure and the regulations to which they are subject, air and rail transport services are very different and are not comparable for the purpose of the principle of equal treatment . . . In the light of the international practice of exempting aviation fuel from excise duties, which is enshrined in the Chicago Convention and in international agreements concluded between States, competition between Community air transport operators and operators in non-member countries would be distorted if the Community legislature unilaterally imposed excise duties on that fuel. Consequently, the exemption provided for by Article 8(1)(b) of the Directive was objectively justified.8 8

Case C-347/97 Braathens Sverige AB v. Riksskatteverket (1999) ECR I-3419, 138–9.

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The CJEU therefore bases its findings that air and rail transport are not comparable mainly on the different regulatory contexts to which they are subject. This is, however, a circular argument. DB’s position was precisely that at the very least some of those differences in regulation are illegal, and it requested that the ECJ discuss those alleged illegalities. A regulator (the EC) can hardly be allowed to get away with unjustified discrimination by making reference to the very regulatory context whose legality is being questioned. Environmental principle, in particular, ‘polluter pays’ The Treaty binds the institutions, including the Commission, to a number of environmental principles which they are pledged to uphold. These principles do not always and in all circumstances grant individuals rights in accordance with the Van Gend & Loos criteria. However, in cases where application of the principles is clearly wanting, or utterly ignored, such as here, it is the CJEU’s duty to uphold them, vis-à-vis both individual Commission decisions and the secondary law which underpins these decisions. The Court has adopted groundbreaking judgments in many areas of EU institutional and economic law, as in Les Verts,9 Rewe (Cassis de Dijon),10 Woodpulp,11 Keck12 and Air Transport Association of America.13 The Court has repeatedly pushed the boat out and in doing so has triggered or strengthened regulatory responses by the European institutions. Were it to reverse its case law in the circumstances at issue, it would propel the discussion on negative environmental externalities and make the EU a true frontrunner in international responses to pressing environmental concerns: the current Directive14 may well provide for more room for member states initiatives in environmentally relevant taxation of energy products. However, under the polluter pays principle, it should arguably be a Treaty obligation for the EU institutions to ensure proper integration of the negative externalities, not merely a possibility for the member states.

9

Case C-294/83, Les Verts v. Parliament (1986) ECR I 1339. Case C-120/78, Rewe v. Bundesmonopolverwaltung für Branntwein (1979) ECR I 649. 11 Joined cases C-89/85, C-104/85, C-114/85, C-116/85, C-117/85, C-125/85, C-126/85, C-127/85, C-128/85 and C-129/85, A. Ahlström Osakeyhtiö and others v. Commission of the European Communities (Wood Pulp) (1994) ECR I 99. 12 Joined cases C-267/91 and C-268/91, Keck and Mithouard (1993) ECR I 6097. 13 Case C-366/10, Air Transport Association of America and Others (2011) ECR I 13755. 14 Note 4 above. 10

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25

RES: TOWARDS A NEW EUROPEAN POLICY Theodore C. Panagos1

INTRODUCTION The economic crisis currently affecting some EU member states resulted in the initiation of a general discussion concerning the revision of the Renewable Energy Sources (RES) Support Schemes throughout the EU.2 These schemes were mainly adopted in order for private entities to be able to run their RES projects with a reduced business risk within the liberalised energy market. The member states adopted such schemes at least fifteen years ago, targeting the quick penetration of RES into their energy mix.3 However, a likely revision has been recently recommended by the Commission and the message seems to be clear that although the RES should be moved to the centre of the energy mix in Europe, they should change from subsidised to competitive models.4 This 1

2

3

4

Dr Theodore C. Panagos is a lawyer by profession, Managing Partner at PFG Law Firm (Athens) and Visiting Professor in Energy Law at the International Hellenic University. He is former Vice-Chairman of the Regulatory Authority for Energy and former Member of the National Energy Council. He has authored books on the legal framework of unbundling in energy, energy markets and hydrocarbons. See Art. 3 of European Parliament and Council Directive 2009/28/EC of 23 April 2009 on the promotion of the use of energy from renewable sources and amending and subsequently repealing Directives 2001/77/EC and 2003/30/EC (2009) OJ L140/16 (RES Dir). See also Art. 3(1) of RES Dir, concerning the mandatory national overall targets and measures and Art. 4, concerning the national renewable energy action plans and Energy Union Package, COM (2015) 80 Final, 25 February 2015. European Parliament Resolution on the Energy Road Map 2050, a future with energy of 14 March 2013 (2012/2103/INI), para. 28 along with Communication from the Commission to the European Parliament, the Council, the European Economic and Social Committee of the Regions, Renewable Energy: a major player in the European energy market (COM (2012) 271 Final, 6 June 2012) and European Commission, Guidelines on State aid for environmental protection and energy 2014–2020, 2014/C 200/01, OJ C200/28-6-2014, paras 107–24.

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chapter examines the issues that may arise from such revision and the relevant future regulatory framework for not having a significant impact on the RES penetration on the one hand, without challenging the actual legal framework and the certainty of law on the other. The development of RES has been at the top of the EU’s strategic choices since the 1990s. Among the main purposes of this initiative were the diversification of the energy sources and materials in order to achieve European security of supply (due to the fact that oil and natural gas were mainly imported from third countries); the protection of the environment; and the growth of regional economies. The diversification of energy sources and the use of RES are becoming more necessary and emphatic following the likely reduction of nuclear energy in Europe as well as the various geopolitical issues that threaten the smooth transmission of natural gas from east to west. Moreover, increased environmental sensitivities in Europe call for more RES capacity rather than the use of polluting carbon and oil power plants. In any case, a low carbon economy remains an EU target.5 Within the framework of the Support Schemes, which were adopted by the member states and ‘blessed’ by the Commission, high feed-in tariffs (FiTs) and long-term power purchase agreements (PPAs) were set out for the RES producers’ compensation. More specifically, the FiTs were usually linked to the cost of construction of the respective parks. The producers’ compensation is mainly recovered from the wholesale electricity market and a levy, usually charged to the consumers. Under these circumstances, the RES are subsidised, as they do not participate in the wholesale market, but they enjoy a mandatory priority access6 (and dispatch) in the electricity systems and are compensated by maintaining a guaranteed price (FiT). Thus, while the RES penetration was proceeding swiftly and the EU was receiving the advantages thereof, the member states were not adjusting the Support Schemes in order to mitigate their economic impacts, especially with the consumer in mind. The lack of such adjustment resulted in economic problems within the budgets of the electricity market operators and consequently delays in payments of the RES producers’ compensation. THE IMPACT OF THE ECONOMIC CRISIS ON THE RES SUPPORT SCHEMES The consequences of the economic crisis in many member states resulted in an additional impact on the construction of further RES projects. In particular, under the pressure of the crisis, the states intervened in the Support Schemes, mainly in FiTs, in order to mitigate the deficits, creating legal uncertainty and thus a loss of security for investors. Moreover, the banking system was reluctant to finance RES projects. In some member states (including Spain, Bulgaria and Greece) the 5

6

See European Parliament Resolution of 15 March 2012 on a Roadmap for moving to a competitive low carbon economy in 2050 (2011/2095 INI). See Art. 16(2)(b) of RES Dir.

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state proceeded with the reduction of FiTs, even for the already signed PPAs. Thus, legal uncertainty was added to the likely violation of both the constitutional provisions of these countries and the provisions of the ECRH.7 The lack of legal certainty along with these interventions created a further delay of RES development as the investors were (and are) reluctant to continue with the construction of the parks. These interventions were instigated usually by the states following the invocation of the circonstances exceptionnelles doctrine. However, it is doubtful whether these measures, touching on the nucleus of fundamental rights, are compatible with the European and national legislation. Furthermore, the reluctance of the banking system was (and is) obviously not only due to the fact that banks do not have adequate funds for the respective finance, but because they also felt (and still feel) unsafe concerning the repayment of financing. TOWARDS A NEW REALITY It does not seem that RES power plants could be utilised in electricity systems in the same way as conventional ones, mainly due to their high volatility and other particularities. If they were to be so used, this would make them non-competitive. For this reason, the regulatory framework should continue granting them a kind of sustainable protection on the following grounds: (1) access priority; (2) minimum guaranteed FiT; and (3) certainty of law. The above aspects are necessary for a new investment in RES to be realised, so that these projects are not exposed to a significant business risk that is not compatible with their nature. In light of the above, a transitional roadmap from the RES subsidised regime to a sui generis competitive one, compatible with the nature of RES, so that RES producers could offer their energy directly in the market, could be based on the following presuppositions. First, the removal of electricity wholesale market distortions, where they exist, is absolutely necessary, so that the system marginal price should reflect at least the average variable cost of the conventional power plants. This will ensure that RES producers will receive fair and reasonable revenue from the market, over time. The Target Model for Electricity would hopefully help towards this direction at a European level. In this regard, a threshold (minimum) of FiT at a European level should be guaranteed by a European mechanism that should be established. The mandatory implementation of every mechanism of additional income as provided for by European legislation8 (that is, green certificates, guarantees of origin) must be supported, so that the impact on the consumer will be diminished. In addition, the activation and intensification of the rest of the mechanisms that could support the cooperation of the member states on further RES development (that is, joint projects, statistical transfers and so on) should be implemented as soon as possible.9 Furthermore, a fair and reasonable fixing of a basic FiT and its premium per RES technology should be determined, in the 7 8 9

The European Convention on Human Rights and in particular its First Additional Protocol. See Art. 15 of RES Dir. See Arts 6 and 7 of RES Dir.

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event that this methodology is implemented. At this point, the priority access of RES should be maintained. Instead of a unilateral mandatory reduction of the FiTs, especially for the photovoltaic technology, member states could proceed towards an initiative for a negotiated reduction, after a period of five to six years from the beginning of their operation, against a reasonable retribution (that is, extension of the duration of PPAs and so on). Finally, a safe regulatory and legal framework should be complied with over time, so that legal certainty is ensured. CONCLUSION The development of RES seems to be a continuous and necessary goal for the energy sector in the EU. The member states should take measures in order to mitigate the impact of the RES Support Schemes on national economies, in particular during the crisis period. However, this must not change the objectives of the general strategy of the EU, which states that RES development is still one of the main pillars of the European decarbonisation energy policy. Given that RES development constitutes a mandatory target, a threshold of RES FiT should be guaranteed at European level through a relevant mechanism during the first eight to ten years of operation. Any likely measures should respect the national and European principles of law and especially constitutional rights.

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26

ENERGIEWENDE IN GERMANY: THE DAWN OF A NEW ENERGY ERA Lutz Mez1

After the reactor disaster in Fukushima the German federal government, the Bundestag and the Bundesrat, decided on the Energiewende. This involves the gradual phase-out of the use of nuclear power plants by 2022 while renewable energy is expanded to become the main part of future energy supply. Already as part of the integrated climate change and energy programme, the federal government has brought in the first packages for a state-of-the-art, secure and climate-friendly energy supply in Germany and at the same time is set on ambitious, intelligent and efficient climate protection measures. Germany is aiming for a sustainable energy system by 2050 and the plan to be one of the most energy-efficient and environmentally friendly economies in the world. This is why saving energy and increasing energy efficiency play a crucial role in this process. Energy transformation, however, does not affect only energy policy. It is a fundamental choice about the social, economic, technological and cultural development of Germany. However, the policy for an Energiewende in Germany was set not in 2011 but several decades previously. This applies to the nuclear phase-out, which is inextricably linked to the changing views on nuclear power after the Chernobyl reactor disaster, as well as for the promotion of renewable energy sources in electricity generation and the constant reduction of energy consumption in all sectors of the economy.

1

Lutz Mez is Professor in Political Science at the Freie Universität Berlin. Since 1984, Dr Mez has been working at the Otto-Suhr-Institute for Political Science. He is co-founder of the Environmental Policy Research Centre and was its executive director until April 2010. Dr Mez is a specialist in comparative analysis of nuclear power, energy and climate change policies.

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THE POINT OF DEPARTURE Germany is one of the largest energy consumers in the world. The consumption of primary energy reached the level of 13.095 petajoules (PJ) in 2014, the lowest figure since German reunification in 1990 when 14.905 PJ were consumed. The impact of energy policy decisions in the years 2010 and 2011 to promote renewable energies and to phase out nuclear energy are visible in the primary energy balance since 2012 by modified shares of various energy sources. In 2014, mineral oil, with a share of 35 per cent, was still the most important energy source, followed by natural gas with a share of 20.4 per cent. Hard coal and lignite contributed 12.6 per cent and 12.2 per cent respectively to the energy mix. Nuclear power accounted for only 8.1 per cent in 2014, compared to almost 11 per cent in 2010. The contribution of renewables reached 11.1 per cent. Other energy sources contributed less than 1 per cent to cover primary energy consumption. Germany relies on petroleum, natural gas and uranium imports, but could obtain its full supply from coal. However, the production of domestic hard coal is possible only at much higher prices than the purchase of imported coal, so that only lignite covers the entire domestic demand. The import quota for oil, gas and coal in 2012 amounted to 98.3, 85.7 and 80.8 per cent respectively. Renewables – hydropower, wind power, biomass and solar energy – count for almost 100 per cent of domestic energy sources. Currently around two-thirds of primary energy consumption is still covered by imports. The share of electricity in final energy consumption is only around 20 per cent in Germany, and it is unlikely that electricity consumption will much higher in the coming decades. Current debate, which focuses mainly on power generation, power consumption and development of electricity prices, does therefore not meet the central problems of the Energiewende. THE ENERGIEWENDE The first steps towards Energiewende took place in the Federal Republic of Germany in September 1973 – shortly before the first oil price crisis.2 The then social-liberal federal government presented an energy programme which for the first time included goal orientations of all energy sources. At the same time, a diversification of energy imports was targeted. The use of regenerative energy sources was first exclusively supported through R&D programmes and later by the construction of test wind turbines. In order to reduce energy consumption for heating and hot water, the federal government set higher standards for thermal insulation and the Ministry

2

The first oil crisis was caused by the Yom Kippur war between Israel and Syria, and the Federation of Arab States, accompanied by the oil embargo of OPEC (Organization of Petroleum Exporting Countries). By throttling oil production, oil prices climbed from $3 per barrel to over $5 per barrel, and in 1974 even further, to over $12 per barrel. The second oil crisis begain in the wake of Iran’s 1979 Islamic Revolution. The loss of oil production in Iran caused the price of oil to soar to over $38 per barrel.

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of Economy launched a campaign entitled ‘Energy saving – our best source of energy’. The term Energiewende appeared in the wake of the second oil crisis in the scientific literature on the future of Germany’s energy supply. In 1980, a study titled ‘Energiewende – growth and prosperity without oil and uranium’ was published by the Öko-Institute. The authors, Florentin Krause, Hartmut Bossel and Karl-Friedrich Müller Reissmann, presented a scenario for the energy supply of the Federal Republic without oil imports and nuclear power plants. This was followed in 1985 by another publication from the Öko-Institute, authored by Peter Hennicke et al. with the title ‘The Energiewende is possible’.3 Here, arguments were developed for the re-municipalisation of energy supply. Local communities should take electricity, gas and district heating supply back into their own hands, so that the lost energy policy impact to the large private energy utilities could be regained and political space recaptured.

Table 26.1 Current figures (2013) and quantitative targets of the Energiewende 2013 Greenhouse gas emissions (compared to 1990) −22.6%

2020

2030

2040

−40%

−55%

−70% −80–95%

2050

Reduction of energy consumption and increase of energy efficiency Primary energy consumption (compared to 2008)

−3.8%

−20%

−50%

Energy productivity (since 2008)

0.2% per year

2.1% per year (2008–50)

Gross electricity consumption (compared to 2008)

−3.2%

−10%

Primary energy demand (compared to 2008)

−5.5%

Heat demand (compared to 2008)

0.8%

−20%

Gross electricity consumption

25.3%

at least 35%

at least 50%

at least 65%

at least 80%

Final energy consumption

12.0%

18%

30%

45%

60%

Heat consumption

9.1 %

14%

Transport sector

5.5%

−25% in the range of −80%

Final energy consumption in the transport sector (compared to 2005) Increase of share of renewable energy

Source: Bundesministerium für Wirtschaft und Energie (BMWi), Die Energie der Zukunft (Monitoring Report) (Berlin, 2014), p. 11.

3

P. Hennicke, Die Energiewende ist möglich (S. Fischer-Verlag, 1985).

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The integrated climate and energy concept, adopted by the federal government in 2007, defined the goals of Energiewende by the year 2050, to be achieved via partial goals for 2020, 2030 and 2040 (see Table 26.1). By 2050, greenhouse gas emissions in Germany should be reduced by 80 to 95 per cent (base year 1990) and the share of renewable energy sources in electricity consumption should reach at least 80 per cent. Improving energy efficiency is the key question in this context, therefore energy consumption should be reduced by half compared to the 2008 figure. Since individual measures often only have limited potential, energy transformation in all sectors – industry, transport, household and the trade and services sector – has to start quickly. THE NUCLEAR PHASE-OUT The nuclear reactor catastrophe of Chernobyl had a decisive influence on the use of nuclear power in Germany. The Green Party, represented in the Bundestag since 1983, asked for the immediate shutdown of all nuclear facilities. Public opinion on this question had been divided since the mid-1970s. In 1986, the situation changed dramatically. Within two years, the proportion of people opposed to nuclear energy rose to over 70 per cent while approval declined to 10 per cent. The position of the Social Democratic Party (SPD) and trade unions changed: all nuclear power plants in Germany should be closed within ten years. Only after the change of federal government in autumn 1998 to a government with the so-called ‘nuclear consensus’ could a fundamental turnaround in German energy policy be achieved. The results of the agreement reached after twenty months of negotiations with the operators of nuclear power plants were, among other things, that the operating licences of the plants should be temporary, and that the construction of new nuclear power plants, as well as reprocessing of nuclear fuel, should be banned. In 2002, the Atomic Energy Act was amended accordingly. For the first time a big industrialised country made a clear decision about nuclear policy: phasing out the use of nuclear power by the year 2023. Although the SPD and the Christian Social Union had different viewpoints regarding this question, the nuclear exit law continued to be in force during the Grand Coalition. After a further change of government in 2009, the government extended operation licences for nuclear power plants. This led to a renaissance of the anti-nuclear movement in Germany, in which the smaller energy utilities took part. In spite of these protests the revised nuclear law entered into force on 1 January 2011. In March 2011, however, just a few days after the nuclear reactor disaster in Fukushima, a moratorium of the oldest nuclear reactors was announced. In June 2011, the federal Cabinet decided on a shutdown of eight nuclear power reactors and the tiered shutdown of the remaining nine reactors between 2015 and 2022. By the end of 2022 all German nuclear power plants have to be inoperative. THE PROMOTION OF RENEWABLE ENERGY SOURCES In Germany, the use of renewable energy underwent a rapid development. Its share of gross electricity consumption rose from 6.8 per cent (2000) to around 25 per cent in the year 2014. By the end of 2014 around 22,600 wind turbines,

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1.22 million photovoltaic systems, 1.66 million solar panels and over 7,500 biogas plants were in operation. The framework conditions for this development were issued mainly at federal level. However, international factors, EU directives, the energy programmes of the federal states and especially regional and local actors also influenced this development. The mechanism of the feed-in tariff for electricity from renewable energy sources was implemented in Germany in the year 1990 as a Parliament initiative in the form of the Stromeinspeisungsgesetz (StrEG). The producers received a minimum compensation of electricity from renewable energy and the utilities were obliged to use this type of power in their network. With the adoption of the Renewable Energy Sources Act (EEG) by the federal government in the year 2000 the StrEG was substantially extended. The EEG supported almost all renewable energy sources, as well as technology and innovation incentives, and continued the purchase obligation, guaranteed feedin tariffs and investment security for the operator. While the StrEG contained no targets, the renewable energy sources’ (RES) share of total energy consumption should have doubled, according to the aim of the EEG, until 2010. The EEG continued the minimum price system from the StrEG for all renewable energy sources, promoting the use of biomass, solar and geothermal energy. As the central control element, the EEG provided compulsory purchase for renewable power on the basis of the amount of electricity generated in a given calendar year. The operators are committed to the recording and compensation of renewables, establishing a nationwide compensation for these payments. The funding instruments for renewable energy have been developed not only in terms of the fundamental transformation of the energy sector, and also not first and foremost to reduce emissions and dependence on imports, but to build a powerful environmental industry. Renewables are part of an energy mix, the aim of which is to ensure energy security and generate new export opportunities. The success of the instruments does not alone depend on the amount of the subsidies or the feed-in tariff. Rather, a number of other conditions and factors help to ensure that the general framework for the expansion is effective. These include the type of approval procedure; the method of financing; tax law and investment security; public opinion and the acceptance by locals and residents of wind turbines or solar energy systems. POLICY TO INCREASE ENERGY EFFICIENCY Energy efficiency is a key factor for a sustainable energy and climate policy. The national energy strategy adopted by the federal government has as its objective that primary energy consumption is reduced 20 per cent by 2020 and 50 per cent by 2050. To achieve these goals, energy efficiency must be constantly increased. An effective energy-saving measure is the thermal insulation of buildings; the use of combined heat and power technology in the power plant sector is an example of improved energy efficiency. Improving thermal insulation in buildings demands that the repair cycles of buildings and houses be

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coordinated and it can therefore not be realised in the short or medium term for all existing buildings; however, the conversion in the power plant sector may be carried out more rapidly. As the efficiency of co-generation plants or smaller, decentralised heat and power plants is significantly higher than in so-called condensation power plants, which produce only electricity, thus also reduces the emission of the greenhouse gas carbon dioxide significantly. Progress made in improving energy efficiency is measured through a monitoring process and evaluated by an expert commission. Essential to the formation of efficiency indicators are current energy statistics and reliable information about the most important influence and reference values of the energy consumption. Relevant benchmarks are population, GDP, production value or gross value added. The use of primary energy per unit of real gross domestic product (GDP) has declined since 1990 by 8.3 GJ/€1,000 of GDP until 2011 on 5.5 GJ/€1,000 of GDP. The total primary energy consumption per capita has fallen even more during this period, from 187 GJ per capita to 163 GJ per capita. But to achieve objectives in the integrated energy and climate concept, energy efficiency must be significantly improved in all sectors. Finally, the Expert Commission, which has reviewed the monitoring reports and the progress made in the Energiewende, submitted its reports in December 2012 and December 2014. The Commission considers that a reinforcement of the current trends is necessary.

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WHAT IS A SUSTAINABLE POLICY? A CASE FOR THE ENERGIEWENDE Gerardo Zarazua de Rubens1

‘Sustainable development [SD] seeks to reconcile development and environmental concerns through policy-making that integrates environmental protection, social justice, and intergenerational equity’.2 Hence the factors that encompass a sustainable policy resemble those of SD as policy-makers must consider: (1) the distributional effects; (2) the time-scale of mechanisms, including intergenerational impacts; and (3) the economic and environmental trade-offs as well as the feasibility and acceptability of the policy mechanisms given the current socio-political context of development.3 Consequently, when generating policy, there is an inevitable questioning with regard to the epistemology and ontology of the policy ideals, in order for policy-makers to determine the moral, economic and SD rationale to address the trade-offs of the policy mechanisms. The phenomenon framed as ‘policy acceleration’ therefore aims to conceptualise the new policy-making systems (such as low carbon economies and energy 1

2

3

Gerardo Zarazua de Rubens is a Research Analyst in energy policy and international energy markets at Cornwall Energy (UK), with previous experience as Logistics Consultant with Kuehne and Nagel Mexico. He holds an MSc with Distinction in Sustainable Development (2014) from the University of St Andrews, UK, and a first degree in International Business (2012) from the Tecnológico de Monterrey (ITESM-CEM), Mexico, that included periods of study abroad at the universities of Nottingham and Exeter. His research has been focused on energy and climate policy, and the governance for low-carbon economies and sustainable development. S. C. Hackett, Environmental and Natural Resources Economics: Theory, Policy, and the Sustainable Society (M.E. Sharpe, 2011), p. 4. R. Gerlagh, ‘Too much oil’, CESifo Economic Studies, 57(1) (2011), 79–102; T. O. Michielsen, ‘Brown backstops versus the green paradox’, Journal of Environmental Economics and Management 64 (2014), 364–76; H. Schlör, W. Fischer and J.-F. Hake, ‘The system boundaries of sustainability’, Journal of Cleaner Production 88 (2014), 52–60.

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transition) derived from the efforts made to alleviate two of the biggest issues humanity is encountering this century: energy security and climate change.4 Here, according to Martin Jänicke that policy must (1) contain ambitious and broadly accepted targets (such as the carbon targets set by countries like the UK and Germany); (2) have a flexible policy mix (fostering technological and systematic innovations); and (3) have a multi-impulse approach (pricing and regulatory mechanisms). Subsequently, policy acceleration states that if such principles are included within the policy mechanisms, the approach can derive in transformative improvements of the system, such as evolution from single feed-in tariffs to reforms based on renewable energy sources (RESs) or from ‘energy efficient heating’ to ‘plus-energy houses’.5 In addition, from the perspective of energy and climate policy, it could be argued that it is necessary to draw the ‘boundaries of the sustainability system’, which are defined as (1) the finite nature of energy resources; (2) the resource’s sustainability; (3) expected demand; and (4) the effects of climate change. The system can be seen as having a weak sustainability which is based on an efficiency strategy to invest the exhaustible resource returns (natural goods) in reproducible capital (such as technology), in order to compensate for the usage of natural stocks and thus keep the total levels of capital stocks in the system constant over time.6 However, the system can be alternatively conceptualised as having strong sustainability, which is based on a consistency and preservation strategy, by rejecting the premise that an artificial world can compensate current ecological losses for future generations. Thus, strong sustainability aims to shape consumption and production patterns, in order to preserve the natural capital goods over time and work within the boundaries of the sustainability system.7 It is noteworthy that these premises – sustainability boundaries and policy acceleration – put a strong emphasis on trans-generational effects. Hence, sustainable policy-making must consider not only the current distributional effects in terms of domestic actors (producers, consumers, the government and environment) or external actors (neighbouring countries); rather, it must also analyse the intergenerational liabilities as to how future generations will bear the current costs of attaining sustainable frameworks of development.8 Consequently, the normative ideals behind a sustainable policy should aim to address current and future distributional effects. From a theoretical perspective, the ‘green paradox’ aims to highlight such trade-off imbalances by demonstrating the issues of climate-friendly policies as 4

5 6 7 8

M. Jänicke, ‘Innovations for a sustainable resource use – reflections and proposals’, Eco-Efficiency in Industry and Science 29 (2014), 235–46; F. Umbach, ‘Global energy security and the implications for the EU’, Energy Policy 38(3) (2010), 1229–40; A. Goldthau, ‘Rethinking the governance of energy infrastructure: scale, decentralization and polycentrism’, Energy Research & Social Science 3(1) (2014), 134–40. Jänicke, ‘Innovations for a sustainable resource use’, 54; Schlör et al., ‘System boundaries’. Schlör et al., ‘System boundaries’. Ibid. H. Welzer, Selbst denken: Eine Anleitung zum Widerstand (S. Fischer, 2013), mentioned in Schlör et al., ‘System boundaries’.

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the consequential present and future impacts of decision-making (of energy producers and consumers), market development, increased carbon emissions and distributional justice.9 Hence, optimal sustainable policy should (1) decrease the cumulative extraction of fossil fuels and (2) shift part of the use of fossil fuels to a later period when CO2 concentrations have passed their peak; this could address the stated ‘green paradox’ trade-offs.10 In consequence, sustainable policy-making must encompass the elements of environmental protection and intergenerational distribution in combination with attaining incremental improvement in social justice and cumulative systemic prosperity, in order to aim for a closer sustainable development framework.11 Within this context, this chapter explores further the conceptualisation and development of a sustainable policy through the analysis of the German Energiewende (‘energy turning point’); since the policy represents the main ‘dominant framework through which Germany conceptualise[s] energy security’12 and a future of climate change alleviation. Hence, its importance is relevant not only in terms of Germany’s domestic decision-making in respect of energy security, but it also important for Europe and the world that ‘Germany gets its Energiewende right’; as the nation is a ‘large microcosm of the EU, and all the issues tackled in the Energiewende are those that its EU partners will, sooner or later, have to tackle’.13 Therefore, it is within Europe’s and the world’s broader interest that Germany, as a pioneer nation, finds affordable, effective and sustainable energy frameworks of development. IS THE ENERGIEWENDE SUSTAINABLE? The Energiewende is based on three major pillars: (1) an increased proportion of RESs; (2) complete nuclear phase-out by 2022 and; (3) energy saving and efficiency and ‘has been [the] staple of German energy policy in one form or another since the early 1990s’.14 The policy ideals are placed within a framework of a ‘goal-oriented multi-impulse strategy’ that uses ‘economic and regulatory core instruments (eco tax, feed-in tariffs, emission trade, but also 9

H.-W. Sinn, The Green Paradox (MIT Press, 2011); Michielsen, ‘Brown backstops’; Gerlagh, ‘Too much oil’; J. Strand, ‘Technology treaties and fossil-fuels extraction’, The Energy Journal 28(4) (2007), 129–42; M. Hoel, ‘The supply side of CO2 with country heterogeneity’, Scandinavian Journal of Economics 113(3) (2011), 846–65. 10 Michielsen, ‘Brown backstops’. 11 Gerlagh, ‘Too much oil’; Michielsen, ‘Brown backstops’; Schlör et al., ‘System boundaries’; Hackett, Environmental and Natural Resources Economics. 12 S. Röhrkasten and K. Westphal, ‘Energy security and the transatlantic dimension: a view from Germany’, Journal of Transatlantic Studies, 10(4) (2012), 328–42, at 335; E. Borden and J. Stonington, ‘Germany’s Energiewende’, in W. Clark (ed.), Global Sustainable Communities Handbook. (Elsevier Inc., 2014), pp. 369–86. 13 D. Buchan, The Energiewende – Germany’s gamble (Oxford Institute for Energy Studies, 2012), p. 5. 14 Röhrkasten and Westphal, ‘Energy security and the transatlantic dimension’, 333; M. A. Schreurs, ‘Orchestrating a low-carbon energy revolution without nuclear: Germany’s response to the Fukushima nuclear crisis’, HeinOnline 14 (2013), 83–108.

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standards) within a broader policy mix’ with the aim to further attain the security of energy supply, economic efficiency and environmental (climate) protection, whilst maintaining the momentum of its industrial-intensive activities.15 Despite its evident success with regard to RES-based developmental capacity, the implementation of the nuclear phase-out and its strong acceptance into the mainstream of political and public arenas, the Energiewende nonetheless appears to not follow normative ideals behind sustainable frameworks of development. This argument is present when analysing Germany’s energy transition under the conceptualisation of the sustainable policy-making discussed earlier in this chapter. The Energiewende, as ‘the German climate policy experiment, has become a success story, both in terms of ecology and economy’, by progressing significantly in terms of energy democratisation, the reduction of CO2 emissions (26.5 per cent below 1990 levels), increasing the share of RES-based capacity (over 22 per cent) and achieving partial (2022 total) nuclear phase-out.16 In addition, Germany has been able to maintain the resiliency17 of its economy (which was set as a key pillar of the transition), by decoupling CO2 emissions from economic growth and sustaining its highly industrial nature.18 Hence, the country has established a roadmap for transitioning into low-carbon energy systems (without nuclear), within the ‘context of an accelerated national transition in a thoroughly industrialized economy’, and thus ‘pushing the world in the direction of cleaner energy’.19 Nonetheless, the Energiewende is a long-term policy and its success should be assessed as such.20 Monetary expenses differ from economic cost where the short-term valuation (such as energy prices or investment costs) do not include the cost of CO2 emissions, nor the speed of transition, and thus can be misleading when assessing the overall success of the Energiewende.21 Additionally, if the transition is considered as a regime 15

Jänicke, ‘Innovations for a sustainable resource use’, 244; F. Umbach, ‘Islands dispute puts spotlight on China’s rare earths strategy’, Geopolitical Information Service (28 December 2012), mentioned in Röhrkasten and Westphal, ‘Energy security and the transatlantic dimension’. 16 Schreurs, ‘Orchestrating a low-carbon energy revolution’; Borden and Stonington, ‘Germany’s Energiewende’; S. Lechtenböhmer and S. Samadi, ‘Blown by the wind. Replacing nuclear power in German electricity generation’, Environmental Science & Policy 25 (2013), 234–41; Röhrkasten and Westphal, ‘Energy security and the transatlantic dimension’; E. Gawel, S. Strunz and P. Lehmann, ‘The German Energiewende under attack: is there an irrational Sonderweg?’, UFZ-Diskussionspapiere (2012), available at www.ufz.de/export/data/global/40438_15%20 2012%20Gawel_Strunz_Energiewende_gesamt_internet.pdf; M. Jänicke, ‘Innovations for a sustainable resource use – reflections and proposals’, Eco-Efficiency in Industry and Science 29 (2014), 235–46. 17 See B. Walker, C. S. Holling, S. R. Carpenter and A. Kinzig, ‘Resilience, adaptability and transformability in social–ecological systems’, Ecology and Society 9(2) (2004), 5. 18 Schlör et al., ‘System boundaries’; Gawel et al., ‘The German Energiewende under attack’. 19 Gawel et al., ‘The German Energiewende under attack’, 3; Schreurs, ‘Orchestrating a low-carbon energy revolution’, 101. 20 Gawel et al., ‘The German Energiewende under attack’. 21 J. Nitsch, T. Pregger and T. Naegle, ‘Erneuerbare in der zukünftigen Energieversorgung – wie sind die Ziele der Energiewende erreichbar?’ Energiewirtschaftliche Tagesfragen, 62(5), 30–7, mentioned in Gawel et al., ‘The German Energiewende under attack’.

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shift,22 the Energiewende can be currently considered as a political success, but the assessment on technological and economic levels would have slower feedback, since ‘[an] energy system’s technological and economic structure does not change at once but rather gradually’.23 Consequently, the achievements of the Energiewende can be potentially outweighed by the negative effects of the transition for example with regard to distributional justice, as there are imbalances created by (1) energy-pricing effects; (2) losses from the nuclear market; and (3) regional implications due to grid offsets by intermittent RES power.24 Moreover, the nature of the Energiewende can ultimately contradict the epistemology of its ideals such as climate change alleviation, since the push for RESbased systems has evidently resulted in short-term increases in fossil fuel-based sources, which can potentially lead to the failure to ‘achieve the federal government’s climate protection goal for 2020’ and eventually 2050.25 In this regard, the Energiewende fails to further address the distributional effects in terms of price and cost allocation across Germany’s economic and social spheres; in addition, its effects go beyond the domestic level and affect the EU and its neighbouring regions. Moreover, the Energiewende raises questions in terms of its intergenerational effects and economic and environmental trade-offs, which can be better explained through theoretical frameworks such as the ‘green paradox’.26 These implications of the Energiewende are a natural result of the epistemological and ontological contradictions behind the ideals of the policy versus those of sustainable development because the applied policy is a ‘goal-oriented multi-impulse strategy’ that lacks a multi-dimensional perspective, as it does not consider subsequent collateral effects of the increased use of fossil-based energy sources on the cumulative levels of CO2 at domestic and international levels. In consequence, it can be argued that the Energiewende may have ‘well-intended’ ideals that hinder ‘perverse effects’, driving Germany into paths of uncertain security and further acceleration of climate change.27 The Energiewende, moreover, cannot solely depend on the initial political consensus and broadly accepted targets, since failure to address further the increasing trade-offs and shift to a more sustainable framework would put at risk the security and stability of the policy. In this regard, the Energiewende must re-evaluate the conceptualisation of its sustainability boundaries with the

22

S. Strunz, ‘The German energy transition as a regime shift’, Ecological Economics 100 (2014), 150–8. 23 K. Araújo, ‘The emerging field of energy transitions: progress, challenges, and opportunities’, Energy Research & Social Science 3(1) (2014), 112–21; Strunz, ‘The German energy transition as a regime shift’, 157. 24 Gawel et al., ‘The German Energiewende under attack’; Michielsen, ‘Brown backstops’; Buchan, The Energiewende. 25 See World Nuclear News, ‘Coal taints Germany’s energy mix’ (6 May 2014), available at www. world-nuclear-news.org/EE-Coal-taints-Germanys-energy-mix-1203141.html; M. Pahle, ‘Germany’s dash for coal: Exploring drivers and factors’, Energy Policy 38(7) (2010), 3431–42. 26 Michielsen, ‘Brown backstops’; Gerlagh, ‘Too much oil’; Sinn, The Green Paradox. 27 Michielsen, ‘Brown backstops’, 364; Röhrkasten and Westphal, ‘Energy security and the transatlantic dimension’.

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aim of diversifying and extending the limitations (considering intergenerational impacts, distributional justice and cumulative CO2 emissions) set by the initial understandings of the transition.28 Thus, it might aim for possible inclusions of stronger frameworks of sustainable development, such as the proposed models by Schlör et al.29 Additionally, the Energiewende could also follow the strong green paradox framework that aims to increase the ‘aggregate welfare effect’ across time, addressing issues such as intergenerational effects.30 Here, the policy would rather be looking at leaving largely unexploited the fossil fuel reserves, as well as mitigating the emissions already released. Therefore, although the Energiewende has shown achievements like ‘emission reductions, renewable energy deployment, job creation, and social acceptance’, this analysis suggests that there is a lack of sustainability in the policy which can result in incremental negative impacts across time.31 In consequence, the German government must reassess the epistemology behind the Energiewende, with the aim of addressing its significant trade-offs. Nonetheless, as Borden & Stonington (2014) mention, the question must continue to be not whether the Energiewende should be implemented, but rather how should the goals of sustainable transition be accomplished?

28

Schlör et al., ‘System boundaries’. Ibid. 30 See R. Gerlagh, ‘Too much oil’, CESifo Economic Studies 57 (1) (2011), 79–102. 31 Borden and Stonington, ‘Germany’s Energiewende’, 385. 29

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THE FINNISH ENERGY POLICY: FULFILLING THE EU ENERGY AND CLIMATE TARGETS WITH NUCLEAR AND RENEWABLES Sanna M. Syri1 and Behnam Zakeri2

Finland is a sparsely populated country of 5.4 million inhabitants and is the northernmost member of the EU, being located almost completely north of the 60° latitude. Its significant energy-intensive export industry developed mainly after World War II. Finland does not have any indigenous fuels other than peat and wood. In Finland, the electricity supply mix is quite balanced, consisting of nuclear power (27 per cent), hydropower (15 per cent), biomass (13 per cent), coal (12 per cent), natural gas (8 per cent), peat (4 per cent), waste (1 per cent), wind (0.9 per cent) and imports (19 per cent) in 2013. The majority of conventional generation is produced in highly efficient combined heat and power (CHP) plants, which also supply heat to all cities in Finland. Since the mid-1990s, Finland has been a part of the joint Nordic electricity market. Finland’s emission reduction target for the domestic sectors (that is, outside the EU emissions trading system, ETS) is -16 per cent from 2005 to 2020.3 The target for renewable energy – an increase from about 26 per cent to 38 per cent4 – is 1

2

3 4

The research fields and expertise of Professor Sanna Syri are energy economics, mitigation of climate change, EU-wide energy and climate policy and electricity markets. She is frequently consulted by the Finnish Parliament to support national-level decisions in environmental and energy policies. She is also a member of the Finnish Climate Panel nominated by the Minister of Environment. Behnam Zakeri’s main focus areas include energy systems models, flexible power generation, high-level integration of renewable energy and energy storage. COM/2008/0017 final – COD 2008/0014 Council Directive 2009/28/EC on the promotion of the use of energy from renewable sources and amending and subsequently repealing Directives 2001/77/EC and 2003/30/EC OJ L 140, 5 June 2009, 16–62.

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one of the highest among the EU27 countries, second only to Sweden and Latvia. In the past, the Finnish government’s energy policy has concentrated on providing reliable and affordable energy to support industrial activity and the Finnish economy in general. The requirement of very deep greenhouse gas emission cuts changes this paradigm. At present, the general aims of the government’s energy policy are the ability to respond effectively to the challenge of climate change mitigation and the ability to support sustainable economic growth, while maintaining a high level of energy security: security of supply at affordable prices, increasing self-sufficiency and efficiency of energy use. The government’s long-term goal is a carbon-neutral society.5 Nuclear energy developed into a significant part of the Finnish electricity supply in the 1970s. Two Loviisa units originally of 440 MW each, owned by former state-owned IVO Ltd (today Fortum Ltd), were commissioned in 1977 and 1980 respectively. In 1978 and 1980, two units of 660 MW were commissioned by the industry-owned TVO Ltd at Olkiluoto. A typical feature for the Finnish energy sector is the active role of energy-intensive industry via shared ownership of large power plants, which provide energy on a cost basis for the owners.6 At the moment, there is one 1,600 MW Areva EPR nuclear reactor under construction at Olkiluoto for TVO Ltd, with estimated connection to the grid in 2018 at the earliest, instead of the originally planned start-up in 2009. Unlike many other EU countries, the increase of nuclear power is a key measure taken in Finland towards a carbon-neutral society. In 2010 the Finnish Parliament gave positive decisions-in-principle to two other new reactors. The aging and decommissioning of present nuclear and conventional plants may favour the addition of new nuclear plants in the future.7 One of the new nuclear power plant licence holders is a new company in Finland, Fennovoima Ltd, which plans a 1,200 MW reactor to be built by Rosatom in Pyhäjoki in northern Finland. The Finnish metals industry and municipal energy companies are the main shareholders of Fennovoima Ltd. In autumn 2014, Fortum Ltd also announced that they are willing to join Fennovoima as part of a restructuring in their Russian power plant ownerships. The other holder of a new licence, TVO, announced in May 2015 that they are not proceeding with the new unit due to the delays experienced with the EPR in Olkiluoto. Biomass is the most significant form of renewable energy in Finland, and forest industry is in a key role in biomass utilisation. Most biomass-based energy production (both electricity and heat) in Finland takes place in connection with the forest industry, using process residuals. There is currently a large interest for biomass-based alternative solid fuels replacing coal in existing CHP plants 5

6

7

Government of Finland. National Energy and Climate Strategy. Report to Parliament on 20 March 2013. S. Syri, V. Satka, T. Kurki-Suonio and S. Cross, ‘Nuclear power at the crossroads of liberalised electricity markets and CO2 mitigation – case Finland’ (2013) En Strat Rev 1. B. Zakeri, S. Rinne and S. Syri, ‘Wind integration into energy systems with a high share of nuclear power– What are the compromises?’, Energies 8(4) (2015), 2493–527.

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of larger cities in Finland as well, but the current low prices of CO2 emissions in the EU ETS are not sufficient to realise these projects, and there is only rather limited support for woodchip based energy production (maximum €18/MWh). However, there is a feed-in premium programme (€83.50/MWh) for biomass gasification, with a €50/MWh heat premium. Based on this, a large-scale gasifier of 140 MW in connection with an existing coal-fired power plant was commissioned in 2012 at Vaskiluoto in the 615 MW coal-fired power plant, which provides 230 MW electricity and 175 MW district heating capacity. From a European perspective, Finland has been slow in promoting wind power. The first feed-in tariff for wind power came into force in 2011. It is a premium system with €83.50/MWh for twelve years, with a quick starter’s level of €105.3/MWh until the end of 2015. The upper limit of the system is 2,500 MW total capacity. The feed-in tariff has created a large interest among project developers: a total of 11,000 MW of projects is currently under planning and development. However, progress in building has been unexpectedly slow. By the end of 2014, the total installed capacity was 627 MW in Finland. The reason for this slow realisation lies mainly in slow licensing processes: projects are delayed significantly due to such things as citizens’ complaint processes and restrictions posed by the radar operation requirements of the Finnish military. Out of the total 11,000 MW of planned wind projects, around 3,000 MW are offshore projects, and they are very unlikely to be built without separate higher support.8 In 2013, the government announced a €20 million bonus for the first offshore wind demonstration project, and the 40–4 MW project of Suomen Hyötytuuli Ltd outside Pori city won the competition. In the future, the combination of large shares of nuclear power and wind energy may pose challenges for the Finnish electricity system. Initial studies indicate that this would be manageable if the transmission capacity could be optimally employed, or by adopting power-to-heat and energy storage systems.9 However, the fact that the other Nordic countries also have ambitious plans to boost the share of wind power intensifies the management challenge of high-level wind integration. In the domestic sector, that is, heating, transport, waste management, forestry and agriculture, CO2 emission reductions by 2020 and 2030 are challenging and in most cases considerably more expensive than reductions in the ETS sectors.10 In waste management, cheap reduction measures, such as methane capture at landfills, were taken earlier. The current trend is the energy use

8

O. Salo and S. Syri, ‘What economic support is needed for arctic offshore wind power?’, Renewable and Sustainable Energy Reviews 31(3) (2014), 343–52. 9 B. Zakeri, S. Syri and S. Rinne, ‘Higher renewable energy integration into the existing energy system of Finland – Is there any maximum limit?’ Energy 92(3) (2015), 244–59; S. Rinne and S. Syri, ‘The possibilities of combined heat and power production balancing large amounts of wind power in Finland’, Energy 82 (2015), 1034–46. 10 A. Hast, T. Ekholm and I. Savolainen, ‘Meeting emission targets under uncertainty – the case of Finnish non-emission-trading sector’, Mitigation and Adaptation Strategies for Global Change 18(5) (2013), 637–58.

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of waste, and new combustion plants, typically providing heat and electricity, are being built in all major cities. The amount of transport is growing in Finland: total road transport mileage, for example, grew by one third during 1995–2011.11 The main contribution to statistical reductions in transport CO2 emissions comes from the fulfilment of the EU blending requirements of biofuels. In addition, Finland has set a more stringent national transport biofuel requirement than EU legislation: 20 per cent of transport fuels by 202012 to support the Finnish second-generation forest residues based biofuels industry; some of the biofuel plant projects, however, have recently been cancelled due to profitability problems.

11

Finnish Transport Agency, ‘Transport statistics 2011’, Finnish Transport Agency Statistics 2 (2013). 12 Finlex Law on advancing biofuels in transport 13 April 2007/446

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THE EU–RUSSIA RELATIONSHIP AND THE EU ENERGY UNION: FROM DEPENDENCE AND VULNERABILITY TOWARDS COMPETITION AND A FREE FLOW Marek Martyniszyn1

The EU–Russia relationship is characterised by co-dependence in various areas, including in that of gas trade. On the EU side, the member states to a varying degree are dependent on Russian gas imports. Some (Bulgaria, Estonia, Finland, Latvia and Lithuania) used to fully rely on Russian gas. Overall, Russian gas amounts to about one-third of EU’s gas imports and a quarter of its consumption.2 The EU’s dependence on Russian gas is reinforced by the nature of gas trade and the poor infrastructure. The majority of gas is still transported through pipelines. In Central and Eastern Europe most of them run from east to west, with few interconnections and limited storage capacity. While globally the trade in liquefied natural gas (LNG) is on the rise, until recently in the EU’s Central and Eastern member states (including Finland) there was no single LNG terminal capable of receiving LNG.3 Therefore, Gazprom – the state-controlled 1

2

3

Dr Marek Martyniszyn is a Lecturer in Law at Queen’s University Belfast. He specialises in the international and transnational aspects of competition law and policy, including the limits of extraterritorial jurisdiction and the issue of state involvement in anticompetitive practices. In broader terms, his research interests lie in international economic law. Before joining the School of Law at Queen’s University Belfast, Dr Martyniszyn was a Senior Research Fellow in the Institute for Consumer Antitrust Studies at the Loyola University Chicago School of Law. He holds a PhD degree from University College Dublin (Ireland) and an LLM from the European Institute of the Saarland University (Germany). ENI, ‘O&G: world oil and gas review’ (2012), available at www.eni.com/world-oil-gasreview-2012/static/pdf/wogr-2012.pdf See Gas Infrastracture Europe, ‘Gas LNG Europe’ (June 2014), available at www.gie.eu/download/maps/2014/GLE_LNG_JUNE2014.pdf

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firm enjoying a monopoly on Russian gas exports – had considerable leverage over some member states, which may be unable in the short or even medium term to switch to other suppliers or energy sources. On the other side, Russia exports its gas almost exclusively through pipelines.4 Due to the cost and time involved in pipeline construction, Russia is dependent on its current foreign gas customers. As half of Russian gas exports flow to Europe,5 in the short and medium term Russia may not be able to sell the ‘European’ gas elsewhere. Moreover, a significant part of Russian federal budget revenues come from hydrocarbons exports. The scale of reliance on such revenues suggests that ‘a reduction in natural gas sales would be politically catastrophic’.6 Furthermore, Russia operates a multi-tier pricing for gas. Domestic prices are regulated and set below cost.7 Gazprom, which is responsible for about 70 per cent of Russia’s total gas production, is able to cross-subsidise. It uses export profits to cover the domestically generated losses, and still generates profits to fill state coffers. A significant increase in domestic gas price could destabilise the industrial sector and may have a significant impact on the population. In effect, Russia relies on its gas sales to Europe. The relationship is one of co-dependence. Simultaneously, while Russia needs its European gas sales, it does not seem dependent on sales to a particular country (except for Germany, Russia’s most important customer). So long as Russia is able to negotiate deals with individual states – not the EU as a whole – it enjoys considerable bargaining power. This makes it possible to use gas exports for other purposes also. In fact, prices for Russian gas differ greatly across the EU without a clear economic reasoning justifying the differences.8 Moreover, it is well-established that Russia has used its energy lever for strategic foreign-policy aims multiple times in the past.9 In this context, in November 2013 the European Commission opened formal proceedings against Gazprom.10 The Commission was concerned that Gazprom might be abusing its dominant position on gas supply markets in certain member states, in breach of EU competition law. In particular, three types of possible 4

Russia opened its first and only LNG export terminal in 2009. Gazprom, ‘First Russian LNG plant launched in Sakhalin’ (18 February 2009), available at www.gazprom.com/press/news/ 2009/february/article64569 5 M. Assenova, ‘Russian energy review in 2012: consolidating state control in an uncertain market’, Eurasia Daily Monitor (18 January 2013), available at www.jamestown.org/ single/?no_cache=1&tx_ttnews[tt_news]=40333&tx_ttnews[backPid]=620#.UhtkEj_pww4 6 A. Tucker, ‘The new power map: world politics after the boom in unconventional energy’, Foreign Affairs (19 December 2012), available at www.foreignaffairs.com/print/135945 7 Gazprom, ‘Setting fair gas prices in Russia to boost domestic economy’ (22 April 2014), available at www.gazprom.com/press/news/2014/april/article189315 8 See the graph of alleged Russian gas prices provided by Izvestia, available at http://izvestia.ru/ news/544100 9 See, for example, a study by Larsson from the Swedish Defence Research Agency: R. L. Larsson, ‘Russia’s energy policy: security dimensions and Russia’s reliability as an energy supplier’, FOI-R–1934–SE (2006), available at http://storage.globalcitizen.net/data/topic/knowledge/ uploads/20110731213514705.pdf 10 European Commission, IP/12/937, ‘Antitrust: Commission opens proceedings against Gazprom’ (4 September 2012), available at http://europa.eu/rapid/press-release_IP-12-937_en.htm

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anticompetitive practices are under scrutiny: (1) the use of ‘no resale’ clauses in supply contracts, which may be hindering the free flow of gas in the EU; (2) the prevention of the diversification of gas supplies; and (3) the imposition of unfair pricing by linking oil and gas prices in long-term contacts.11 In a sudden reaction, only a week after the opening of the proceedings the Russian President issued a blocking order, negatively affecting foreign enforcement efforts in all cases of Russian strategic enterprises, including Gazprom.12 Most likely due to the developments in Ukraine, the Commission’s proceedings were put on hold. Against this backdrop, the ongoing Ukrainian crisis further exposed the EU’s import dependence and vulnerability, with Russia threatening to cut off gas supplies over the winter. Unexpectedly, this situation created an opportunity by providing a much-needed stimulus to unite the EU on the energy issue. In April 2014 Donald Tusk – now President of the European Council, but at the time Polish Prime Minister – called for an Energy Union to be created.13 He proposed founding it on six principles. First, the EU was to develop a mechanism for jointly negotiating energy contracts with Russia. Tusk suggested having a single European body charged with buying gas, in order to ‘confront Russia’s monopolistic position’. He proposed its implementation in stages. First, bilateral agreements were to be stripped of any market-distorting clauses. Second, a template gas purchase contract was to be developed. Third, the European Commission was to take part in all new gas purchase negotiations. Five other principles suggested by Tusk related to mechanisms guaranteeing energy solidarity in case of cut-offs; the expanding of the EU’s energy infrastructure in both interconnections and storage capacity; making full use of the existing fossil fuel resources; and reaching out to new gas suppliers. Tusk’s proposal built on a similar plea by Jerzy Buzek, then the President of the European Parliament, and Jacques Delors, one of the ‘fathers of Europe’, who had already, in 2010, called for the creation of a European Energy Community.14 They also recommended that the EU have ‘a single interface’ in relations with both the energy producer and transit countries and stressed the need for the EU to be able to pool its supply capacities and to ‘engage in coordinated energy purchasing’.15 11

A. Riley, ‘Commission v. Gazprom: the antitrust clash of the decade?’ (CEPS Policy Brief No. 285, 2012), 8–10, available at www.ceps.eu/ceps/dld/7433/pdf. For more on the broader geopolitical context of this case see also M. Martyniszyn, ‘The EU’s case against Gazprom is about far more than business’ (24 April 2015), available at https://theconversation.com/the-eus-caseagainst-gazprom-is-about-far-more-than-business-40773. 12 M. Martyniszyn, ‘Legislation blocking antitrust investigations and the September 2012 Russian Executive Order’, World Competition 37(1) (2014), 103–19. 13 D. Tusk, ‘A united Europe can end Russia’s energy stranglehold’, The Financial Times (21 April 2014), available at www.ft.com/cms/s/0/91508464-c661-11e3-ba0e-00144feabdc0.html 14 J. Buzek and J. Delors, ‘Towards a new EEC’ (5 May 2010), available at www.europarl.europa. eu/meetdocs/2009_2014/documents/envi/dv/815/815663/815663en.pdf 15 Buzek was actively promoting the idea of joint or coordinated gas purchases among the chiefs of the EU’s gas companies. See J. Buzek, ‘Buzek makes case for gas purchases coordination in EU with energy CEOs’ (20 April 2011), available at www.sitepres.europarl.europa.eu/president/ de-en/press/press_release/2011/2011-April/press_release-2011-April-15.html

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The idea of the Energy Union has been embraced by the new European Commission, led by Jean-Claude Juncker, who became the new Commission’s President in November 2014. Juncker has identified it as one of his top priorities.16 In February 2014 the European Commission published its vision – a framework strategy for the creation of an Energy Union.17 The Commission has already invested considerable political capital into this project. Maroš Šefčovič, the Commission’s Vice-President responsible for the Energy Union, described this initiative as ‘the most ambitious European energy project since the Coal and Steel Community’.18 The Commission framed the presented strategy around five dimensions and fifteen action points. The first of the identified dimensions is ‘energy security, solidarity and trust’. It encompasses the diversification of supplies, in terms of sources, suppliers and routes. The strategy also talks about assessing options for a voluntary demand aggregation mechanism for the collective purchasing of gas ‘during a crisis and where Member States are dependent on a single supplier [emphasis added]’.19 The fact that only voluntary schemes are envisaged means that the Commission is not currently considering proposing the creation of some sort of a central gas purchasing agency, or state-mandated arrangements. The Commission also provides that any voluntary arrangements would need to be compliant with EU competition rules and World Trade Organization law. This clarification is important as such mechanisms may be also described as buying cartels, which may raise competition concerns, if they were capable of exerting sufficient market power.20 The European Commission proposes also ex ante compliance checks with EU law of any proposed intergovernmental agreements between member states and third countries, in relation to energy supplies, gas in particular. In the Commission’s view its participation in such negotiations and development of standard contract clauses can help ‘avoid undue pressure and ensure respect of European rules’.21 16

J.-C. Juncker, ‘A new start for Europe: my agenda for jobs, growth, fairness and democratic change. political guidelines for the next European Commission’ (15 July 2014), available at http://ec.europa.eu/priorities/docs/pg_en.pdf 17 European Commission, ‘Energy Union package: a framework strategy for a resilient Energy Union with a forward-looking climate change policy’, COM(2015) 80 final (25 February 2015), available at http://ec.europa.eu/priorities/energy-union/docs/energyunion_en.pdf 18 European Commission, IP/15/4497, ‘Energy Union: secure, sustainable, competitive, affordable energy for every European’ (25 February 2015), available at http://europa.eu/rapid/press-release_ IP-15-4497_en.htm 19 European Commission, ‘Energy Union package: a framework strategy’, 6. 20 It is noteworthy that the EU’s interest in collaborative purchasing is not unique. Various Asian countries, which absorb a large part of global LNG exports, are considering such schemes in order to secure better contract terms and pricing. The first joint purchases have already taken place. For example, in 2014 Korea Gas Corporation (KOGAS), reportedly the world’s largest LNG buyer, teamed up for a joint gas purchase with Japan Oil, Gas and Metals National Corporation (JOGMEC). J. Chung, ‘Japan firm buy gas together; more joint deals to come’, Reuters (24 March 2014), available at http://reut.rs/1gsxphc 21 European Commission, ‘Energy Union package: a framework strategy’, 8.

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The framework strategy is comprehensive. For example, it outlines actions which need to be taken in order to fully integrate the European energy market, and it underlines the importance of measures aimed at improving energy efficiency and its contribution to the moderation of demand. In order to deliver on its promise, the Commission also outlined fifteen interlinked action points. The first provides that ‘full implementation and strict enforcement of existing energy and related legislation is the first priority to establish the Energy Union’. As is further clarified, the Commission will take action to endure that the member states fully implement energy legislation and it will be strictly enforcing EU competition law in this area.22 This is an important declaration and it echoes a recent signalling by the EU’s Competition Commissioner of the readiness to ‘move forward’ with the pending antitrust investigation of the Gazprom practices.23 Indeed, in April 2015 the Commission issued a Statement of Objection to Gazprom, formally outlining the charges.24 Whether the EU’s Energy Union materialises depends on the political commitment of the member states and the EU institutions. The circumstances are favourable. In recent years the dependence pendulum has swung in the EU’s favour. The growing exploitation of shale gas in the USA and the growth in LNG trading contributed to lower prices (of coal also), facilitating necessary adjustments. Lithuania opened its first LNG terminal. Another terminal is close to completion in Poland. First, much-needed cross-border interconnections are operational (Poland-Czech Republic, Slovakia-Hungary) and more are being worked on.25 Moreover, the EU has started using reverse gas flow. It is now possible to, for example, pass Russian gas originally sent to Germany via the North Stream, to Poland or Italy, if need be. Finally, member states have recently demonstrated respect of EU law in the context of the planned South Stream pipeline. While Russia concluded bilateral agreements with a number of member states in that regard, the European Commission found them in breach of EU law and the project was ultimately abandoned. The outlined framework strategy constitutes a very ambitious multidimensional project, both economically and politically. The EU’s single market is not yet complete. The delivery on the Energy Union promise would be an important step towards its completion. European integration started from the ashes of World War II and the founders of what is now the EU pragmatically

22

Ibid., 19. ‘Vestager: Commission ready to move forward with Gazprom probe’, EurActiv (19 February 2015), available at www.euractiv.com/sections/energy/vestager-commission-ready-move-forward-gazpromprobe-312250 24 European Commission, IP/15/4828, ‘Commission sends Statement of Objections to Gazprom for alleged abuse of dominance on Central and Eastern European gas supply markets’ (22 April 2015), available at http://europa.eu/rapid/press-release_IP-15-4828_en.pdf 25 See the infographic in ‘Conscious uncoupling’, The Economist (5 April 2014), available at www. economist.com/news/briefing/21600111-reducing-europes-dependence-russian-gas-possiblebutit-will-take-time-money-and-sustained 23

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began with economic integration, which was to have and indeed has had spillover effects beyond economics. A more interconnected and competitive single energy market would bring the EU’s citizens more prosperity and it would also, by addressing unbalanced import dependence, contribute towards cementing peace, which – as the ongoing Ukrainian crisis blatantly shows us – should not be taken for granted.

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THE ROLE OF UNCERTAINTY IN ENERGY INVESTMENTS AND REGULATION Luis M. Abadie1 and Joseph V. Spadaro2

INTRODUCTION An increasing number of energy investments may be significantly affected by regulation, either positively or negatively. There is uncertainty concerning future cash flows under current regulations, and uncertainty also in regard to the possibility of regulatory changes. Given the current economic circumstances and legal situation, firms will seek to attain suitable risk and profitability profiles taking into account certain strategies such as the possibility of diversification. But managers usually have some flexibility in their management actions that enables them to make decisions depending on circumstances. In certain circumstances the decisions may be contrary to the 1

2

Luis M. Abadie is a Research Professor in the Basque Centre for Climate Change (BC3) in Bilbao, has a PhD in Economics (University of the Basque Country UPV/EHU, 2007) and is a graduate in Industrial Engineering (UPV/EHU, 1979) and in Computer Science (University of Deusto, 1985). He has extensively published in the fields of energy and climate change. His main research fields are energy economics, carbon markets, greenhouse gas emissions, real options and financial economics. Luis is grateful for financial support received from the Fundación Repsol under the Low Carbon Programme (www.lowcarbonprogramme.org), and acknowledges the financial support received from the Basque Government under project GIC12/177-IT-399-13. Joseph Spadaro is an Environmental Research Scientist with a PhD in Energy from the Ecole Nationale Supérieure des Mines de Paris, France. He is presently Research Professor at the Basque Centre for Climate Change (BC3) in Bilbao, Spain, where he has been involved in several projects funded by the European Commission, including the PURGE Project, in the role of senior scientific investigator at BC3, and the BASE Project, leading the work on the impact assessment of climate extremes and human health. In addition to ongoing work on air pollution, his interests include research on the nexus between prioritisation of long-term techno-economic options in support of urban climate adaptation and clean air policies; the reduction of health vulnerability; and ways to bring about changes in consumer attitudes and consumption patterns related to energy use, household purchases and diets. He is co-author of the book How Much is Clean Air Worth? Calculating the Benefits of Pollution Control (Cambridge University Press, 2014).

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purposes for which energy and climate policies were designed. It is therefore necessary to take into account the potential effects of uncertainty on investments, and to determine under what circumstances the effects desired by legislation would not be achieved. Classic publications on valuation under uncertainty include Dixit and Pindyck (1994)3 and Trigeorgis (1996).4 With regard to valuation under uncertainty of investments in energy assets, readers are also referred to Abadie and Chamorro (2013).5 Project uncertainty can affect both investors and potential lenders, because it can open up the possibility that the project could default and only a portion of the initial investment might be recovered. In this case there are also other factors that affect the risks to lenders, such as the loan-to-value ratio and the expected value. Managers who decide to make and subsequently manage an investment have various options to: (1) choose the optimum time for investment and (2) manage the investment by making the optimal choice between expansion, contraction, temporary delay and abandonment. This can also include consideration of interactions with other competitors and how they might behave. UNCERTAINTY IN THE ENERGY SECTOR Energy policy is often designed considering a single or a limited number of scenarios, whose effectiveness often depends on the degree of compliance of the most probable scenario. Many policies would be effective for low uncertainty, as is the case for renewable energy (RE) of the constant feed-in tariff type that proved to be the most successful scheme, as reported in IRENA (2012).6 Frameworks of this type can provide price certainty in the long term, thus reducing uncertainties for investors in RE. Flexibility gives managers many options, but this in itself may result in energy policy objectives not being met. A case on record is that of ethanol production in Brazil.7 When world sugar prices rose to high levels in 1998, sugar cane manufacturers switched from ethanol production to sugar. The shortage of ethanol led to an increase in the sales of petrol cars and therefore negatively impacted Brazil’s ethanol production policy. However, with the introduction of the flexfuelled vehicle in 2003, which now dominates the car sales market, the ethanol production industry in Brazil has been revived.8 The recent success of the flexfuelled car has resulted in an increase of ethanol production and consumption, 3

A. K. Dixit and R. S. Pindyck, Investment Under Uncertainty (Princeton University Press, 1994). L. Trigeorgis, Real Options: Managerial Flexibility and Strategy in Resource Allocation (MIT Press, 1996). 5 L. M. Abadie and J. M. Chamorro, Investment in Energy Assets Under Uncertainty (SpringerVerlag, 2013). 6. IRENA – International Renewable Energy Agency (2012). Financial Mechanisms and Investment Frameworks for Renewables in Developing Countries, available at www.irena.org/DocumentDownloads/Publications/IRENA%20report%20-%20Financial%20Mechanisms%20for%20 Developing%20Countries.pdf 7 C. L. Bastian-Pinto, L. E. T. Brandão and W. J. Hahn, ‘Flexibility as a source of value in the production of alternative fuels: the ethanol case’, Energy Economics 31(3) (2009), 411–22. 8 C. L. Bastian-Pinto, L. E. T. Brandão and M. L. Alves (2010), ‘Valuing the switching flexibility of the ethanol-gas flex fuel car’, Annals of Operation Research, 176, 333–48. 4

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which has proven to be a great energy policy success. The uncertainty in this case has therefore had a beneficial influence on technological development. On the other hand, in Europe the allowances price of the European Union Emission Trading Scheme (EU ETS), where a cap is set on the total amount of greenhouse gas emitted, resulted in very low prices due to excess emission allowances, which was further exacerbated by a fall in the demand for energy due to the economic crisis. The combination of low prices and high volatility provides little incentive to promote energy efficiency investments. Figure 30.1 shows the historical volatility of CO2 allowances (a measure of the standard deviation between returns). The increase in volatility reflects sharp drops in spot prices followed by increases back to levels similar to those previously recorded. A similar volatility in SO2 emission allowances was observed in the United States following the widespread installation of flue gas desulphurisation systems in the power industry.9 OIL INDUSTRY Factoring uncertainty into analysis may result in changes in regulations. Dias and Rocha10 describe a case in which they analyse the extendible options in

Figure 30.1 Volatility of CO2 emission allowances, European spot market, January 2013−December 2014 (fifty-day moving average) 9

C. De Jong, A. Ooterom and K. Walet, ‘Dealing with emissions’, in V. Kaminski, Managing Energy Price Risk, 3rd edn (Risk Books, 2004), pp. 373–93. 10 A. G. Dias and K. Rocha, ‘Petroleum concessions with extensible options using mean reversion with jumps to model oil prices’. Working Paper presented at the 3rd Annual International Conference on Real Options, the Netherlands (1999).

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petroleum in 1998, when the National Petroleum Agency (ANP) proposed an exploration period of just two years, with an extension of three more years (that is, five years in total). Oil companies, however, considered the five-year exploration period impractical, especially when deep-water oil exploration ventures were involved. The numerical simulations by Dias and Rocha suggest rather that the optimal timing policy should be between eight and ten years. On the basis of their work, ANP later rescinded its initial proposal and decided instead on a nine-year exploration period. Investment decisions in a state of uncertainty depend on a trigger price. Oil volatility can influence an investor’s decision to go ahead if the oil price is above the trigger value. Similarly, if the oil price is below other threshold price levels, the initial investment might be either abandoned if the investment is seen as unprofitable, or temporarily mothballed in the hope that future returns might become profitable. This was certainly the case when the oil market depreciated by as much as 50 per cent during the second half of 2014, although this would have been a highly unlikely scenario at the beginning of 2014. As depicted in Figure 30.2, oil price volatility has led to lower prices, which in turn have resulted in industry layoffs and lower investment in future production.

Figure 30.2 Volatility of oil prices Source: Own work from US Energy Information Administration data (www.eia.gov/dnav/pet/ pet_pri_spt_s1_d.htm).

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RENEWABLE PORTFOLIO STANDARD POLICIES IN US ELECTRIC UTILITY INDUSTRY A Renewable Portfolio Standard (RPS) requires that electric utilities procure a certain percentage of their electricity from renewable energy sources, such as wind, solar and biomass. In the US, the percentage requirement varies by state. The impact of regulatory uncertainty on renewable energy investment has been analysed by Fabrizio,11 who found that the benefits of RPS enactment on investments in renewable generation assets was greater in those states where the regulatory uncertainty was perceived to be lower. CARBON CAPTURE AND STORAGE Regulatory stability is necessary to foster the development and deployment of low-carbon technologies. Investment projects in carbon capture and storage (CCS) technology, for example, are presently unjustified given the lack of specific government policies to promote this type of technology, and because of the unfavourable market conditions and volatility of CO2 emission rights.12 The US Department of Energy decided recently to abandon its involvement in the CCS FutureGen project, which was supposed to be the first commercial-scale power plant in the United States to sequester its own CO2 emissions. Lack of clarity of long-term regulatory policies in support of a stable carbon price was blamed for the final decision taken. Sequestering CO2 costs money, and as long as companies are allowed to vent the gas for free into the atmosphere, there is no financial incentive for them not to do so. NUCLEAR POWER INDUSTRY Regulatory certainty is the largest barrier to investment in low-carbon technologies in the European energy sector. The EC’s recent decision to reduce by 40 per cent greenhouse gas emissions by 2030 relative to 1990 levels is an attempt to outline a legal framework, and to encourage investor certainty on the direction in which energy policy is heading in Europe. In the case of nuclear energy, other than economics, the markets look for long-term certainty on price, stability of governmental policies and regulatory procedures, industry reputation, environmental corporate responsibility and public acceptance. Government backing, for example, through appropriations and cost-sharing programmes, could lead to rapid development, licensing and finally deployment of new nuclear technologies. According to the nuclear energy institute (NEI), located in Washington, DC, the US should develop a regulatory roadmap and build a national testbed facility to support demonstration-scale advanced design reactors. Getting a head start on

11

K. R. Fabrizio, ‘The effect of regulatory uncertainty on investment: evidence from renewable energy generation’, The Journal of Law, Economics, and Organization 29 (2012), 765–98. 12 L. M. Abadie and J. M. Chamorro, ‘European CO2 prices and carbon capture investments’, Energy Economics 30 (2008), 2992–3015.

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licensing would increase the likelihood of operational certainty, thus improving the chances of ensuring market capital to build commercial-scale plants. On the matter of plant useful lifetime, licence extensions beyond sixty years would financially justify mid-life refurbishing costs, allowing amortised plants to continue to generate cheap electricity. EXPROPRIATION RISK One of the most significant aspects of investment under uncertainty is expropriation risk in natural resources. In this case, when a natural resource project exposed to expropriation risk, in particular an oil field, is valued, the government can be seen as holding an option to expropriate the oil field, as occurred when the government of Argentina expropriated Repsol-YPF. Expropriation risk is studied by Schwartz and Trolle.13 These authors point out that a state that exercises its option to expropriate all the benefits of exploitation nevertheless faces certain costs such as less efficient production, potential compensation payments and reputational costs. CONCLUSION A failure to factor uncertainty into energy policy can prevent it from achieving its initial goals. Events that seem highly unlikely can actually happen much more frequently than expected, as happened with the fall in oil prices in 2014. The effects of uncertainty and its impact on investment need to be considered by regulators at the design stage of energy policies, in the valuation of investments and in their optimal management by firms.

13

E. S. Schwartz and A. B. Trolle (2010), ‘Pricing expropriation risk in natural resource contracts: a real options approach’, in W. Hogan and F. Sturzenegger (eds), The Natural Resources Trap: Private Investment without Public Commitment (MIT Press, 2010).

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ENERGY SECURITY IN AN UNPREDICTABLE WORLD: MAKING THE CASE AGAINST STATE AID LIMITATIONS IN ELECTRICITY GENERATION Paul Murphy1

The world we live in is a complicated, unpredictable place. This has never been more true since the conclusion of the 2014 Winter Olympic Games in Sochi, Russia. Since that time, Crimea has transferred from Ukrainian to Russian territory, further armed conflict has continued in the remainder of Ukraine, ISIS has continued to be a significant factor in Syria and Iraq, and a coalition of Middle Eastern countries has intervened militarily in Yemen – just to highlight a few of the most significant examples. In particular, energy markets are particularly volatile, both historically and in this same time-frame, with the dramatic fall in the price of oil, the impact of US shale oil and shale gas on both US and world markets, and the shutdown of Germany’s nuclear reactors and ensuing impact of Energiewende (which has, curiously, increased Germany’s net emissions). The politics of energy have been demonstrated time and again, from Energiewende in Germany to Saudi Arabia’s recent decisions not to defend the price of oil, the state aid debate over the United Kingdom’s Contract for Difference (CfD) and Loan Guarantee 1

Paul Murphy is Special Counsel in the Washington, DC office of Milbank, Tweed, Hadley & McCloy LLP and a member of the firm’s Global Project Finance Group. His practice focuses on multiple aspects of the nuclear industry, and he has made significant contributions to scholarship in the areas of the development and financing of nuclear power, working with the International Atomic Energy Agency, the OECD’s Nuclear Energy Agency, the International Framework for Nuclear Energy Cooperation and the US Government.

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approach for the Hinkley Point C nuclear power project, the economic and financial sanctions imposed against Russia over its actions in Ukraine, and the emergence of LNG export terminals in the United States to support European and Asian markets. With such turmoil, unpredictability and political/geopolitical influence, discussions concerning ‘energy security’ have come to the forefront of thinking, particularly within the European Union, principally in response to the aforementioned actions by Russian vis-à-vis Ukraine and, in particular, with a focus on reducing European dependence on Russian natural gas under this rubric of ‘energy security’.2 Just what does ‘energy security’ mean and why do considerations of ‘energy security’ perhaps change the way that governments might think about the development of baseload energy and related infrastructure projects? To begin, electricity constitutes the critical infrastructure of a nation. The link between electricity and development is at the core of this concept.3 As such, electricity is one of the ‘basic needs’ that governments must provide to their people.4 Based on that premise, it follows that energy security is put at risk whenever a nation must rely on either/both external supply of electricity and/or external supply of the fuel needed to generate electricity. If such reliance exists, as is the case regarding the supply of natural gas by Gazprom to the European Union, client countries are susceptible to supply being unavailable and by pricing being unpredictable, either due to reduced availability, market shocks and/ or price/supply manipulation by the supplier country. By internalising energy supply, the country doing so can achieve superior levels of price stability, as it mitigates the unpredictability associated with reliance on external sources. Furthermore, diversifying fuel sources promotes further energy security by reducing the country’s dependence on any one particular type of fuel supply. Recognising that electricity is an input to so many elements of everyday life and economic development, such stability becomes an important component of the energy security dialogue. While electricity markets have been deregulated in the European Union in an effort to promote price competition and, therefore, a reduction in electricity prices for end-users, deregulation has had the effect of governments ceding control of electricity markets – in terms of both what is built and how prices are determined. However, such deregulation has not really been in full, as, in an effort to meet climate change/emissions reduction goals, renewable energy has been the focus of subsidies and other preferential treatment, thereby creating market imbalances, which can, in turn, create market instabilities. Similar policies in the United States have led to market extremes, whereby negative pricing has been observed in deregulated energy markets. ‘Subsidy’, however, is a dirty 2

3 4

The term of art is ‘energy security’, but the focus of the discussion that follows is principally on electricity. See https://sustainabledevelopment.un.org/content/documents/ecaRIM_bp.pdf Other ‘basic needs’ would include national security, public safety, food, water and shelter.

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word in EU parlance, given state aid limitations,5 but, by excluding renewables from the state aid construct, baseload generation has suffered greatly. Why is such market behaviour disconcerting from an energy security perspective? The unfortunate reality is that such preference for renewable energy is favouring an intermittent generating source. If the sun does not shine (a factor which happens at least one-third of the day, regardless of weather patterns) or the wind does not blow, alternative sources of power must fill such gaps. Traditional baseload forms of power (hydro, coal, gas, nuclear) are either limited in capacity (hydro), disfavoured for environmental reasons (coal),6 limited by supply (gas) or politically challenged (nuclear). Thus, the European Union finds itself in a difficult position: (1) it is dependent on foreign supply for baseload generation; (2) it favours intermittent generation without the means for large-scale energy storage; and (3) in certain countries, it disfavours nuclear power, which would otherwise provide emissions-free baseload generation and address energy security issues. The result is an uncertain situation for a key economic and societal input. Such uncertainty is something that industry in particular disfavours. Commercial unease with instability is no more evident than in the use of hedging instruments that are widely used in large commercial and financial endeavours. Hedging is used for commodities, interest rates and currencies. The idea that industry favours the lowest price, above all else, for a key input is simply not correct; instead, hedging demonstrates that an entity is willing to forgo (or is unwilling to chase) potential favourable price extremes in an effort to avoid the opposing unfavourable price extremes. In short, stability and predictability are more important in the case of key inputs. With industry being the backbone for economic growth, one must question the prudency of any policy that does not promote price and supply stability for a key strategic and social input. If one recognises that energy security is fundamental to national development, it does raise the question of whether the European Union’s rules concerning state aid vis-à-vis electricity generation are appropriate. Taking the example of Hinkley Point C, if the United Kingdom wishes to make a decision to build nuclear power plants as a source of emissions-free baseload generation – based on a determination that nuclear power is the most rational way to meet the competing goals of energy supply, climate change commitments and energy security – then one must question whether it is appropriate for either the European Union, as an institution, or its member states, in the case of Austria, to be able to challenge such a decision on the basis that electricity should be governed by classic, common market/anti-subsidy principles. 5

6

State aid rules are reflected in Article 107(1) of the Treaty on the Functioning of the European Union: ‘any aid granted by a Member State or through State resources in any form whatsoever which distorts or threatens to distort competition by favouring certain undertakings or the production of certain goods, shall in so far as it affects trade between Member States, be incompatible with the common market’. Germany and Poland notwithstanding.

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In the case of the present state aid structure, clearly the basis for challenging the UK’s pricing and loan guarantee programme for Hinkley Point C exists. However, if the market was not providing an answer to the UK’s needs, as determined by its government, then, particularly on the basis of energy security considerations, is it not justifiable, if not the absolute responsibility of the British government, to take whatever measures it determines necessary to incentivise the construction of that form of generation that it determines to best serve its national interests? Energy security is a hard concept to quantify. At a project level, for investors and lenders, energy security is not something that can be factored into a financial model. In this respect, it is similar to intangible values put on similar concepts like ‘energy diversity’, ‘grid stability’/‘capacity’ or ‘clean energy’,7 as none of these considerations are quantifiable through project financial modelling. Nevertheless, at a macroeconomic or national level, each of these concepts can be highly valued by a national government. Because the market acts at a project level, such intangible goals are not factored into decisions on the financing (and, thereby, the economic case) for the project, unless such goals are somehow promoted through structures, such as the CfD/loan guarantee structure for Hinkley Point C. Simply put, if the market does not get to the desired result,8 the national government must (from an energy security perspective) have the ability to create the necessary incentives to promote the goals it so desires.9 While consensus at the EU level on treatment of renewables as a special case has been achieved, the same consensus does not exist for nuclear power. Yet the lack of consensus merely underscores the fact that, in an area as fundamental as energy security – as a basic need for which a national government is responsible – perhaps the law should be tailored in a fashion to put electricity completely outside of the state aid rules, especially when one considers the diversity that exists across the membership of the EU at present and the need for individual member states to determine the means by which to achieve their energy security and emissions goals. With electricity as a key driver of economic development and overall quality of life, it falls to the national government to ensure and protect such supply, as well as factor in other intangible considerations. As such, it becomes difficult for a responsible government to base the provision of such a need on the unpredictability of external energy markets and supplies, which, necessarily, changes the rules by which governments must evaluate energy projects and the support therefor. In the specific case of the European Union, that requires a reexamination of the applicability of state aid to critical infrastructure, such as electricity, and to reassess the impact of deregulation in the energy sector. 7 8 9

Note that carbon pricing models have not proved effective within the European Union to date. Note that the ‘desired result’ will differ from country to country. As of the date of this article, the State of Illinois is trying to create an economic structure to prevent several nuclear power plants owned by Exelon from shutting down, due to market conditions (deregulated market, low price of natural gas, renewable energy subsidies) which have made the plants unable to operate profitably. The rationale for such structure is the value being placed on baseload capacity and emissions-free generation.

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DELIVERING A LOW-CARBON ELECTRICITY SYSTEM IN A LIBERALISED MARKET Roger Kemp1

INTRODUCTION AND SCOPE This chapter discusses the challenges of delivering a low-carbon electricity system in mainland Great Britain.2 The country’s integrated network was established by the Electricity (Supply) Act 1926. The industry was publicly owned and managed by the Central Electricity Generating Board (CEGB) and its predecessors and regional distribution boards3 until privatisation, implemented by the Electricity Act 1989. The industry in 2015 consists of more than 300 companies. Eight are involved in large-scale power generation, one operates the 400 kV and 275 kV high-voltage transmission network and six operate extensive distribution networks at 132 kV or lower voltages. There are six major electricity retailers who purchase energy from generators in half-hourly auctions and sell it to private and commercial consumers. In addition, there are many smaller generators and local distribution companies.4 1

2 3

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Roger Kemp is a Professorial Fellow in the Engineering Department at Lancaster University. He joined the university as a second career, after thirty-five years in industry. He is a Fellow of the Royal Academy of Engineering and of the Institution of Engineering and Technology and has contributed to several reports on energy policy by these bodies. The electricity system in Northern Ireland is integrated with that of the Republic of Ireland. In Scotland the industry was vertically integrated and divided between the South of Scotland Electricity Board and the North of Scotland Hydroelectric Board. A full list of electricity licensees is published by the Office of Gas and Electricity Markets (Ofgem), a non-ministerial government department and the independent national regulatory authority. See www.ofgem.gov.uk

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The mix of fuels used depends on the relative prices of different fuels but is typically coal: 36 per cent, gas: 27 per cent, nuclear: 20 per cent and renewables: 15 per cent.5 The coal-fired power stations are from the 1960s or 70s and are approaching, if not past, their original design life. By the end of 2015, 11.5 GW of coal and oil plant will have closed as a result of the EU Industrial Emissions Directive (2010/75/EU). All existing nuclear stations, except Sizewell B, are scheduled to close within ten years. There are three main challenges in decarbonising the GB electricity supply: • constructing and operating sufficient low-carbon generating plants • ensuring the stability, continuity and safety of an electricity grid fed by low-carbon energy sources • the economics of low carbon and the necessary storage or back-up capacity to cope with variable loads and unpredictable inputs from flow renewables (wind, solar and so on). These are discussed in the following three sections. BUILDING LOW-CARBON GENERATION Figure 32.1 shows the variations of electrical load for typical weeks in summer (the first full week of July 2009) and winter (the first full week of February 2010). It can be seen that the peak load is around 55 GW6 and occurs in the early evening in winter; the lowest load is 20 GW and occurs on summer mornings. Over the decade 2005 to 2015 the peak load on the network decreased slightly, but it is unclear how it will change in future. Figure 32.2 is a greatly simplified diagram of energy flows in the UK economy when the Climate Change Act 2008 became law. The two large users of fossil fuels are road transport (petroleum products) and heating (predominantly natural gas). Any policy to reduce CO2 emissions must tackle these uses of fossil fuels. Current policy is to encourage the transfer of many heating loads from gas boilers to electrically powered heat pumps and to increase the proportion of cars and vans with electric or plug-in hybrid drive systems: if these plans are successful, the annual consumption of electricity will increase substantially. Peak load in the winter is likely to be particularly affected as the early evening is also one of the times of maximum gas use in the domestic sector and a switch from gas central heating to heat pumps would increase the ‘peakiness’ of demand.7 5

6 7

Digest of United Kingdom Energy Statistics (DUKES) 2014 (hereafter DUKES), Department of Energy and Climate Change First (2014), available at www.gov.uk/government/statistics/digestof-united-kingdom-energy-statistics-dukes-2014-printed-version Units are gigawatts (GW). One GW is 1 million kW. The peak power demand on the gas grid is 300 GW, five times the peak electrical load. Any strategy to transfer load to electricity would also have to incorporate some form of energy storage to spread the peaks, as well as heat pumps that ‘amplify’ the energy from the grid. See Royal Academy of Engineering, Heat: Degrees of comfort? Report (January 2012), available at www. raeng.org.uk/publications/reports/heat-degrees-of-comfort

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Figure 32.1 Weekly load patterns – winter and summer Source: Balancing Mechanism Reporting System (BMRS) operated by ELEXON Ltd, the Balancing and Settlement Code Company (BSCCo), under the New Electricity Trading Arrangements (NETA). Available at www.bmreports.com

Figure 32.2 UK energy flows, 2008 Source: Royal Academy of Engineering, Generating the Future: UK Energy Systems Fit for 2050. Report (March 2010), available at www.raeng.org.uk/publications/reports/generatingthe-future-report

By contrast, an increase in the use of plug-in vehicles would result in an increase in overall electricity consumption spread evenly over the year. With appropriate time-of-use tariffs, the additional electricity use could be directed towards times of low demand, thus reducing peakiness.

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In January 2015, the nominal (nameplate) generating capacity of the GB electricity network was roughly 80 GW,8 comprising the following: Conventional steam turbines (mainly coal) Combined-cycle gas turbines (CCGT) Nuclear power Wind Solar PV and other renewables

25 GW 35 GW 10 GW 10 GW 3 GW

To achieve a largely decarbonised electricity system, with the same capacity as at present, by 2030 would require replacing all the baseload coal-fired stations and around half of the CCGT stations – say 40 GW in total. As peak load occurs in the early evening in winter, solar PV could contribute very little and the principal contenders are nuclear power and wind.9 A modern nuclear station, such as Hinkley Point C, for which preparatory site works started in 2014, has an output of 3 GW. Half a dozen stations of that size would provide half the necessary 40 GW. The only other well-proven technology is wind energy. A typical onshore wind turbine can produce 2 MW – offshore devices can be twice that power. Over an average year, because of the variability of the wind resource, the output of an onshore wind turbine is 30 per cent of its nominal rating. For offshore turbines the figure is 35 per cent. To produce an additional 20 GW would thus require around 30,000 onshore turbines or 15,000 offshore (compared with the 2015 total of 6,000 turbines).10 Constructing that capacity of nuclear and wind generation would be a challenge both technically and politically, bearing in mind the opposition of some politicians and lobby groups to either technology. If the adoption of heat pumps and plug-in vehicles progresses rapidly, it could be an underestimate of what is needed. GRID STABILITY It is tempting for policy-makers to see the electricity grid as an inert pipeline where, as long as the overall electricity input matches the loads on the system, there are few constraints on the sources of power. In fact, maintaining a stable transmission and distribution system places significant limitations on the type 8

Based on DUKES and Royal Academy of Engineering, GB Electricity Capacity Margin, Report for the Council for Science and Technology (October 2013), available at www.raeng.org.uk/ publications/reports/gb-electricity-capacity-margin 9 There are many other renewable or low-carbon technologies that could contribute to a decarbonised system, including carbon capture and storage, tidal flow turbines, wave energy converters, solar thermal collectors and tidal lagoons. There are also various energy storage technologies. This short chapter has concentrated on wind power, as it is the best developed and most likely to meet the 2030 targets. 10 This is at the upper end of the range of estimates by the National Grid. Arup and Poyry discuss in Royal Academy of Engineering, Wind Energy: Implications of Large-scale Deployment on the GB Electricity System, Report (April 2014), available at www.raeng.org.uk/publications/reports/ wind-energy-implications-of-large-scale-deployment

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of electricity generation and the control of the system. Two important issues are discussed in the following paragraphs, but there are several others.11 System inertia Conventional steam turbo-generators are heavy and rotate in synchronism at 3,000 rev/minute. They behave like flywheels in that they iron out short-term variations in the 50 Hz frequency of the grid. A proportion of generators are automatically controlled so that, if the frequency drops, more steam is allowed into the turbines, thus maintaining the frequency. By contrast, solar panels and wind turbines provide whatever power is available from the wind or sun and have very low, or even zero, inertia and, as currently used, make no contribution to frequency control.12 Experience from Ireland has shown how the reduced inertia of a grid with significant use of wind can cause instabilities and risk cascade tripping of generation systems.13 Short-circuit level When a short-circuit occurs on a conventional network, the generator produces a very high current that causes circuit-breakers to trip. All solar panels and many recent wind turbines are connected to the grid via electronic inverters; these are self-protecting and limit the short-circuit current to the maximum the electronics can carry. Thus the current into a short circuit is reduced and protection systems on the network may not be able to detect the fault. A reduced fault level means that voltage dips due to sudden surges will be more pronounced, with widespread implications on computer systems; the network becomes more vulnerable to the harmonic currents produced by electronic inverters and may also have a lower ability to cope with cascading faults. The professional institutions, particularly the Institute of Engineering and Technology (IET), have argued that the present governance and regulation arrangements that split the network between transmission and distribution and concentrate on economic factors are inappropriate for the new and complex situation. They have argued for a System Architect function to provide technical direction to the transformation of the network.14 11

These are discussed in greater detail in National Grid plc, System Operability Framework 2014 (September 2014), available at www2.nationalgrid.com/UK/Industry-information/Future-ofEnergy/System-Operability-Framework, and in Institution of Engineering and Technology, Electricity Networks: Handling a Shock to the System (September 2013), available at www. theiet.org/factfiles/energy/pnjv-page.cfm 12 There are control techniques available to give wind turbines ‘enhanced artificial inertia’ and to make both solar and wind power contribute to frequency control, but the latter either require a control connection between grid control and thousands of individual devices or would reduce their annual output, and thus revenue. Present feed-in tariffs and connection arrangements ignore these problems. 13 EirGrid, Summary of Studies on Rate of Change of Frequency Events on the All-Island System (August 2012). 14 Institute of Engineering and Technology, Transforming the Electricity System: How Other Sectors Have Met the Challenge of Whole-system Integration (October 2014), available at www.theiet. org/factfiles/energy/pnjv-report-full-page.cfm

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FINANCING LOW-CARBON GENERATION Since the industry was privatised, generators have sold their electricity to retailers in a market under the New Electricity Trading Arrangements (NETA) with auctions for every half-hour period. The market is based on energy prices (£/kWh). This was logical in the situation where most plant had been fully depreciated and costs were largely fuel (that is, energy). However, for large fleets of renewables or nuclear power, capital expenditure would be very large and operating costs very low; thus the marginal generation costs (per kWh) could be almost zero. Under this situation, it is difficult to see how an electricity market based on an auction of energy (per kWh) is possible. Bid prices would no longer be related to operating costs and there must be a risk that it would be closer to a game of poker, where the bid is based on an assessment of the competition, rather than on cost. A free market for electricity would be likely to produce extremely high prices in winter, particularly at periods of peak demand, but very low prices at times when the demand can be met entirely by renewable energy. If these energy costs are passed on to the customer (using smart meters that are soon to be rolled out), the cost of electricity at peak times would be very expensive, but would cost almost nothing during long periods in the summer. Headlines about a pensioner paying £10 to boil a kettle would be ‘challenging’ for policy-makers but, if peak-time prices are not allowed to reflect shortages, there would be no incentive for investment in peak-lopping generation that would be used only rarely, which would risk blackouts – even more politically challenging! Although wind-free periods are usually of short duration, every few years a widespread anticyclone, resulting in very low wind power, can last for several weeks. A recent example is shown in Figure 32.3 below. The difficulty for system planners is that long-duration lulls in the wind resource occur only rarely and thus the costs of maintaining standby generation in operational readiness becomes extremely expensive. While the levels of necessary back-up capacity are low (a few GW) and generators have mothballed gas-fired plant, the cost is acceptable, but building new back-up plant to cover the loss of 20 GW of wind power during a fortnight’s anticyclone once every few years is likely to be unfundable. Less ambitious renewables targets that require gas-powered generation to be used regularly to provide power for domestic heating would improve the financial case for standby generation but raise the question: why not simply retain gas central heating? THE CHALLENGES For almost 100 years, Great Britain’s electricity system has relied on steady development of known technologies. Decarbonisation will introduce a range of new technologies in a short space of time. Simply getting the new wind farms, solar arrays, tidal stream turbines, carbon capture, nuclear power stations and other infrastructure through the planning and safety audit systems will be challenging. Building them will place demands on the engineering and construction industries that have not been experienced since postwar reconstruction.

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Figure 32.3 Daily wind energy output, winter 2008–9 Source: BMRS, available at www.bmreports.com

More important is the necessity to integrate the assets into a safe and stable network. It would be unwise to assume that a plethora of new assets built by different private companies will necessarily work together as a power system. The existing systems engineering and regulatory arrangements, designed for a technical environment that had been largely unchanged for half a century, are not fit for purpose. Delivering a decarbonised electricity system is an engineering challenge that requires a similar level of systems engineering competence to developing a new space probe. Britain has a privatised electricity sector. The principles were set out by Nigel Lawson in a speech on energy policy. It provided a clear break with the tradition of state control and was the start of the process that led to the Electricity Act 1989 and privatisation of the industry: I do not see the government’s task as being to try to plan the future shape of energy production and consumption. It is not even primarily to try to balance UK demand and supply for energy. Our task is rather to set a framework which will ensure that the market operates in the energy sector with a minimum of distortion and energy is produced and consumed efficiently.15 15

N. Lawson, Speech delivered at the Fourth Annual International Conference, International Association of Energy Economists, Churchill College, Cambridge, June 1982.

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In fact arrangements have never been as ‘hands off’ as this speech suggested and increasingly ministers have managed the sector through feed-in tariffs, capacity payments and other levers of power. For decarbonisation to happen through market mechanisms, described by Lawson, would require a high level of carbon tax and a willingness to see peak-period tariffs reflect actual costs. Both would be politically impossible. Policy-makers are thus faced with the need to manage a complex disaggregated industry going through a technical revolution. Demands on the electricity sector are highly dependent on how decarbonisation of transport and heating are managed; both sectors face their own challenges with no clear strategies towards meeting policy targets. Delivering a low-carbon electricity system will require a high level of systems engineering and coordination across several sectors of the economy that are traditionally the preserve of different ministries. Broad-brush statements of intent, such as ‘we will reduce carbon emissions by 80 per cent by 2050’ are no substitute for a properly designed cross-sector plan. At the moment this is missing and a useful first action might be to recruit a policy team who understand the engineering complexities of the electrical system that policy-makers are being asked to manage.

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A PROPOSAL FOR REFORMING AN ELECTRICITY MARKET FOR A LOW-CARBON ECONOMY Raphael J. Heffron1

The UK is currently reforming its electricity sector. This gives rise to some pertinent questions: do the reforms go far enough and can more reforms be expected in the near future? The UK is not alone in its attempt to transform its electricity sector. The European Union has made three successive bids to reform the electricity market within the last two decades. The latest, namely the Third Energy Package, follows the previous two packages. The electricity sector has proved difficult to reform principally because of the competing demands of competition, energy security and climate change mitigation; what is referred to as the energy trilemma. Achieving all three in unison remains beyond the capabilities of most government administrations. After some two decades of pushing the competition agenda it appears near certain that competition has reached the end of its current journey. It has delivered high prices for consumers, little investment in new energy infrastructure, reduced spending in research and development and an oligopolistic market structure. Meanwhile, the rate of carbon dioxide emissions continues to increase exponentially across the world. 1

Raphael Heffron is a Senior Lecturer in Energy and Natural Resources Law at Queen Mary University of London. Raphael’s research interests are in energy law and policy, and in particular electricity markets, energy subsidies, low carbon energy, energy justice and Arctic energy law. Raphael is a trained Barrister-at-Law and was called to the Bar in July 2007 in the Republic of Ireland. Raphael read for his PhD at Trinity Hall, University of Cambridge. He also holds degrees from the University of Cambridge (MPhil), the University of St Andrews (MLitt) and Trinity College Dublin (BA, MA).

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Nevertheless, one must ask the question: was real competition ever present? It is claimed that the traditional fossil fuel market incumbents had and still have too much influence. For example, in the US during the presidential election year of 2012, a New York Times analysis revealed that $153 million was spent on television advertisements by the lobby promoting coal, oil and gas and/ or criticising clean energy; this is in stark contrast to a mere $41 million by the clean energy source lobbyists. The EU policy of 20:20:20 by 2020 also distorted competition. Too much faith has been placed in the policies of privatisation and competition. The expectation that the private sector would have motives other than profit was misguided. To achieve aims beyond the profit motive, government intervention is needed. Was the banking industry in the UK not saved by direct government intervention and subsidised support? Reform should not be limited to just the restructuring of the electricity market, but should also extend to transforming the philosophical underpinnings of the market. For too long the Chicago School approach has dominated thinking in law and economics. It is now time to consider its limitations and move to reform the approach to law and economics and the development of markets. There are other worthwhile goals than just profit. This is the case in the electricity market now more than ever especially in relation to climate change mitigation. With the effects of climate change being accepted it is the considered view of leading scholars across the world that it is happening at an increased pace. For example, a third of the summer sea ice in the Arctic has disappeared while the effort to keep below a 2°C temperature increase globally is likely to fail despite the latter being agreed at the Copenhagen Accord. An electricity market needs to encourage the development of new energy infrastructure. The latter can provide competition to existing energy infrastructure, help lower prices, develop technology, provide employment and contribute to the lowering of CO2 emissions. In addition, research and development needs to be supported by market participants and should not be overly reliant on public-sector funding. Consumers should be able to afford electricity, unlike the current situation where the number of people classified as suffering from fuel poverty is increasing while others choose between fuel and food or, in the most severe cases, face dying of cold. In examining the EU approach it is increasingly evident that the Third Energy Package, since the onset of the financial crisis, is being applied in a rather lax manner. There is perhaps the realisation that the pursuit of competition is not a goal to which every economic market needs to adhere. The legislative changes proposed by the UK for its electricity market reforms are likely to be approved by the European Commission. This is despite the clear incentives and intervention in the electricity market which will favour nuclear energy and renewable energy sources. It is questionable whether the UK reforms go far enough. Based on the EU experience, it is likely that new reforms will be introduced sooner rather than later. The composition of these reforms deserves rigorous examination and debate. The solution lies in economics and the creation of new economic

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markets. Different energy sources use different technologies. Also, there are different environmental goals and different safety legislation for different energy sources. The nuclear sector, for instance, has its own safety regulator. The electricity market should be divided up. In this way the competing demands of competition, energy security and climate change mitigation can be achieved with a higher degree of certainty. A new outline electricity market would see it notionally divided into five principal parts: (1) gas; (2) coal; (3) nuclear energy; (4) renewables; and (5) an open market. A percentage of the electricity market would be assigned to each part. Until a designated percentage was met, there would be clear government support for that energy source. Any excess would be traded in the open market. This would mean competition for firms within a market for a specific energy source, and one with all the energy sources in an open market (which could include the capacity margin). A government could then set out to achieve a low-carbon economy (such is the aim of the UK government) and over the years reduce the percentage share of coal and gas while increasing that of nuclear energy and renewables. The excess provided by gas and coal to the open market could be charged at a premium with this in turn being used to support the low-carbon sources. The new market would have a number of benefits. It would allow for competition among companies providing the same energy source, thus potentially improving the efficiency of each energy source. It would promote new lowcarbon technology and give it a sustained chance of success. It would enable an improved method of replacing old technology, in particular where nuclear energy is concerned. It would also offer security to investors and encourage them to invest and provide investment for long-term energy projects. Overall, this approach would serve the core elements of EU energy policy. In separating the energy sources into individual economic markets competition would be increased, CO2 emissions would decrease over time while governments could directly support new energy infrastructure development and increase their own energy security.

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THE ROLE OF THE DEMAND SIDE IN ELECTRICITY Malcolm Keay1 and David Robinson2

INTRODUCTION Energy policy has traditionally focused on the supply side. For instance, energy security is normally defined as ‘security of supply’ rather than in terms of an active role for consumers in the matching of supply and demand.3 The degree of intervention on the supply side – for example, in supporting low-carbon generation – has also consistently been much higher than on the demand side. A recent study suggested that some 70 per cent of the intervention total goes to support for production, with a mere 8 per cent or so on energy efficiency (and a negligible amount on demand response).4 This policy bias will need to change; much more attention has to be given to the demand side – and it will need to involve much more than energy efficiency – if we are to deliver effective energy policy for the longer term, especially as we move to a low-carbon energy system. The need for a demand-side approach is particularly significant with electricity. Intermittent renewable sources are increasingly penetrating the electricity

1

2

3

4

Malcolm Keay is Senior Research Fellow at the Oxford Institute for Energy Studies, where his research focuses on electricity markets in the UK and Europe and the implications of climate change policies. David Robinson is an independent consultant and Senior Research Fellow at the Oxford Institute for Energy Studies. His current research focus is on the design and regulation of energy markets to make liberalisation and decarbonisation compatible. See, for example, the Commission’s description of EU energy security at http://ec.europa.eu/ energy/security_of_supply_en.htm. Similarly, the UK government produces a Statutory Security of Supply Report, jointly with Ofgem. Ecofys, Subsidies and Costs of EU Energy, Report prepared for the European Commission (October 2014), available at https://ec.europa.eu/energy/sites/ener/files/documents/ECOFYS%20 2014%20Subsidies%20and%20costs%20of%20EU%20energy_11_Nov.pdf

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system, making the supply side less controllable; at the same time major technical developments are under way on the demand side of electricity, including the introduction of smart meters and smart appliances, and the growth of localised generation sources. As flexibility on the supply side decreases, flexibility on the demand side becomes more important, and it needs to be integrated into policy thinking. DEMAND-SIDE POTENTIAL The potential economic and environmental benefits are huge. A more active demand side can lower costs and reduce resource requirements at every stage of electricity supply: • Flexibility in demand and long-term reductions in peak demand can reduce the requirement for new generating capacity. • Reductions in overall demand mean less electricity generation is needed. • Flexible demand can be one effective means of balancing the system in real time. • Demand response and local generation can reduce the need for new transmission and distribution infrastructure. • Flexible demand supports decarbonisation, for instance by facilitating the penetration of intermittent renewable electricity. POLICY AND REGULATORY CHALLENGES So the potential is there, but a shift in thinking will be needed to realise this potential, including changes in market structures, the removal of regulatory barriers and a new policy approach. Market reforms Promoting a more active role for consumers (for instance, in shifting demand from periods of system stress) is not just, or even primarily, a matter of technology like smart meters and appliances. Indeed, a recent study has concluded that it is commercial rather than technical factors which are now the main obstacle.5 Ultimately it may well be that fundamental market reforms are needed and that the only satisfactory answer to the problem would be to get away from the kWh pricing which is the present industry norm and to enable direct participation by individual consumers in electricity markets, perhaps via so-called ‘transactive pricing’ which allows consumers to contract for the precise package of services they need.6 Meanwhile, some less fundamental changes are being tested, including the following:

5

6

C. Dudeney, G. Owen and J. Ward, Realising the Resource: GB Electricity Demand Project Overview Sustainability First Paper 13 (2014), available at http://www.sustainabilityfirst.org.uk See F. P. Sioshansi (ed.), Distributed Generation and its Implications for the Utility Industry (Academic Press, 2014) for a number of alternative approaches.

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Demand response in capacity markets: Demand response is already developing in many European markets7 but it is expected to receive a boost from the increasing interest in capacity markets. In the UK, steps are already being taken to include demand response in the capacity market for which auctions started in late 2014.8 Markets for flexibility: There is growing interest in the idea of creating markets to trade flexibility services. Sellers could include demand response, flexible generation, storage and perhaps others. Buyers would buy such services in order to meet their commitments and avoid balancing or other charges. The flexibility markets could include short-, medium- or long-term trading. The shorter the commitment, the more flexibility markets approximate (or substitute for) markets for ancillary services (that is, secondary and tertiary reserves). The longer the commitment, the more they begin to look like reliability or capacity markets. Hourly pricing: Some countries, notably in the Nordic region, have introduced retail prices that reflect hourly wholesale market prices. Spain is the first country to introduce a last resort ‘default’ energy price for small consumers (below 10 kW of contracted capacity) that corresponds to the hourly wholesale market price. With a suitable smart meter, the invoice will reflect that consumer’s hourly consumption, creating incentives for the consumer –through smart devices, for example – to shift to lower-priced hours, which will be known the day before. Eventually, this may lead to the aggregation of demand and active participation of this load in flexibility markets. Other reforms Apart from these moves towards market reform, there are many areas of government policy which will need to be developed, for instance: Reforms in regulation: Despite moves by the UK regulator Ofgem to improve incentives for distribution companies, a recent study has concluded that change remains ‘marginal’ at the level of network operation and planning9 – at present, network operators still have a basic interest in network growth. Extensive changes in regulation will be needed to ensure that distribution companies think in terms of the potential for active consumer involvement as a way of reducing demand on the network. Demand reduction incentives: The UK is experimenting with a programme to create incentives for long-term demand reduction (as opposed to the shortterm load-shifting which is the target of demand-response programmes).10 7

See http://sedc-coalition.eu/wp-content/uploads/2014/04/SEDC-Mapping_DR_In_Europe-201404111.pdf 8 See www.gov.uk/government/uploads/system/uploads/attachment_data/file/209280/15398_TSO _Cm_8637_DECC_Electricity_Market_Reform_web_optimised.pdf 9 M. Lockwood, ‘Energy networks and distributed energy resources in Great Britain’, IGov Working Paper, University of Exeter, available at http://projects.exeter.ac.uk/igov/wp-content/ uploads/2014/10/WP11-Energy-networks-and-distributed-energy-resources-in-Great-Britain.pdf 10 See www.gov.uk/electricity-demand-reduction-pilot

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Smart efficiency: The UK demand-reduction programme is an indicator of the way in which energy efficiency needs to develop if it is to be an effective component of decarbonisation policy – away from generalised efficiency improvements to ‘smart efficiency’ which encourages fuel-switching, demand flexibility, peak reduction and changes in consumer behaviour in support of the low-carbon objective. Product policy: This should reflect the same goals as smart efficiency. At the moment the focus is on setting standards for appliances and equipment which lead to reductions in energy usage; in future the emphasis should equally be on developing standards and equipment which can support the consumer capacity for demand response. Investment support: Nearly all investment support at the moment is on the supply side (for example, feed-in tariffs for renewable sources). Governments should consider balancing this with appropriate support measures on the demand side (like guaranteed tariffs for flexibility or demand reduction) to encourage investment in equipment such as on-site electricity storage. Public engagement and community energy projects: More active consumer involvement is only likely to develop if there is a feeling of public engagement in the energy policy process. One way of encouraging this engagement is via smallscale community energy schemes. In many countries there are regulatory and commercial barriers to such arrangements; in some countries, like Germany, community schemes are making a major contribution to the development of renewable resources;11 other countries, like the UK, are less advanced but are developing their own strategies in this area.12 Education and collaboration with consumers: More generally, consumers are seldom well informed about the opportunities for active participation in electricity markets and for saving money through demand response or demand reduction. Markets and competition will play their role – some electricity suppliers are beginning to see that there are opportunities for sharing the economic benefits of changing consumer behaviour. We are also nearing an inflection point with regard to the commercial availability of smart electrical equipment, and demand management through control devices sold by major companies like Apple and Google. But government also has a role to play, especially in educating consumers about the potential benefits of more active involvement. CONCLUSION The electricity industry is undergoing fundamental changes – in effect turning ‘upside down’ – and a change in focus for government policy is also needed. Energy policy has in the past been biased towards the supply side; a more comprehensive approach, giving full recognition to the demand side, needs to be developed. Some steps are already being taken in this direction 11 12

See Sioshansi, Distributed Generation for a number of alternative approaches. See www.gov.uk/government/uploads/system/uploads/attachment_data/file/275163/20140126 Community_Energy_Strategy.pdf

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but they are tentative and marginal. A much more thorough approach is needed. Governments and regulators must tailor their policies around the need to engage consumers and encourage the development of a more active demand side; this will ultimately require a more fundamental reform of electricity markets than has taken place to date, but also major changes in regulation and policy instruments. The eventual aim must be an integrated approach to policy, with a balance between supply and demand sides, to ensure an effective delivery of carbon objectives.

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REPLACING FOSSIL FUEL GENERATION WITH RENEWABLE ELECTRICITY: IS MARKET INTEGRATION OR MARKET CIRCUMVENTION THE WAY FORWARD? Olivia Woolley1

INTRODUCTION Renewable electricity is more expensive to produce than electricity from fossil fuels due to factors including the newness of technologies and the smaller scale of production compared to centralised coal- and gas-fired power plants. The resulting lack of cost competitiveness and related risks that expenditure on plant development may not be recovered through electricity sales alone would, if they are left unaddressed, dissuade investment in the renewables sector. Member states of the European Union have therefore used legal measures, collectively referred to as support schemes, to attract financial backing for the growth of renewable electricity since they first began promoting its production in the 1980s.2 1

2

Dr Olivia Woolley is a Lecturer in Energy and Environmental Law in the School of Law, University of Aberdeen. Her research interests include law’s role in enabling a low-carbon energy transition and the development of legal frameworks for protecting ecosystem functionality. K. Hogg and R. O’Regan, ‘Renewable energy support mechanisms: an overview’, in M. Bonass and M. Rudd (eds), Renewables: A Practical Handbook (Globe Law and Business, 2010), pp. 32–3; S. Negro, F. Alkemade and M. Hekkert, ‘Why does renewable energy diffuse so slowly? A review of innovation system problems’, Renewable and Sustainable Energy Reviews 16 (2012), 3836, 3838 and 3841; V. Lauber, ‘The European experience with renewable energy support schemes and their adoption: potential lessons for other countries’, Renewable Energy Law and Policy 2 (2011), 120.

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The European Commission grudgingly accepts that such national intervention in markets is necessary although it conflicts with its core goal of establishing an EU-wide internal electricity market free of political interference by member states. However, as the Commission’s Guidelines on State Aid for Environmental Protection and Energy of June 2014 evidence, its preparedness to tolerate market distortions in the interests of promoting renewable energy is wearing thin.3 Support schemes which require that a sectoral actor should purchase electricity at a set price over a set period (feed-in tariffs) are largely to be phased out. Renewable electricity generators should be exposed to market forces alongside other power producers, receiving subsidies only as an additional payment on top of direct electricity sales (premium schemes).4 In requiring market exposure, the Commission assumes not only that the distorting effect of subsidies will be reduced, but also that this will aid the growth of renewable electricity by forcing producers to reduce costs in order to compete with other energy sources.5 I argue in this chapter that this assumption is misplaced. Obliging renewable electricity to compete in markets designed for fossil fuel energy sources is more likely to stifle than accelerate the growth in its production. Instead, measures that bypass markets of the type which the Commission now requires member states to stop using are required to replace fossil fuels with renewables at a rate commensurate with avoiding dangerous climate change. RENEWABLE ELECTRICITY AND MARKET STRUCTURE PROBLEMS Support schemes are used to facilitate the financing of renewable energy development by lessening investment risks. The main difficulty with growing market exposure is that backers may be deterred from investing in the renewables sector because of corresponding increases in such risk or may charge interest on monies loaned at rates that make projects unaffordable for their proposers. It goes without saying that technologies which cannot obtain financing in the first place will not be able to attain the production efficiencies, economies of scale and corresponding cost reductions that may lead to a growing market share. Premium schemes seek to address concerns that development costs will not be covered (price risk) by providing that generators should receive a payment on top of market sales.6 They can often be as effective as feed-in tariff schemes 3

4 5

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European Commission, ‘Guidelines on state aid for environmental protection and energy 2014–2020’, 2014/C200/01. Ibid., 25, Sec. 3.3.2.1. European Commission, ‘European Commission guidance for the design of renewable support schemes – Accompanying the document Communication from the Commission: Delivering the internal market in electricity and making the most of public intervention’, Staff Working Document (2013) 439 Final, 5 and 7–9. The label ‘premium scheme’ is used to refer to a variety of scheme types under which a sum is paid on top of electricity sales. For further information see European Commission, ‘European Commission guidance for the design of renewable support schemes’, 8–9; T. Couture and Y. Gagnon, ‘An analysis of feed-in tariff remuneration models: implications for renewable energy investment’, Energy Policy 38(2) (2010), 955–65; and E. Gawel and A. Purkus, ‘Promoting the market and system integration of renewable energies through premium schemes – a case study of the German market premium’, Energy Policy 61 (2013), 599–609.

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for addressing concerns over cost recovery.7 However, the absence of a purchase obligation introduces the route to market risk (absent from feed-in tariff schemes) that electricity from renewable sources will not be sold.8 In addition, premiums may not remove price risk for new market entrants who tend to sell their output to wholesalers at a discount from expected market prices because they lack the assets and revenue streams to bear market risks themselves.9 This is likely to be problematic for decarbonisation as the emergence and establishment of challengers to the status quo has been an essential feature of past energy transitions.10 A further consequence of heightened investment risk is that market participation, even with the support of premiums, may be restricted to incumbent energy producers because they are better able to bear risks of loss.11 A fundamental concern with this situation for the growth of renewable electricity is that businesses which derive much of their revenue from fossil fuels are unlikely to be in the forefront of promoting their displacement by lower-carbon alternatives.12 Support schemes that offer prospects of substantial profits have encouraged investment by incumbents in renewables, but the tendency in the design of premium schemes to prevent windfall profits by capping total recoverable costs or requiring payment to a subsidy-paying counterparty when market prices are above the level required for cost recovery removes this incentive.13 The structure of fossil fuel markets is also inimical to investment in renewable energy in two respects. The first is the widespread use of the merit order, under which the output of generating stations is scheduled for dispatch according to their marginal costs of production, to determine electricity prices in spot markets. Wind and solar have negligible marginal costs due to the free availability of the source with the perverse consequence that prices will tend to drop as their contribution to energy supplies grows, and that developers will struggle to recover their initial outlay through energy sales.14 Premiums may make up 7

C. Klessmann, C. Nabe and K. Burges, ‘Pros and cons of exposing renewables to electricity market risks – a comparison of the market integration approaches in Germany, Spain, and the UK’, Energy Policy 36(10) (2008), 3646–61, at 3646 and 3654. 8 Gawel and Purkus, ‘Promoting the market and system integration of renewable energies’, 607–8. 9 Ibid., 607; Klessmann et al., ‘Pros and cons’, 3652 and 3656; Lauber, ‘The European experience’, 130–1. 10 G. Unruh, ‘Escaping carbon lock-in’, Energy Policy 30(4) (2002), 317–25, at 321–2; R. Kemp, ‘Technology and the transition to environmental sustainability: the problem of technological regime shifts’ Futures 26(10) (1994), 1023–46, at 1027 and 1033–6. 11 Gawel and Purkus, ‘Promoting the market and system integration of renewable energies’, 607; Couture and Gagnon, ‘An analysis of feed-in tariff remuneration models’, 959 and 962; Klessmann et al., ‘Pros and cons’, 3656 and 3660. 12 Unruh, ‘Escaping carbon lock-in’, 321–2. 13 Lauber, ‘The European experience’, 130; Couture and Gagnon, ‘An analysis of feed-in tariff remuneration models’, 960–1. 14 Gawel and Purkus, ‘Promoting the market and system integration of renewable energies’, 607; Klessmann et al., ‘Pros and cons’, 3649 and 3657. A full explanation and analysis of the merit order effect is provided in Pöyry, ‘Wind energy and electricity prices: exploring the merit order effect’, Report for the European Wind Energy Association (2010), available at www.ewea.org/ fileadmin/files/library/publications/reports/MeritOrder.pdf

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for falling revenues to a degree, but it would be preferable to develop markets that are suitable for intermittent energy sources rather than compensating generators for mandatory participation in unsuitable fossil fuel markets. Secondly, penalties for departing from predicted levels of output are most likely to affect intermittent generators because of problems with predicting the availability of the resource (balancing risk).15 The requirement under the Commission’s state aid guidelines that receipt of support should be conditional on participation in market mechanisms for maintaining system stability creates higher risks of additional production costs for wind and solar energy than for controllable fossil fuel counterparts.16 Finally, even if growing market exposure does not retard the growth of the renewables sector it is doubtful that this will result in the accelerated displacement of high-carbon energy. Renewable electricity does not afford the major reduction in costs or dramatic improvement in services that have generally been required for new energy sources and technologies to achieve market dominance.17 The position may change if requirements for carbon permits under the EU’s emissions trading scheme increase the cost of fossil fuel energy significantly, but carbon pricing is fraught with uncertainty as a driver for consumption of alternative energy sources whilst the displacement of dominant energy sources and technologies has tended to happen gradually even where the new source or technology possesses the key attributes for a shift from one market paradigm to another.18 CIRCUMVENTING MARKETS AND FEED-IN TARIFFS It is clear from the factors considered above that participation in fossil fuel markets is unlikely to deliver the replacement of fossil fuels by renewable electricity, and that this, even if it happens, will not proceed with the urgency that the existential threats posed for human living by climate change and the EU’s political aspiration of an 80–95 per cent reduction in greenhouse gas emissions by 2050 both demand. Governments should employ their legislative powers to ensure that this happens during the coming decades. In this regard, the success enjoyed by states that have used feed-in tariffs provides an excellent model of how market-bypassing measures can be used to expedite the growth of renewable electricity production. Setting guaranteed prices at levels corresponding with those required to enable cost recovery has proved highly successful as a means of creating investor confidence, but without 15

Gawel and Purkus, ‘Promoting the market and system integration of renewable energies’, 607; Klessmann et al., ‘Pros and cons’, 3660. 16 European Commission, ‘Guidelines on state aid’, 25, Para. 124(b). 17 Unruh, ‘Escaping carbon lock-in’, 321; R. Fouquet, ‘The slow search for solutions: lessons from historical energy transitions by sector and service’, Energy Policy 38(11) (2010), 6586–96, at 6590-3; C. Perez, Technological Revolutions and Financial Capital: the Dynamics of Bubbles and Golden Ages (Edward Elgar Publishing, 2002), 11. 18 Unruh, ‘Escaping carbon lock-in’, 322–3; ‘The slow search for solutions’, 6587, 6592–4; Perez, Technological Revolutions and Financial Capital, 8–35.

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placing unnecessary burdens on consumers.19 Information asymmetries have occasionally resulted in tariff levels being set too high by states, but schemes can be designed to allow adjustment in rates where this occurs.20 Degression can also be used to decrease remuneration in line with reducing costs of production as experience with the commercial operation of technologies grows.21 The typical coupling of rate setting with obligations for sectoral actors to purchase all electricity produced from renewable sources, and for systems operators to afford priority access and dispatch to renewable electricity, removes the potentially chilling effect on investment of route to market and balancing risks. Feed-in tariffs also provide a breathing space within which possibilities for improving efficiency in operation and for realising economies of scale can be explored. It is not right to say that the motivation to reduce costs is absent if a fixed price is paid as it will be in the interests of plant operators to maximise profits by cutting costs.22 In summary, policies that espouse a commitment to prioritising the decarbonisation of energy supplies should advocate the use of market circumventing approaches such as feed-in tariffs rather than requiring that the expansion of renewable electricity production must be conducted through existing electricity markets. Feed-in tariffs will undoubtedly continue to give rise to difficulties with the operation of electricity markets and to generate political controversies because of their perceived contribution to higher electricity prices.23 However, the first response to such problems should be to consider how those difficulties can be addressed, including by better political communication of the reasons for supporting renewable generation in this way, rather than reverting to business as usual in the knowledge that this will not achieve the changes in energy consumption required for humanity’s long-term well-being.

19

Lauber, ‘The European experience’; Couture and Gagnon, ‘An analysis of feed-in tariff remuneration models’; Doerte Fouquet and Thomas Johansson, ‘European renewable energy policy at crossroads – focus on electricity support mechanisms’, Energy Policy 36(11) (2008), 4079–92; Lauber (126–7) and Couture and Gagnon (962) note that prospects of higher revenues from electricity sales, and therefore higher cost burdens for consumers, are required if investment in renewables is to be attractive under schemes with market exposure. Investment costs tend to be lower under feed-in tariff schemes due to the predictability of revenue. 20 L. Stokes, ‘The politics of renewable energy policies: the case of feed-in tariffs in Ontario, Canada’, Energy Policy 56 (2013), 490–500, at 496–9. 21 Fouquet and Johansson, ‘European renewable energy policy at crossroads’, 4084–5. 22 Lauber, ‘The European experience’, 129–30; A. Verbruggen and V. Lauber, ‘Basic concepts for designing renewable electricity support aiming at a full-scale transition by 2050’, Energy Policy 37(12) (2009), 5732–43, at 5738–9. 23 Stokes, ‘The politics of renewable energy policies’.

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SUSCEPTIBILITY OF ELECTRICITY GENERATION TO CLIMATE VARIABILITY AND CHANGE IN EUROPE: A REVIEW OF LITERATURE Muriel C. Bonjean Stanton,1 Suraje Dessai2 and Jouni Paavola3

INTRODUCTION Extreme weather events can lead to the breakdown of infrastructure networks and critical services such as electricity.4 Understanding the impacts of climate variability and change (CV&C) on electricity generation, transmission and distribution is thus increasingly important not only for electricity companies 1

2

3

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Muriel C. Bonjean Stanton is a postgraduate research student in the School of Earth and Environment at the University of Leeds, exploring how public and private organisations frame and respond to risks associated with climate variability and change. Muriel’s research interests mostly centre on private-sector adaptation, public-private interactions around CV&C, climate governance and policy, and institutional and behavioural change. Muriel has ten years’ previous experience in adaptation to CV&C and natural resource management both in developing and developed contexts. Suraje Dessai is Professor of Climate Change Adaptation in the School of Earth and Environment at the University of Leeds. His research focuses on the management of climate change uncertainties, perception of climate risks and the science-policy interface in climate change impacts, adaptation and vulnerability. He is the recipient of an ERC Starting Grant and a lead author of the Fifth Assessment Report of the IPCC WG2. Jouni Paavola is Professor of Environmental Social Science and Director of the ESRC Centre for Climate Change Economics and Policy (CCCEP) in the School of Earth and Environment at the University of Leeds. His research examines environmental governance institutions and their environmental, economic and social justice implications, with a focus on climate change and biodiversity. D. J. Arent, R. S. J. Tol, E. Faust, J. P. Hella, S. Kumar, K. M. Strzepek, F. L. Tóth and D. Yan, ‘Key economic sectors and services’, in C. B. Field, V. R. Barros, D. J. Dokken, K. J. Mach, M. D. Mastrandrea, T. E. Bilir, M. Chatterjee, K. L. Ebi, Y. O. Estrada, R. C. Genova, B. Girma, E. S. Kissel, A. N. Levy, S. MacCracken, P. R. Mastrandrea and L. L. White (eds), Climate Change 2014: Impacts, Adaptation, and Vulnerability Part A: Global and Sectoral Aspects Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (Cambridge University Press, 2014), available at www.ipcc.ch/report/ar5/wg2

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providing critical services but also for policy-makers in charge of ensuring a country’s security of energy supply. Although the potential impacts of CV&C on the energy sector globally have been documented in the literature,5 the impacts of CV&C on electric power systems has received surprisingly scant attention and assessments at regional, national or local levels.6 This chapter reviews peer-reviewed literature published to date on the impacts of CV&C on electricity generation in Europe, summarising the findings by fuel source and highlighting key areas for future research. DATA AND METHODS A literature search was carried out to collate publications on the susceptibility of the European electricity sector to climate variability and change. Web of Science, Scopus and Engineering Village databases were searched for peerreviewed journal articles written in English, for ‘all years’, focused on Europe, and using different search word variants for climate change (climat*, chang*, variab*, extreme*, scenario*, model*, forecast*), modes of electricity generation (renewable, therm*, nuclear) and susceptibility (risk*, impact*, vulnerab*, susceptib*). A total of 102 searches yielded 4,461 results. Forty-six papers were found to be relevant and were included in this review, encompassing mainly Europe-wide and national assessments and some studies at subnational level (hydrological catchment, political region). POTENTIAL CLIMATE IMPACTS ON ELECTRICITY PRODUCTION IN EUROPE The scientific community has only recently started to investigate the impacts of CV&C on the electricity sector and research in this area is still in its infancy.7 There are three broad strands of research on the impacts of CV&C on the electricity sector which focus on: (1) supply-side effects; (2) demand-side effects; 8; and (3) both supply and demand side effects.9 This chapter reviews only literature based on supply-side effects. 5

6

7 8

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J. O. Ebinger and W. Vergara, Climate Impacts on Energy Systems: Key Issues for Energy Sector Adaptation (World Bank Publications, 2011); Arent et al., ‘Key economic sectors and services’. S. N. Chandramowli and F. A. Felder, ‘Impact of climate change on electricity systems and markets – a review of models and forecasts’, Sustainable Energy Technologies and Assessments 5 (2014), 62–74. Ibid., 62–74. S. Mirasgedis, Y. Sarafidis, E. Georgopoulou, V. Kotroni, K. Lagouvardos and D. P. Lalas, ‘Modeling framework for estimating impacts of climate change on electricity demand at regional level: case of Greece’, Energy Conversion and Management 48(5) (2007), 1737–50; K. Pilli-Sihvola, P. Aatola, M. Ollikainen and H. Tuomenvirta, ‘Climate change and electricity consumption – witnessing increasing or decreasing use and costs?’ Energy Policy 38(5) (2010), 2409–19; T. Zachariadis and P. Hadjinicolaou, ‘The effect of climate change on electricity needs – a case study from Mediterranean Europe’, Energy 76 (2014), 899–910. T. K. Mideksa and S. Kallbekken, ‘The impact of climate change on the electricity market: A review’, Energy Policy 38(7) (2010) 3579–85; R. Golombek, S. C. Kittelsen and I. Haddeland, ‘Climate change: impacts on electricity markets in Western Europe’, Climatic Change 113(2) (2012), 357–70; D. R. Klein, M. Olonscheck, C. Walther and J. P. Kropp, ‘Susceptibility of the European electricity sector to climate change’ Energy 59 (2013), 183–93.

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Three main approaches are used to assess the impacts of CV&C on electricity generation in the literature. First, some studies use past weather datasets to assess changes in electricity output for different technologies.10 Second, other studies estimate future climate variables using Global Climate Models (GCMs) or Regional Climate Models (RCMs) for given greenhouse gas concentrations and emissions scenarios (for example, IPCC SRES or RCPs, ENSEMBLES, UKCP09), and input these into models.11 The third approach extrapolates future trends based on detected changes in historical records. The patterns observed in past observations can be used in future predictions12 (that is, the Statistical Analogue Resampling Scheme (STARS) approach developed by the Potsdam Institute for Climate Impacts Research) but must be adjusted as more observations become available. The studies used a multitude of baseline/future periods, GCMs/RCMs and emission scenarios; these are not fully reported in this chapter, but can be found in the relevant references. Electricity production may experience positive or negative impacts due to CV&C. For example, Dowling13 notes that in Europe electricity generation using fossil and nuclear fuels is likely to decrease but that based on renewable sources is likely to increase. Impacts of CV&V on electricity generation are considered to be larger in southern Europe than in northern Europe. Hydropower and nuclear facilities have such long life-spans – fifty to sixty years14 – that they will be affected by medium- and long-term climate change impacts: this makes them more vulnerable than those generation technologies that have shorter life-spans (for example, solar panels) – the latter can be replaced or relocated more easily. In Europe, thermoelectric production based on fossil and nuclear fuels will be negatively affected by climate change. The heating and cooling needs of the power plants vary according to the average ambient conditions such as temperature, pressure, humidity and water availability. A modest increase in air temperature may lead to a significant drop in energy supply in areas where thermal power generation dominates.15 A rise in ambient air temperatures of about 1°C would result in total capacity loss of 1.0–2.0 per cent due to decreasing 10

A. Durmayaz and O. S. Sogut, ‘Influence of cooling water temperature on the efficiency of a pressurized-water reactor nuclear-power plant’, International Journal of Energy Research 30(10) (2006), 799–810; M. S. Laković, D. Mitrović, V. Stefanović and M. Stojiljković, ‘Coal-fired power plant power output variation due to local weather conditions. Part A: Recovery, utilization and environmental effects’, Energy Sources 34(23) (2012), 2164–77. 11 P. Seljom, E. Rosenberg, A. Fidje, J. E. Haugen, M. Meir, J. Rekstad and T. Jarlset, ‘Modelling the effects of climate change on the energy system – a case study of Norway’, Energy Policy 39(11) (2011), 7310–21. 12 H. Koch and S. Vogele, ‘Hydro-climatic conditions and thermoelectric electricity generation. Part I: Development of models’, Energy 63 (2013), 42–51. 13 P. Dowling, ‘The impact of climate change on the European energy system’, Energy Policy 60 (2013), 406–17. 14 Ibid. 15 R. Schaeffer, A. S. Szklo, A. F. Pereira de Lucena, B. S. Moreira Cesar Borba, L. P. Pupo Nogueira, F. P. Fleming, A. Troccoli, M. Harrison and M. S. Boulahya, ‘Energy sector vulnerability to climate change: A review’, Energy 38(1) (2012), 1–12.

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efficiency of cooling processes and shutdowns.16 For the summers of 2031–60, the average decrease in the European power plant capacity is estimated to be 6.3–19 per cent, depending on the type of cooling system and climate scenario.17 The literature is univocal that there will be substantial reductions in the mean capacities of thermoelectric power plants in Europe due to the projected substantial increases in water temperatures and reductions in summer flow of water courses.18 More frequent droughts and heatwaves may also result in more frequent partial or full shutdowns of nuclear power plants in the future;19 thermal pollution regulations governing and limiting the discharge of hot water leading to plant shutdowns is one of the main causes of the reduction in electricity generation.20 For example, in France, several nuclear power plants had to reduce generation to comply with thermal pollution regulations during the heatwave of 2003, forcing France to import electricity.21 The most severe impacts of CV&C will be felt in electricity generation in southern Europe,22 as this is where nuclear power plants with the most cooling problems in summer are mainly located.23 In Spain the reduction in summer mean usable electricity capacity is predicted to be 15–21 per cent for 2031–2060 relative to 1971–2000.24 A study in the UK, however, has pointed out that nuclear power plants have not faced cooling problems in recent years.25 The majority of the studies that assess the impacts of CV&C on electricity generation focus on hydro- and wind power. According to Rothstein and Parey,26 hydropower is one of the most vulnerable sources of electricity to climate change. Hydropower potential is defined by river flows or capacity of 16

J. Sieber, ‘Impacts of, and adaptation options to, extreme weather events and climate change concerning thermal power plants’, Climatic Change 121(1) (2013), 55–66. 17 M. T. Van Vliet, J. R. Yearsley, F. Ludwig, S. Vögele, D. P. Lettenmaier and P. Kabat, ‘Vulnerability of US and European electricity supply to climate change’, Nature Climate Change 2(9) (2012), 676–81. 18 M. T. H. Van Vliet, S. Vögele and D. Rübbelke, ‘Water constraints on European power supply under climate change: impacts on electricity prices’, Environmental Research Letters 8 (2013), 3; B. Hoffmann, S. Häfele and U. Karl, ‘Analysis of performance losses of thermal power plants in Germany – A System Dynamics model approach using data from regional climate modelling’, Energy 49 (1) (2013), 193–203; Koch and Vogele, ‘Hydro-climatic conditions and thermoelectric electricity generation’. 19 K. Linnerud, T. K. Mideksa and G. S. Eskeland, ‘The impact of climate change on nuclear power supply’, The Energy Journal 32(1) (2011), 149–68. 20 H. Koch, S. Vögele, F. Hattermann and S. Huang, ‘Hydro-climatic conditions and thermoelectric electricity generation. Part II: Model application to 17 nuclear power plants in Germany’, Energy 69 (2014), 700–7. 21 Klein et al., ‘Susceptibility of the European electricity sector to climate change’. 22 Laković et al., ‘Coal-fired power plant power output variation due to local weather conditions’. 23 D. Rübbelke and S. Vögele, ‘Impacts of climate change on European critical infrastructures: the case of the power sector’, Environmental Science & Policy 14(1) (2011), 53–63. 24 Van Vliet et al., ‘Water constraints on European power supply under climate change’. 25 Rübbelke and Vögele, ‘Impacts of climate change on European critical infrastructures’. 26 B. Rothstein and S. Parey, ‘Impacts of and adaptation to climate change in the electricity sector in Germany and France’, in J. D. Ford and L. Berrang (eds), Climate Change Adaptation in Developed Nations: From Theory to Practice, vol. 42 (Springer, 2011).

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reservoirs. Therefore, changes in flows or quantity of stored water will alter hydropower production. Run of the river hydroelectric plants are designed for specific river flow distribution (based on past observations) and hence their operations will be disrupted by altered flow conditions. Hydropower plants with reservoirs play a key role in ‘storing’ electricity, ensuring the reliability of electricity production. However, CV&C is changing the water inflow patterns into the reservoirs, thus reducing its reliability as a source of energy. Europe’s hydropower potential has been estimated to increase by 4–5 per cent for the period 2031–206027 and up to 6 per cent by the 2070s.28 However, the experience will vary substantially across Europe: southern European countries will experience a substantial decrease in hydropower potential29 while Nordic countries will gain hydropower potential.30 Hydropower potential is also significantly seasonal31 and climate change will alter seasonality. In catchments that rely on snow or ice, the projected increased temperatures will result in increased winter flows and reduced summer flows. Finger et al.32 predict hydropower generation to decrease by over half by the end of the century during the summer months. Loss of natural storage in snow and ice will also need to be compensated by the construction of additional storage capacity to maintain hydropower generation potential.33 27

Van Vliet et al., ‘Water constraints on European power supply under climate change’. B. Lehner, G. Czisch and S. Vassolo, ‘The impact of global change on the hydropower potential of Europe: a model-based analysis’, Energy Policy 33 (2005), 839. 29 R. Pasicko, C. Brankovic and Z. Simic, ‘Assessment of climate change impacts on energy generation from renewable sources in Croatia’, Renewable Energy 46 (2012), 224–31; G. T. Aronica and B. Bonaccorso, ‘Climate change effects on hydropower potential in the Alcantara River basin in Sicily (Italy)’, Earth Interactions 17(19) (2013), 1–22; L. Gaudard and F. Romerio, ‘The future of hydropower in Europe: interconnecting climate, markets and policies’, Environmental Science & Policy 37 (2014), 172–181; S. J. Pereira-Cardenal, H. Madsen, K. Arnbjerg-Nielsen, N. Riegels, R. Jensen, B. Mo, I. Wangensteen and P. Bauer-Gottwein, ‘Assessing climate change impacts on the Iberian power system using a coupled water-power model’, Climatic Change 126(3–4) (2014), 351–64. 30 L. Lundahl, ‘Impacts of climatic change on renewable energy in Sweden’, Ambio 24 (1995) 28–32; Seljom et al., ‘Modelling the effects of climate change on the energy system’; B. Hamududu and Å. Killingtveit, ‘Assessing climate change impacts on global hydropower’, Energies 5(2) (2012), 305–22; H. H. Chernet, K. Alfredsen and Å Killingtveit, ‘The impacts of climate change on a Norwegian high-head hydropower system’, Journal of Water and Climate Change 4(1) (2013), 17–37; Gaudard and Romerio, ‘The future of hydropower in Europe’. 31 D. Carless and P. G. Whitehead, ‘The potential impacts of climate change on hydropower generation in Mid Wales’, Hydrology Research 44(3) (2013), 495–505; P. Mukheibir, ‘Potential consequences of projected climate change impacts on hydroelectricity generation’, Climatic Change 121(1) (2013), 67–78; S. Maran, M. Volonterio and L. Gaudard, ‘Climate change impacts on hydropower in an alpine catchment’, Environmental Science & Policy 43 (2014), 15–25. 32 D. Finger, G. Heinrich, A. Gobiet and A. Bauder, ‘Projections of future water resources and their uncertainty in a glacierized catchment in the Swiss Alps and the subsequent effects on hydropower production during the 21st century’, Water Resources Research 48(2) (2012), available at http://onlinelibrary.wiley.com/doi/10.1029/2011WR010733/abstract 33 R. Westaway, ‘Modelling the potential effects of climate change on the Grande Dixence hydroelectricity scheme, Switzerland’, Journal of the Chartered Institution of Water and Environmental Management 14(3) (2000), 179–85. 28

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Wind energy cannot be naturally stored and its generation must be smoothed before entering the grid. Hueging et al.34 show that changes in the annual mean wind energy density (WED) are small across Europe up to the end of the twenty-first century (small inter-annual variability). However, there are geographical and seasonal changes and differences. Some studies suggest an increase in wind power potential in northern Europe and a decrease in southern Europe.35 Seasonal changes in WED may be substantial (high intra-annual variability). A significant increase in wind energy potential is predicted for northern and central Europe during wintertime but the potential will decrease for summer months.36 In southern Europe, an increase of wind potential is predicted for summer months, especially in the coastal areas, while a decrease of potential is predicted for winter months.37 However, there are substantial uncertainties associated with the modelling processes, the selection of scenarios and the estimation of the empirical relationship between wind speed and wind energy.38 Solar energy generation can be impacted by extreme weather events (such as hail or heavy storms) and increased air temperature, which can alter photovoltaic (PV) cells’ efficiency and reduce generation rate. Predicted reduction of aerosol emissions can lead to substantial increase in surface solar radiation over Europe and increase PV energy generation productivity.39 In northern Europe (the UK in particular), current solar energy potential already offers a huge untapped potential.40 For the 2030s, a statistically significant reduction in 34

H. Hueging, R. Haas, K. Born, D. Jacob and J. G. Pinto, ‘Regional changes in wind energy potential over Europe using regional climate model ensemble projections’, Journal of Applied Meteorology and Climatology 52(4) (2013), 903–17. 35 Ibid., 903–17; I. Tobin, R. Vautard, I. Balog, F. M. Bréon, S. Jerez, P. M. Ruti, F. Thais, M. Vrac and P. Yiou, ‘Assessing climate change impacts on European wind energy from ENSEMBLES high-resolution climate projections’, Climatic Change 128(1–2) (2014), 99–112. 36 S. C. Pryor, R. J. Barthelmie and E. Kjellström, ‘Potential climate change impact on wind energy resources in northern Europe: analyses using a regional climate model’, Climate Dynamics 25(7–8) (2005), 815–35; G. P. Harrison, L. C. Cradden and J. P. Chick, ‘Preliminary assessment of climate change impacts on the UK onshore wind energy resource’, Energy Sources, Part A: Recovery, Utilization and Environmental Effects 30(14–15) (2008), 1286–99; P. Nolan, P. Lynch, R. McGrath, T. Semmler and S. Wang, ‘Simulating climate change and its effects on the wind energy resource of Ireland’, Wind Energy 15(4) (2012), 593–608; J. Wachsmuth, A. Blohm, S. Gößling-Reisemann, T. Eickemeier, M. Ruth, R. Gasper and S. Stührmann, ‘How will renewable power generation be affected by climate change? The case of a metropolitan region in Northwest Germany’, Energy 58 (2013), 192–201. 37 Pasicko, Brankovic and Simic, ‘Assessment of climate change impacts’; J. A. Santos, C. Rochinha, M. L. R. Liberato, M. Reyers and J. G. Pinto, ‘Projected changes in wind energy potentials over Iberia’, Renewable Energy 75 (2015), 68–80. 38 L. C. Cradden, G. P. Harrison and J. P. Chick, ‘Will climate change impact on wind power development in the UK?’, Climatic Change 115(3–4) (2012), 837–52. 39 J. A. Crook, L. A. Jones, P. M. Forster and R. Crook, ‘Climate change impacts on future photovoltaic and concentrated solar power energy output’, Energy and Environmental Science 4(9) (2011), 3101–9; Dowling, ‘The impact of climate change’; M. Gaetani, T. Huld, E. Vignati, F. Monforti-Ferrario, A. Dosio and F. Raes, ‘The near future availability of photovoltaic energy in Europe and Africa in climate-aerosol modeling experiments’, Renewable and Sustainable Energy Reviews 38 (2014), 706–16. 40 D. Burnett, E. Barbour and G. P. Harrison, ‘The UK solar energy resource and the impact of climate change’, Renewable Energy 71 (2014), 333–43.

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PVE productivity is predicted for eastern Europe, whilst a significant increase is predicted in western and southern Europe.41 Few studies have examined the impact of CV&C on bioenergy and wave energy production in Europe. Bioenergy potential is projected to increase in northern Europe due to climate change and technological developments, and in southern Europe the adverse effects of climate change are expected to be compensated by technological advances.42 Forest bioenergy could be adversely affected by rapid climate change, but short rotation biomass production could adapt to changing environmental conditions43 and hence provide a reliable source of bioenergy. In Scotland, wave power potential is positively related to wind speeds44 and in Cornwall the available wave power will increase by 2–3 per cent by 2100.45 CONCLUSION This chapter synthesised the findings of the peer-reviewed literature on the impacts of CV&C on electricity generation in Europe. Although substantial uncertainties surround the results of such studies, they provide very informative trends of the potential situations infrastructure managers and policymakers will have to deal with in the future. Taken as possible scenarios rather than predictions, they are also indicative of a plausible mix for future electricity supply under CV&C. Thermoelectricity generation (fossil fuel and nuclear) is expected to decrease across Europe due to CV&C. Hydro- and wind-power electricity generation potential is to increase in northern Europe but decrease in southern Europe. Solar power is still largely untapped but presents huge possibilities for future electricity generation, especially in southern Europe. Studies on bioenergy and wave energy production are still too few and need further research. Additionally, as electricity systems are planned or operated at national and subnational scales, more impact analyses should be carried out at a scale that is more meaningful for managing electricity infrastructure and formulating policies now and for the future.

41

Gaetani et al., ‘The near future availability of photovoltaic energy’; I. S. Panagea, I. K. Tsanis, A. G. Koutroulis and M. G. Grillakis, ‘Climate change impact on photovoltaic energy output: The case of Greece’, Advances in Meteorology 2014 (2014), available at www.hindawi.com/ journals/amete/2014/264506 42 S. L. Cosentino, G. Testa, D. Scordia and E. Alexopoulou, ‘Future yields assessment of bioenergy crops in relation to climate change and technological development in Europe’, Italian Journal of Agronomy 7(2) (2012), 154–66. 43 Lundahl, ‘Impacts of climatic change on renewable energy in Sweden’. 44 G. P. Harrison and A. R. Wallace, ‘Climate sensitivity of marine energy’, Renewable Energy 30(12) (2005), 1801–17. 45 D. E. Reeve, Y. Chen, S. Pan, V. Magar, D. J. Simmonds and A. Zacharioudaki, ‘An investigation of the impacts of climate change on wave energy generation: The Wave Hub, Cornwall, UK’, Renewable Energy 36(9) (2011), 2404–13.

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THE EXTERNAL DIMENSION OF CROSSBORDER ELECTRICITY TRANSMISSION PLANNING IN THE EU Karolis Gudas1

The European Union has been facilitating construction of internal and external cross-border electricity transmission lines since the adoption of the Electricity Transit Directive in 19902 and the Maastricht Treaty in 1992.3 It has sought the cooperation of all of its neighbouring states, in particular Libya, the southern Mediterranean region, Switzerland and Russia. The areas for cooperation include renewable energy integration and facilitation of large-scale infrastructure projects linking the EU’s electricity networks to third countries.4 In fact, only a few EU member states are connected with the transmission systems of third countries. Switzerland is highly interconnected with Austria, Germany, France and Italy. Lithuania, Latvia and Estonia are part of the BRELL electricity system,5 which synchronously operates with Russia and Belarus. 1

2 3

4

5

Karolis Gudas is a PhD Research Fellow at the World Trade Institute, University of Bern and the Swiss National Centre of Competence in Trade Regulation. He is a dispute resolution lawyer at Motieka & Audzevicius and a former Junior Fellow at the European Commission, Institute for Energy. Council Directive 90/547/EEC ‘On the Transit of Electricity Through Transmission Grids’. Title XII of the Maastricht Treaty; see also the regulatory framework which is in force in the EU on the trans-European networks: Title XVI of the Treaty of Functioning of the European Union. See ‘The EU Energy Policy: engaging with partners beyond our borders’, Communication from the Commission to the European Parliament, the Council, the European Economic and Social Committee and the Committee of the Regions. On security of energy supply and international cooperation (7 September 2011). The BRELL electricity loop is part of the wide area transmission system known as IPS/UPS (integrated power system/unified power system), which historically covered the territory of the former Soviet Union states.

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Finland has several transmission interconnections with Russia. A few other third countries have transmission lines with the EU and could potentially benefit from the implementation of projects of common interest.6 To a large extent, however, the electricity lines with third countries are the consequence of the historical cooperation between the transmission system operators and of changes to the borders of the EU. The contribution of the EU-level policies has been minor, with the exception of the establishment of the Energy Community, which imports the EU’s energy policies to non-EU states.7 This is for several reasons. First, none of the key agreements in the electricity sector have been concluded between the EU and its neighbouring states (including the agreement with Switzerland and Russia). Second, the EU’s investment regimes in the new cross-border transmission projects are typically subject to strict geographical limitations. This chapter suggests liberalising the regulatory framework for merchant investments8 in cross-border electricity infrastructures in the context of cooperation with third states. The first section briefly outlines the investment in cross-border transmission project options and the nature of incentives. The second section provides an overview of the limitations on merchant investment in cross-border electricity transmission links. OVERVIEW OF THE TRANSMISSION INVESTMENT INCENTIVE REGIMES The expansion of cross-border electricity networks in the EU is largely driven by the objectives of security of supply, environmental protection, increased electricity transfers and secured flexibility of electricity systems.9 The EU rules allow, under certain conditions, investments in new cross-border interconnectors by the transmission system operators and merchant investors. The new interconnectors might also be constructed through government intervention. Each of the investment options – i.e. (1) with state intervention; (2) by a transmission system operator; or (3) by a merchant investor – is subject to different eligibility and incentive regimes. 6

7

8

9

Annex I, ‘Electricity Infrastructure Priority Corridors and Areas’ of Regulation No 347/2013 of the European Parliament and of the Council ‘On guidelines for trans-European energy infrastructure’. Many preferential trade agreements between EU and third states declare the intention to facilitate the development of cross-border electricity transmission lines, but provide no legal mechanisms for the authorisation of the construction of such infrastructure. The term ‘merchant investment’ refers to investment by a third party in the construction and operation of the transmission line, which creates the transmission rights for the investor, either physical or financial. In this context, this chapter examines the new interconnectors regime stipulated under Article 17 of Regulation no. 714/2009 of the European Parliament and the Council, ‘On conditions for access to the network for cross-border exchanges in electricity’. See Communication of 5 November 2013 from the European Commission, ‘Delivering the internal electricity market and making the most of public intervention’.

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Merchant investments,10 for a limited period of time, may be partially or fully exempted from certain market rules, such as third-party access, unbundling requirements or balancing services.11 Transmission projects, which qualify as projects of common interest,12 may benefit from the merchant investment regime, provided that the relevant conditions are met, and additional incentives.13 These include the services of a European coordinator, facilitated and coordinated permit-granting procedures, lower administrative costs and financial support. Moreover, a cross-border electricity transmission project might be treated as a project contributing towards security of supply, in which case it may benefit from merchant investments, facilitated maintenance and renewal of electricity networks, specific commitments of a state.14 Alternatively, it might be treated as a project contributing towards meeting the national renewable energy targets and could thus benefit from renewable energy support mechanisms.15 Finally, the EU facilitates the construction of cross-border electricity transmission links under particular instruments, such as the European Energy Programme for Recovery (EEPR).16 The EEPR provides the legal basis for certain cross-border electricity transmission projects to benefit from financial support, more efficient administrative authorisation and licensing/certification procedures.17

10

Merchant investments, according to Article 17.1(a–f) of Regulation 714/2009 are subject to six conditions: (1) the investment must enhance competition in electricity supply; (2) the level of risk attached to the investment must be such that the investment would not take place unless an exemption is granted; (3) the interconnector must be owned by a natural or legal person which is separate from the system operators; (4) charges are levied on users of that interconnector; (5) no part of the capital or operating costs of the interconnector has been recovered; (6) the exemption must not be to the detriment of competition or the effective functioning of the regulated system to which interconnector is linked. 11 Article 17.1 of Regulation 714/2009. 12 See A. Johnston and G. Block, EU Energy Law, 1st edn (Oxford University Press, 2012), pp. 151–7. 13 Projects of common interest are projects of European interest, which fall under thematic areas or electricity corridors listed by the European Union. See both general and specific criteria for projects of common interest: Article 4 of Regulation 347/2013 of the European Parliament and of the Council ‘On guidelines for trans-European energy infrastructure’. 14 Article 6 of Directive 2005/89/EC of the European Parliament and of the Council ‘Concerning measures to safeguard security of electricity supply and infrastructure investment’. 15 Articles 9–11 of Directive 2009/28/EC of the European Parliament and of the Council ‘On the promotion of the use of energy from renewable energy sources’: the Renewable Energy Directive allows member states of the EU to implement joint projects between member states and with third countries. Member states may apply to the European Commission for the construction of an interconnector with a third country, which would be used for the export of electricity produced from renewable energy sources to the EU. 16 Johnston and Block, EU Energy Law, p. 158. 17 Article 24 of Regulation 663/2009 of the European Parliament and of the Council ‘Establishing a programme to aid economic recovery by granting community financial assistance to projects in the field of energy’.

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The investments made by the transmission system operator or through intervention by the state are mainly subject to the decision of the state and/or the transmission system operator. Most such investments are expected to be financed from tariffs paid by the users of the transmission system.18 Transmission system operators are also encouraged to use their revenues for building new transmission links.19 MERCHANT INVESTMENT REGIME AND LIMITATIONS Merchant transmission investments require exemption from certain market rules. Exemption from the market rules place the traders of electricity, competing in the same markets, in different positions. Merchant investment projects are therefore not generally regarded as the most favourable policy option. However, merchant investments may become critical in cases when neither the state nor the transmission system operator takes the initiative to implement cross-border electricity transmission projects. Yet merchant transmission investment option is subject to strict limitations, irrespective of the potential size of the contribution towards meeting the EU’s policy objectives. Four limitations and suggested policy changes are discussed below. First, merchant transmission is not eligible for most of the incentives facilitating authorisation and permit-granting procedures when compared to the projects that qualify as being of common interest or that fall under the scope of the EEPR (see above). The complexity and lack of harmonisation of planning and authorisation procedures, as well as legal objections, have substantially complicated implementation of cross-border electricity infrastructures.20 Therefore, most of the regulatory incentives that are designed to facilitate procedures for authorisation and granting of permits for cross-border electricity infrastructures should be viewed as the standards of good governance applicable to all cross-border electricity infrastructures, rather than as incentives. Ideally, the EU should establish a regulatory framework harmonising procedural and substantive rules related to construction and authorisation of cross-border electricity infrastructures.21 Second, the merchant transmission option is limited to the transmission projects that connect at least two member states of the EU. Regulation 714/2009 allows only new ‘interconnectors’ to benefit from the exemption rules. It limits the definition of an ‘interconnector’22 to a transmission line that crosses or spans a border between member states and which connects the national transmission 18

Communication of 10 November 2010 from the Commission to the European Parliament, the Council, the European Economic and Social Committee and the Committee of the Regions ‘Energy 2020. A strategy for competitive, sustainable and secure energy’. 19 Article 16.6 of Regulation 714/2009. 20 See Communication of 10 January 2007 from the Commission to the Council and the European Parliament entitled ‘Priority interconnection plan’; also European Network of Transmission System Operators for Electricity, ‘ENTSO-E Position Paper on permitting procedures for electricity transmission infrastructure’, 2010. 21 At present, the EU is considering the adoption of three network codes harmonising rules regarding the connection to the grid. 22 Notably, the Electricity Directive of 2009 provides a definition of the ‘interconnector’ corresponding to any ‘equipment used to link electricity systems’.

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systems of the member states. In other words, if the ‘interconnector’ does not connect the transmission systems of at least two member states, then it is not eligible for the exemption from third-party access and other market rules. However, since many of the European electricity systems are interconnected and share the installed electricity generation capacity, such a limitation might go against the nature of the investment regime itself. This is provided that making a contribution towards the objectives set by the EU might be possible by connecting to one of the European states. Moreover, the interconnectivity level of transmission systems between the EU member states has been increasing ever since the European Council set the 10 per cent interconnectivity target in 2005. Third, the regulatory framework for merchant transmission promotes the use of direct current interconnectors. The EU rules allow the use of alternating current technology only in exceptional cases, mainly where the costs and risks of the investment in question are particularly high compared with the costs and risks normally incurred when connecting two neighbouring national transmission systems.23 In fact the direct current interconnectors are conventional solutions for long-distance submarine electricity transmission or connection of unsynchronised electricity networks, but the best option between overhead alternating and direct current transmission technologies is less clear. Many electricity systems have developed based on the use of alternating current technology. The costs of this technology for distances not exceeding 600–700 km are argued to be lower.24 The framework for the merchant investments should, therefore, leave the options between alternating and direct current open to be decided on a case-by-case basis subject to security, economic and reliability requirements. Finally, in order for a new merchant interconnector to qualify for the exemption from market rules, it is required to enhance competition in electricity supply. Given the nature of the financial risks involved in the decision to invest in the transmission system, competition rules discourage potential investments in new transmission projects as they offer possibilities to benefit from the investment to third parties that did not take any risk. Provisions on deviation from the competition rules should be more flexible in return for the investment. However, the European Commission exemption decisions feature limitations,25 which undermine the potential for large-scale investments in the capital-intensive electricity network. Literature provides evidence that letting dominant generators undertake merchant transmission investment may be beneficial, if potential abuses of dominance are mitigated.26

23

Article 17.2 of Regulation 714/2009. Note that both alternating current and direct current have been extensively researched. Scientific contributions argue that both these technologies have their own advantages and disadvantages. On factors affecting transmission growth and transmission technologies, see T. Gonen, Electrical Power Transmission System Engineering: Analysis and Design, 3rd edn (California State University, 2014). 25 See European Commission Exemptions for New Electricity Infrastructures on Estlink (27 April 2005); on East-West Cable (19 December 2008). 26 See A. de Hauteclocque and V. Rious, ‘Reconsidering the European regulation of merchant transmission investment in light of the third energy package: the role of dominant generators’, Energy Policy 39(11), 7068–70. 24

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CONCLUSION Trade in electricity with third countries is an important dimension of the EU’s energy policies. However, development of cross-border electricity links with third countries is strictly limited. In respect of the rules on merchant transmission investment, this chapter suggests several policy changes: (1) to allow merchant investments to benefit from regulatory incentives facilitating permit-granting and authorisation procedures; (2) to broaden the definition of the ‘interconnector’ to the equipment used to link electricity systems; (3) to eliminate preferential treatment of the direct current technology by allowing the decision on the transmission technology to be made on a case-by-case basis; and (4) to provide more leeway to deviate from the competition rules.

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38

INTEGRATING VEHICLES AND THE ELECTRICITY GRID TO STORE AND USE RENEWABLE ENERGY David Hodas1

The world is awash in fossil fuels, plentiful largely due to technological innovations, such as fracking. Atmospheric concentrations of CO2 now exceed 400 parts per million. According to the International Energy Agency, carbon intensity (carbon emissions per $ of economic activity), which has been flat for forty years, must decline 5.7 per cent by 2020, 43 per cent by 2035 and over 60 per cent by 2050 to limit warming to 2°C.2 This is a daunting challenge. Just as the Stone Age did not end due to a lack of stones, over the next century the fossil fuel age will not end for a lack of fossil fuels, but will only end when fossil fuel buyers switch to an economy driven by electricity produced from renewable energy, a trend that is already beginning.3 The world could be powered by efficiently used renewable energy. There is more than enough renewable energy to do this: more energy from the sun 1

2 3

David Hodas is is Distinguished Professor of Law at Delaware Law School – Widener University. He teaches and writes on Sustainable Energy Law and Policy, Climate Change Law, Environmental, Administrative and Constitutional Law. He co-authored Climate Change Law: Mitigation and Adaptation (West-Thomson Reuters, 2009), is a member of the Energy Expert Group of the IUCN Environmental Law Commission, chairs the State of Delaware Governor’s Energy Advisory Council and is an editor of the IUCN Academy of Environmental Law e-journal. Professor Hodas has a BA cum laude and with honours in political science, Williams College (1973); a JD cum laude, Boston University School of Law (1976); and an LLM in Environmental Law (Feldshuh Fellow), Pace University School of Law (1989). International Energy Agency, Tracking Clean Energy Progress 2015 (IEA, 2015). Electricity is the fastest-growing final form of energy, yet the power sector contributes more than any other to the reduction in the share of fossil fuels in the global energy mix. International Energy Agency, World Energy Outlook 2014 Executive Summary, 1–4 (2014).

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hits the earth in one hour than all of the energy consumed on our planet in an entire year.4 We already capture some of this energy with solar, wind and hydroelectric technology and convert that energy into useful electric power. Critically, achieving a low-carbon economy is less technology dependent than it is dependent on new, well-designed energy law: ‘[National and international] policy and regulatory frameworks . . . will determine whether investment and consumption decisions are . . . low carbon’.5 Reduced fossil fuel use requires well-designed sustainable energy laws and policies that promote efficient use of renewable energy: a new legal paradigm is needed that broadly shifts private incentives towards efficient use of renewable energy. A major renewable energy challenge is how to economically store solar and wind energy for use when it is needed as electricity. Another major challenge is how to power transportation with only minimal use of fossil fuels, while simultaneously adding at least 100 million new cars and light trucks in India, China and other economically growing nations. Vehicle-to-grid (V2G) electric cars could be a game-changing technology to address these enormous challenges. V2G vehicles offer the opportunity to integrate separate energy conversion systems: the electricity grid and light vehicle transportation fleet. The electricity transmission grid, the greatest engineering feat of the twentieth century, is limited by its lack of electricity storage capacity; it must generate and deliver electricity the instant it is needed, at widely dispersed locations and at multiple, often unpredictable, times. To meet this demand, the grid has immense electric power generating capacity. Energy for the grid is stored in the form of coal piles, natural gas pipelines, nuclear fuel and water behind large dams for use at stationary electric generation facilities to meet electricity demand. It does not matter which plant or fuel source generates the electric power, so long as the plant is connected to the grid. In contrast, motor vehicles are mobile and, unlike electricity, transportation energy needs are fairly predictable. The energy, however, must be in the vehicle when it is driven. V2G electric (or hybrid electric) vehicles offer a technology that could symbiotically integrate the electric grid and transportation energy systems. V2G technology, which uses electric vehicle batteries to store and return energy to the electric grid based on real-time signals that communicate the grid’s instantaneous needs to the vehicle, would meet the needs of both the grid operator and the vehicle driver. The grid needs power (instantaneous flow from an energy source) at varying times, but does not care which power plant (or V2G vehicle) supplies the power. The vehicle, on the other hand, needs stored energy at fairly predictable times (when the trip begins) but the (non-fleet) average vehicle is idle 96 per cent of the time.6 The grid could use power stored in idle V2G batteries 4 5 6

N. Lewis, ‘Powering the planet’, MRS Bulletin 32(10) (2007), 808–20. International Energy Agency, World Energy Outlook 2009 (IEA, 2009), p. 5. C. Gorguinpour, Office of the Assistant Secretary of the Air Force, ‘DOD electric vehicle program: the DOD V2G pilot project’ (2013), available at http://electricvehicle.ieee.org/files/2013/03/DoD-Plug-InElectric-Vehicle-Program.pdf

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whenever needed, yet each vehicle would be tapped only within the constraints of its driver’s specific schedule and driving needs. It is useful to compare the power capacity of these systems. The 2013 US electricity grid power generation capacity was about 1,065 GW.7 The US light vehicle fleet has about 236 million petrol and diesel vehicles.8 The average vehicle could generate 222 horsepower, which is equivalent to 165.6 kWm (mechanical kW).9 The total light vehicle fleet power capacity, 39,081 GW, is over thirty-six times the power-generation capacity of the entire US electrical generation system!10 A comparison of the power capacity of the electric grid with electric vehicles is similarly instructive. For example, the Nissan Leaf battery can deliver 85 kW peak power and the Tesla Model S 85 performance can deliver 310 kW.11 For the purposes of this analysis we can conservatively assume a fleet of V2G cars with an average peak power rating of just 50 kW.12 In that case, 20 million V2G vehicles would have the combined power capacity of around 1,000 GW, which is roughly equivalent to the entire US electric grid power capacity, even though these cars would amount to less than 10 per cent of the US light duty vehicle fleet. A V2G system could not only supply the grid’s electricity storage needs, but could also promote broader integration and more efficient use of intermittent renewable energies, such as wind and solar power. A well-integrated combination of wind power, solar power and V2G battery storage could power the grid up to 99.9 per cent of the time.13 This storage would virtually eliminate the intermittency problem renewables face – they do not generate electricity when the sun does not shine or the wind does not blow, and they may not be able to sell all the electricity when solar and wind energy is high because the grid may not need it then. In a V2G system, solar and wind facilities could have a much higher grid capacity rating, directly lowering the financial cost of renewable electricity. Moreover, V2Gs can improve power grid stability and robustness.14 7

US Energy Information Agency, Annual Energy Outlook 2015 (EIA, 2015), table: Electricity Generating Capacity 8 US DOT Bureau of Transportation Statistics, National Transportation Statistics (2015), Table 1-11. 9 US EPA, ‘Light duty automotive technology, CO2 emissions and fuel economy trends 1975–2013’, Executive Summary (December 2013), 5. 10 This discussion is based on an update of the analysis first presented in W. Kempton and J. Tomić, ‘Vehicle to grid power implementation: From stabilizing the grid to supporting large-scale renewable energy’, Journal of Power Sources 144 (2005), 280–90. 11 E. Rask, T. Bohn and K. Gallagher, ‘On charging equipment and batteries in plug-in vehicles: present status’, Innovative Smart Grid Technologies, 2012 IEEE PES (2012) (abstract); full presentation available at https://anl.app.box.com/s/ckv6muyjp15u4g7qaijryeqi4tuhx8e2IEEE ISGT Conference (2012). 12 A. A. Pesaran, T. Markel, H. S. Tataria, and D. Howell, ‘Battery requirements for plug-in hybrid electric vehicles – analysis and rational’, National Renewable Energy Lab Conference Paper NREL/CP-540-42240 (July 2009). 13 C. Budischak, D. Sewell, H. Thomson, L. Machd, D. E. Veronc and W. Kempton, ‘Cost-minimization combinations of wind power, solar power and electrochemical storage, powering the grid up to 99.9% of time’, Journal of Power Sources 225 (2013), 60–74. 14 A. Gajduk, ‘Improving power grid transient stability by plug-in electric vehicles’ New Journal of Physics 16 (2014), 115011

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The business model for V2Gs would first tap high value, time-critical electric power services, spinning reserves and frequency regulation. As the regulation and spinning reserves markets saturate, V2G vehicles could begin providing peak power and renewable energy storage capacity. Over time, about half to one-third of the fleet would be V2G vehicles serving as back-up power and storage for renewable energy, thereby virtually eliminating the renewable energy intermittency problem.15 As noted, the first stage of implementing a V2G system would be to use V2G vehicles to provide frequency regulation services to the grid operator. Frequency regulation refers to maintaining a consistent level of voltage at all points in the grid. Today, frequency regulation is expensive and relatively slow because it requires turning power plants on or off, or up and down in response to voltage or frequency problems detected in the grid. V2G cars could provide the same service, but much faster, more precisely and where it needed. The energy stored in the vehicles would be available to provide electricity to the grid when parked at home or work, and most cars are driven less than one hour per day. When power is needed to raise frequency, V2G vehicles would be signalled to supply power immediately. When the grid has too much power, the excess power would be sent to V2G vehicles to lower the frequency and store energy for future use. These V2G vehicles, when parked, would be mini-power plants.16 Vehicle owners would be paid for the services provided. Recent pilot tests of this system indicate that vehicle owners, who would be paid for the services provided, could earn about $210 per month.17 Implementation would be relatively easy, depending on the legal and business model chosen.18 One approach would have a company contract with V2G owners, aggregating them into bundles representing at least 1 MW. The grid operator would contract with the aggregator to supply frequency regulation services in bundles of at least 1 MW. The grid operator would buy the regulation services as needed through the aggregator. The aggregator would pay the individual V2G owners. In terms of legal implementation all that would be needed initially is the statutory and regulatory authority for this contracting system. In the United States, the grid operators already have the federal and state authority to purchase regulation services, which they do many times every 15

W. Kempton and J. Tomić, ‘Vehicle to grid power implementation: From stabilizing the grid to supporting large-scale renewable energy’, Journal of Power Sources 144(1) (2005), 280–90. 16 J. Motavalli, ‘Electric cars provide power back to the grid (and get paid for it)’ (26 April 2013), available at www.plugincars.com/payback-v2g-electric-cars-provide-power-grid-and-get-paidit-127091.html 17 Gorguinpour, ‘DOD Electric Vehicle Program’. See also S. Shepard and J. Garner, Vehicle Grid Integration: VGI Applications for Demand Response, Frequency Regulation, Microgrids, Virtual Power Plants, and Renewable Energy Integration (Navigant Research, 2015) (Executive Summary), available at www.navigantresearch.com/wp-assets/brochures/VGI-15-Executive-Summary.pdf 18 W. Kempton, F. Marra, P. B. Andersen and R. Garcia-Valle, ‘Business models and control and management architectures for EV electrical grid integration’, in R. Garcia-Valle and J. A. Pecas Lopes (eds), Electric Vehicle Integration Into Modern Power Networks (Springer Science + Business Media, 2013), pp. 87–105.

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day from gas-fired power plant owners. However, state utility laws must be modified to permit V2G aggregation. Much of the V2G work has been located in state of Delaware where a statute was enacted in 2009 establishing the legal framework for V2G technology.19 The law creates the legal concepts of ‘aggregator’20 and ‘grid-integrated electric vehicle’,21 and specifically authorises payments from the aggregator to grid-integrated electric vehicle (V2G) owners.22 Beyond this first step, there will be legal and policy questions as investment shifts to a renewable electricity system linked to V2G. Federal, regional and state statutory and regulatory aggregation policy instruments will be needed, along with new net and smart metering laws and regulations. Grid challenges such as cyber security and reliability standards (national and international) will need to include V2G. Law will need to address a variety of V2G infrastructure issues, such as the widespread availability of V2G connections in car parks and on-street parking, property and tax laws relating to building owners, home owners, tenants, employers and employees. Transmission capacity and electricity distribution networks will need to be upgraded to twenty-first century standards, a present need even without V2G. The benefits of a V2G system could be enormous, dramatically enhancing the prospects of shifting to a low-carbon energy system. As renewables replace coal, petrol and natural gas, CO2 emissions and the adverse health effects of air pollution from burning fossil fuels to generate electricity will rapidly reduce. In addition, pollution from fossil fuel powered motor vehicles will greatly reduce, as electric and hybrid-electric V2G cars replace existing vehicles. A renewable energy V2G system, when combined with improved electricity efficiency, could replace fossil fuels in many regions.

19

Delaware Code 26, Sec. 1001 (1) and (14), and Delaware Code 26, Sec. 1014. ‘“Aggregator” means any person or entity who contracts with an . . . electric supplier or PJM Interconnection . . . to provide energy services which facilitate battery storage systems for gridintegrated electric vehicles and related technologies’, Delaware Code 26, Sec. 1001 (1). 21 ‘“Grid-integrated electric vehicle” means a battery-run motor vehicle that has the ability for two-way power flow between the vehicle and the electric grid and the communications hardware and software that allow for the external control of battery charging and discharging by . . . [an] electric supplier, PJM Interconnection, or an aggregator’, Delaware Code 26, Sec. 1001 (14). 22 ‘A retail electric customer having . . . one or more grid-integrated electric vehicles shall be credited in kilowatt-hours (kWh) for energy discharged to the grid from the vehicle’s battery at the same kWh rate that customer pays to charge the battery from the grid . . . [G]rid-integrated electric vehicle must meet the requirements in . . . this section. Connection and metering of grid integrated vehicles shall be subject to the rules and regulations in . . . this section.’ Delaware Code 26, Sec. 1014 (g). 20

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A STITCH IN TIME: COULD IRELAND’S FORTHCOMING WHITE PAPER BREATHE NEW LIFE INTO ITS BRAVE BUT FALTERING RENEWABLE ELECTRICITY POLICY? Eva Barrett1

Ireland’s renewable energy policy is at a pivotal point. While many constructive moves have been made by the Irish government to increase renewable energy, it has not reached the levels required by the EU.2 In addition, local opposition to wind development and its supporting infrastructure is on the increase;3 competition in Ireland’s energy development and supply markets is low;4 electricity 1

2

3

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Dr Eva Barrett is a Lecturer in Law at National University of Ireland Maynooth and an Adjunct Assistant Professor (lecturing Energy Law and Policy in the European Union) at Trinity College Dublin. She qualified as a solicitor while working for a large Irish commercial law firm in 2009, and subsequently worked in the European Commission in Brussels and at the Institute of International and European Affairs in Dublin. In 2014 she was elected Vice-President of Energy Law Ireland. Directive 2009/28/EC of 23 April 2009 on the promotion of the use of energy from renewable sources and amending and subsequently repealing Directives 2001/77/EC and 2003/30/EC (2009) OJ L 140/16 (hereafter ‘Renewable Energy Directive’), annex II. See generally National Economic and Social Council, ‘Wind energy in Ireland: building community engagement and social support’, NESC Report 139 (14 July 2014), available at http:// files.nesc.ie/nesc_reports/en/139_Wind_Energy_Main_Report.pdf; V. Browne, ‘EirGrid pylon plan shows contempt for the people’, Irish Times (8 January 2014); F. McDonald, ‘Rural Ireland rises up against EirGrid plans to build several hundred pylons in southeast: EirGrid say such grid reinforcement is necessary to ensure supply in future’ Irish Times (16 November 2013). The Irish development and supply markets cannot currently be described as ‘effectively competitive’, using the ordinary meaning of this term. In the second quarter of 2014, the governmentowned Electric Ireland held 62.18 per cent of the development market (in terms of customer numbers); 46 per cent of the plants operating in the development/production market and owned both the transmission and distribution systems. See ESB, Innovations for Generations. Annual Report and Accounts 2013’ (ESB, 13 March 2014), available at www.esb.ie/main/about-esb/ annual-report-2013.jsp; Commission for Energy Regulation, ‘Electricity & gas Retail Markets Report Q2 2014 Information Paper’, CER Report (13 November 2014) CER/14/768.

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prices have risen to the point where a general level of consumer affordability may not be deliverable;5 and Ireland is currently the subject of infringement proceedings for failing to transpose the provisions of the Renewable Energy Directive which require Ireland to reach specific renewable energy levels.6 To address these (and other problems afflicting the sector) the Irish government is currently finalising a White Policy Paper to ‘adopt a long term view on the interventions necessary to shape future energy policy.’7 This chapter seeks to analyse the background to the forthcoming Irish White Policy Paper to answer the question of whether it has a realistic chance of rejuvenating Ireland’s renewable energy policy, to enable the Irish government to reach the renewable energy levels required by the European Union. IRELAND’S RENEWABLE ELECTRICITY PLEDGE On 1 July 2010, the Irish government made a brave promise. It pledged that by 2020, 40 per cent of Ireland’s electricity would be produced from renewable energy, and primarily from onshore wind.8 The renewable electricity pledge was described by the International Energy Agency as one of the most ambitious in the world.9 It was contained in the government’s national renewable energy action plan, which was submitted to the European Commission, to provide detail of Ireland’s path to consuming 16 per cent of its energy from renewable resources by 2020 (an obligation placed on Ireland by the EU’s Renewable Energy Directive).10 While the national renewable energy action plan also provided final and interim targets for the use of renewable energy in the heating and cooling and transport sectors for 2020 and the preceding years, the focus was placed squarely on the electricity sector as the sector expected to make the greatest contribution to Ireland’s achievement of its 16 per cent target.

5

The European Bank for Reconstruction and Development benchmark for the general affordability of utilities (including electricity, gas and water) is that together they should not exceed 25 per cent of all household expenditure; this percentage is currently being exceeded in Ireland. See E. Barrett, ‘“Getting the price right”. Could a reintroduction of temporary price controls solve the problem of increasing renewable energy in Ireland while simultaneously guaranteeing affordable electricity to domestic consumers?’ (2014) 37 Dublin University Law Journal 37(1) (2014), 31–53. 6 Case C-236/14, Commission v. Ireland (2014) OJ L 140/16. European Commission, ‘Renewable energy: Commission refers Ireland to Court for failing to transpose EU rules’, Commission Press Release (21 January 2014), available at http://europa.eu/rapid/press-release_IP-14-44_en.htm 7 P. Rabbitte, ‘Speech at the launch of the energy policy Green Paper’, Croke Park, Dublin (12 May 2014), available at www.dcenr.gov.ie/Corporate+Units/Press+Room/Speeches/2014/Minister+Rabbitte++Speech+at+launch+of+Energy+Policy+Green+Paper.htm (note that the Green Paper is designed to inform the finalisation of the White Energy Policy Paper). 8 Department of Communications, Energy and Natural Resources, ‘National Renewable Energy Action Plan. Ireland. Submitted under Article 4 of Directive 2009/28/EC’ (Government of Ireland, 1 July 2010), available at www.dcenr.gov.ie/NR/rdonlyres/03DBA6CF-AD04-4ED3-B443-B9F63 DF7FC07/0/IrelandNREAPv11Oct2010.pdf. 9 As noted in Department of Communications, Energy and Natural Resources, ‘2050 low carbon roadmaps electricity generation sector scoping report’, DCENR (18 November 2014), 6. 10 Renewable Energy Directive.

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Despite the extensive number of measures included in the national renewable energy action plan11 specifically designed to facilitate the attainment of this target, Ireland is currently lagging behind its interim renewable electricity goals. On 13 January 2012, Ireland submitted its first progress report on its national renewable energy action plan. In this report the government indicated that it had reached a 14.8 per cent share of renewable electricity consumption in 2010 (primarily accounted for by 1,364 MW of onshore wind).12 This figure was a long way behind the 20.4 per cent target originally pledged for 2010. In 2013 Ireland still had not met this target (with renewable electricity contributing just 20.1 per cent to Ireland’s electricity needs).13 Although a second progress report was required from the government in January 2014, to date this has not been made public. It is against this backdrop that the White Paper is being finalised. THE LEAD-UP TO THE FORTHCOMING WHITE PAPER On 12 May 2014, the Irish Minister for Communications, Energy and Natural Resources launched a Green Policy Paper, to stimulate an informed debate on the future direction of Irish energy policy, and to act as a precursor to the government’s White Policy Paper, which was expected to be finalised in September 2015 but as yet has not materialised. The Green Policy Paper identified six areas as focal points for the government: (1) empowering energy citizens; (2) markets, regulation and prices; (3) planning and implementing essential energy infrastructure; (4) ensuring a balanced and secure energy mix; (5) putting the energy system on a sustainable pathway; and (6) driving economic opportunity. It provided an overview of Ireland’s energy market (and the progress which had been made in developing this market since the government’s previous energy policy paper of 2007) and included six to ten questions under each of six main headings.14 In discussing the Irish energy market it described both the positive steps which had been taken to develop the Irish electricity market and the challenges which climate change and security of energy supply pose to Ireland 11

Department of Communications, Energy and Natural Resources, ‘National Renewable Energy Action Plan’. 12 Department of Communications, Energy and Natural Resources, ‘National Renewable Energy Action Plan (NREAP) Ireland First Progress Report Submitted under Article 22 of Directive 2009/28/EC’ (Government of Ireland, 2012), available at www.dcenr.gov.ie/NR/rdonlyres/ B611ADDD-6937-4340-BCD6-7C85EAE10E8F/0/IrelandfirstreportonNREAPJan2012.pdf (hereafter ‘First progress report’). 13 Commission for Energy Regulation, ‘Electricity security of supply report 2014 submitted to the European Commission pursuant to Directive 2009/72/EC and Directive 2005/89/EC’ (Commission for Energy Regulation, 2014), available at www.cer.ie/docs/000266/CER14741%20Electricity% 20SoS%20Report%20Final%202014.pdf 14 Department of Communications, Energy and Natural Resources, ‘Green Paper on Energy Policy in Ireland’, DCENR Report (12 May 2014), available at www.dcenr.gov.ie/NR/rdonlyres/DD9FFC79E1A0-41AB-BB6D-27FAEEB4D643/0/DCENRGreenPaperonEnergyPolicyinIreland.pdf

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(which despite the positive steps taken remains an isolated market with limited indigenous resources, limited interconnection15 and a system of infrastructure in need of significant additional construction and investment).16 The successful establishment of an all-island single electricity market in 2007 (linking Ireland’s wholesale electricity with that of Northern Ireland); the increase in retail market competition (following a reduction of the state-owned electricity supplier’s domestic retail market share; in 2013 this was 62.18 per cent);17 the construction of an east-west interconnector (a 500 MW interconnector linking the transmission systems of Ireland and the UK); the increase of renewable energy supplies and significant energy efficiency enhancements were cited as clear achievements.18 In identifying and addressing central areas potentially in need of reform, questions were posed on matters such as how best to engage citizens in the development of infrastructural development; whether barriers existed which were preventing additional electricity consumers switching to new suppliers; how permitting and licensing processes for major infrastructure projects could provide for greater collaboration with community stakeholders; how best to support the continued increase of renewable energy on the electricity grid; and whether existing policy interventions for sustainability (such as public service obligation, priority dispatch, efficiency measures) could be considered to be consistent and aligned. The Green Policy Energy Paper elicited an unprecedented number of submissions, totalling twenty-five volumes of submissions from individuals and 206 submissions from groups. To facilitate further public discussion, regional general seminars and targeted seminars focusing on the six priority areas identified by the paper were held during October, November and December 2014. The government has also appointed a steering group to advise on the finalisation of its follow-up White Energy Paper, to include Professor John Fitzgerald (an economist at the Irish Economic Social Research Institute and a former 15

Ireland’s electricity grid is connected to Northern Ireland via one major interconnector (the Louth to Tandragee interconnector consisting of a 275 kv double circuit overhead line with an approximate capacity of 500 MW). In turn, the Northern Ireland electricity gird is linked to Britain via the Moyle interconnector which runs between Islandmagee, Co. Antrim and Auchencrosh, Ayrshire, Scotland. There are also two 11 kv standby north-south interconnectors (Strabane to Letterkenny and Enniskillen to Corraclassy). Plans do exist, however, to increase cross-border interconnection between Northern Ireland and the Republic of Ireland with a 400 kv interconnector. Irish Wind Energy Association, Energy Ireland Yearbook 2013 (bmf Business Services, 2013), p. 95. 16 A plan has been put in place to develop Ireland’s electricity infrastructure (known as ‘Grid 25’) and is estimated to cost in the region of €4 billion. See EirGrid, ‘Grid 25. A strategy for developing Ireland’s electricity grid for a sustainable and competitive future’ (2009), available at www. eirgrid.com/media/Grid%2025.pdf 17 Commission for Energy Regulation, ‘Electricity security of supply report 2014’. 18 Department of Communications, Energy and Natural Resources, ‘Green Paper on Energy Policy in Ireland’.

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member of the Renewable Energy Strategy Group, which published a Strategy for Intensifying Wind Energy Deployment in 2000),19 Dr Brian Motherway (a sociologist and the CEO of the Sustainable Energy Association of Ireland), Helen Donoghue (a mathematician and Senior Energy Fellow at the Institute of International and European Affairs and a former member of the European Commission) along with officials from the Irish Department of Communications, Energy and Natural Resources.20 ANALYSIS While the Green Policy Paper posed many relevant and valuable questions with a stated purpose of stimulating ‘a broad and informed debate’ on energy policy,21 its usefulness and that of the forthcoming White Energy Policy Paper could ultimately be quite limited. This is simply because most of the core longterm decisions affecting Ireland’s future energy policy (and particularly likely to impact upon renewable energy development) have already been taken. For instance the government has already determined the path that Ireland intends to follow to reach its 16 per cent renewable energy target (in its submissions to the European Commission);22 the structure of ownership to be applied to Ireland’s transmission system;23 and how renewable energy development is to be supported (by including a large number of its costs in the final electricity retail prices charged to electricity consumers).24 Thus, the usefulness of this exercise to facilitate the development of a comprehensive policy designed to get Ireland’s renewable energy strategy back on track will ultimately be decided by two things. First, it will depend on the willingness and skill of the government and its steering committee in sifting through a sea of submissions and presentations to identify relevant, cogent and useful suggestions, which are likely to address the significant problems of the Irish energy sector and facilitate Ireland’s achievement of its renewable electricity targets. Second, it will also be decided by the readiness of the government to remain open to adapting, updating and possibly even reversing previously taken decisions. 19

Renewable Energy Strategy Group, ‘Strategy for intensifying wind energy deployment’ (Government of Ireland, 2000), 17, available at https://www.esri.ie/pubs/OPEA7.pdf 20 Department of Communications, Energy and Natural Resources, ‘Minister White announces Steering Group to advise on Energy Policy Paper’ (24 September 2014), available at www.dcenr. gov.ie/Press+Releases/2014/Minister+White+announces+Steering+Group+to+advise+on+Energy +Policy+Paper.htm 21 Department of Communications, Energy and Natural Resources, ‘Green Paper on Energy Policy in Ireland’, 4. 22 Department of Communications, Energy and Natural Resources, ‘National Renewable Energy Action Plan’ and Department of Communications, Energy and Natural Resources, ‘National Renewable Energy Action Plan (NREAP) Ireland First Progress Report’. 23 European Commission, ‘Commission Decision of 12.4.2013 pursuant to Article 3(1) of Regulation (EC) No 714/2009 and Article 10(6) of Directive 2009/72/EC –Ireland–Eirgrid / ESB’ (2013) C(2013) 2169 final. 24 See the discussion of the public service obligation in Department of Communications, Energy and Natural Resources, ‘National Renewable Energy Action Plan’ and the section on pricing in Department of Communications, Energy and Natural Resources, ‘Green Paper on Energy Policy in Ireland’.

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CONCLUSION Ireland’s brave renewable energy policy is faltering. Interim renewable electricity targets have not been met and the government is facing infringement proceedings for having failed to introduce sufficient measures to reach the renewable energy levels required by the EU. Numerous problems are impeding the expedient development of renewable electricity and the delivery of a comprehensive energy policy designed to guarantee security of energy supply and to address climate change. Against this backdrop, a White Energy Paper is being finalised to address the central issues impeding the success of Ireland’s energy policy. While an unprecedented number of public submissions have been made to inform this paper and the future direction of Irish energy policy, the success of the White Energy Paper in getting Ireland back on track to meet its 40 per cent renewable electricity target will ultimately depend on the government’s ability and readiness to sift through the submissions made and to take bold action to breathe new life into its ambitious but faltering renewable energy strategy.

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RECENT DEVELOPMENTS IN THE HUNGARIAN ELECTRICITY REGULATORY FRAMEWORK Robert Szuchy1

INTRODUCTION The aim of EU law regarding the internal electricity market is to establish an open and transparent market, non-discriminatory access to the networks and a level playing field. After large-scale privatisation and liberalisation of the sector in the 1990s, it seems that the EU has to face new challenges to keep its energy market free, open and competitive. Even though European countries have liberalised their electricity market, the rise of energy prices has re-ignited debate over the role of governments. After forced privatisation in Central and Eastern European countries, now governments intend to have more control over the energy market. For example, Hungary has embarked on a plan to nationalise significant parts of its energy sector, especially the distribution of electricity and natural gas and gas storage systems. The European Commission appears to be watching these developments with concern, though it is not ready yet to take any serious action. However, besides re-nationalisation, governments have numerous tools to regulate energy and especially the electricity market, as is currently the case in Hungary. THE EU FRAMEWORK According to the Third Energy Package of the EU and the relevant Directive2 on the electricity market, market prices should provide the right incentives for 1

2

Robert Szuchy is an Associate Professor in the Department of Commercial and Financial Law at the Faculty of Law of Károli Gáspár University (Budapest, Hungary). He holds a PhD degree in Competition Law and is the author of several articles in the fields of competition, business and energy law. Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in electricity and repealing Directive 2003/54.

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the development of the network and for investing in new electricity generation.3 To that end, undistorted market prices would provide an incentive for crossborder interconnections and for investments in new power generation while leading, in the long term, to price convergence.4 National regulatory authorities should be able to fix or approve tariffs, or the methodologies underlying the calculation of the tariffs, on the basis of a proposal by the transmission system operator or distribution system operator(s), or on the basis of a proposal agreed between those operators and the users of the network. THE REGULATORY FRAMEWORK IN HUNGARY Electricity market legislation in Hungary is based on EU directives and regulations. The second Electricity Market Directive5 was transposed into the Electricity Act6 – which came into force in January 2008 – and subsidiary legislation.7 As part of the liberalisation and the opening of the Hungarian electricity market the Second Electricity Directive was implemented by Act LXXXVI of 2007 on electricity: a villamos energiáról szóló törvény (hereafter referred to as ‘the Electricity Act’). The Electricity Act ended the public-sector utility segment of the market with its state-set electricity prices and, as of its introduction on 1 January 2008, electricity prices have been liberalised, except prices for universal services. THE HUNGARIAN ENERGY AND PUBLIC UTILITY REGULATORY AUTHORITY The role of the Hungarian Energy and Public Utility Regulatory Authority (previously referred to as ‘Hungarian Energy Office’ and hereafter referred to as ‘HEA’) has been continuously changing along with the development of market structures and operating models as well as European legislation. The scope of the activities which have to be overseen by the HEA was extended in Hungary with the complete regulation of district heating in 2011 and with public water utilities in 2012. As market developments are becoming more widespread, it put emphasis on the market monitoring task and pays specific attention to regional market integration concerning both electricity and natural gas. However, the most important legislative change was to provide the legislative power for the HEA to adopt legally binding regulations for the whole energy sector, instead of administrative decisions, as before. The crucial change is that previously the HEA’s decision could be challenged in the ordinary court system, but now its regulations can only be challenged before the Constitutional 3 4 5

6 7

Preamb. 56 of Directive 2009/72/EC. Preamb. 60 of Directive 2009/72/EC. Directive 2003/54/EC of the European Parliament and of the Council of 26 June 2003 concerning common rules for the internal market in electricity and repealing Directive 96/92/EC. Act LXXXVI of 2007 on electricity (a villamos energiáról szóló törvény) (the ‘Electricity Act’). Governmental Decree No. 273/2007 (X.19) on the implementation of the Electricity Act (the ‘Implementation Decree’) regulating entities and activities in the electricity sector.

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Court on the basis of non-compliance with Hungarian constitutional rules. This new system has significantly limited the possibility of appeal by electricity companies, especially in cases of price regulation. The compliance of the new rule with EU law is questionable. THE HUNGARIAN MODEL OF PRICE REGULATION – THE UTILITY CUT BILL As a result of market liberalisation, the price of electricity is no longer regulated, save for the price supplied in the framework of universal service (public service obligations). However, the scope of public service obligations regulated in the Directive8 in Hungary has been widely extended, and includes certain public bodies and churches as well. Although the price regulatory framework in Hungary was previously in line with EU standards, since 2010 political interventions have increased, the first of which was a temporary price freeze in 2010. The political reasoning for the price cut was the high utility prices for households in Hungary. However, the utility bills of Hungarian households as a ratio to annual household expenditure is not high within the region, although it is high in a European context.9 Presented as the biggest achievement of the former and the government formed by the coalition of the right-wing FIDESZ and KDNP, re-elected by a two-thirds majority for the second time (which had never before happened in the history of the Hungarian democracy), the utility price cut was one of the most important issues during the elections and afterwards. The cut in electricity prices of universal service customers (mainly domestic customers) was implemented in three waves and in different ways. As a result of the regulatory changes at the end of 2012, the 2013 price for consumers supplied by universal service providers (USPs) was reduced by 10 per cent compared to the previous year.10 The Hungarian government chose a very tricky but not entirely marketfriendly method for the first round of the ‘electricity bill cut’. The amendment of the Electricity Act exempted USPs from the obligation to receive energy under the feed-in regime, therefore in 2013 the renewable energy generated under the feed-in regime was purchased by the competitive segment only.11 Moreover, in both the first and the second round of price cuts, the price of electricity was also cut by squeezing the USPs’ margins. System usage charges were cut for universal service customers and they therefore increased for those 8

Art. 3 of Directive 2009/72/EC. See http://ec.europa.eu/eurostat/statistics-explained/index.php/Energy_price_statistics#Electricity _prices_for_househld_consumers 10 Hungarian Energy Market Report, 1/2013, Regional Center for Energy Policy Research, available at www.rekk.eu/images/stories/rekk_report_2013_1.pdf 11 Section 13 of the Electricity Act was amended by Section 91(2) of Act 217 of 2012, while Decree 78/2012 of the Ministry of National Development amends the ministerial decrees on energy price regulation. 9

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in the free market. Finally, other financial tools only shifted to consumers in the free market.12 The decrease in the system charges paid by low-voltage connection consumers is compensated for by the substantial rise in the fee paid by medium- and high-voltage customers. Seventy-eight per cent of the distribution charges were also transferred to larger industrial consumers from the smaller consumers. The consequence of the above-mentioned changes is a 20 per cent cut in electricity prices predominantly for household customers. The full-year benefit to universal service customers in 2013 from the 20 per cent total cut was therefore nearly 100 billion Hungarian forints (around $45 million), approximately 0.3 per cent of the Hungarian GDP.13 The third wave of the cut was introduced during the spring session of the Hungarian Parliament in 2014. From September 2014 electricity prices were cut by another 5.7 per cent, through the regulatory intervention of the HEA. The intervention in regulated prices has worsened price distortions, and the implementation of the price cuts contains significant cross-subsidisations from industrial to household users. Moreover, at the beginning of 2015 the Hungarian government planned further waves of cuts in the household sector, as the ‘fourth utility bill cut’, but it has intended to move forward and to extend the price-cut policy into the non-household sector as well – although this has yet to materialise. At first, this appears a difficult task, due to the fact that in Hungary, as a result of EU rules and requirements, electricity prices and the electricity market – besides universal services – are fully open and liberalised and all electricity consumers, including households, are free to choose their supplier. In 2015, the Hungarian government, however, set up a new state-owned utility company (not just for electricity generation) named ‘First National Utility Provider Ltd’,14 which should provide cheap power for SMEs and possibly other companies too. This plan raises several questions and concerns, especially regarding whether the company would be able to comply with the EU state aid rules or even with the requirements laid down in Directive 2009/72/EC. OTHER SECTORS It is not only the electricity sector that has been affected by the price cuts. The same percentage of reduction of the natural gas price has been achieved for mostly household consumers by eliminating the security storage fee for them and by decreasing both the base and the product fee, as laid down in the regulations of the HEA. Furthermore, the price of district heating was also decreased by 20 per cent by purely regulatory based price re-allocation.

12

OECD, OECD Economic Survey: Hungary 2014 (OECD Publishing, 2014). Storm in overhead cost: analysis of the overhead reduction of January 2013 by REKK, Working Paper No. 1, Regional Centre for Energy Policy Research (REKK), Corvinus University of Budapest. 14 In Hungarian: ENKSZ Első Nemzeti Közműszolgáltató Zrt. 13

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CONCLUSIONS Non-market-based regulated prices will not reflect real supply cost and will encourage household consumers to stay under universal service. Moreover, distorted prices reduce incentives for using electricity efficiently. With the establishment of the national utility service provider there is a high risk that if a high number of consumers switches to the company – due to low prices – the space for the free electricity market will be narrowed and several competitors may exit from the market in the future. This might diminish and distort competition in the market, and may cause higher prices outside the universal service frame. Meanwhile, concerns and questions related to compatibility with EU state aid rules might also be raised in the future.

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DELIVERING THE REVIVAL OF NUCLEAR POWER Keith Baker1

In response to the twin pressures of energy insecurity and climate change, policymakers around the world are placing increased emphasis on the importance of nuclear power. The World Nuclear Association (WNA) indicates that sixty-five new reactors are currently under construction with plans for a further 165.2 This marks a dramatic revival in the fortunes of a technology that had come to be regarded as uneconomic and potentially dangerous. Once the preserve of states, nuclear power programmes are now delivered though complex interdependent networks of commercial concerns over which governments do not exert direct control. To realise renewed investment in nuclear power, governments must now work through decentred networks and practise governance. New nuclear power plants (NPPs) are being constructed in France, Finland and in parts of the US but no new plants are currently under construction in the UK. This chapter argues that this variation can be explained in terms of the extent to which the institutional environment and regulatory regime allows construction and revenue risks to be mitigated or controlled. RISK AND GOVERNANCE Risk is generally understood as an expression of uncertainty about the likelihood and severity of the foreseeable consequences of decisions.3 The concept of risk allows for the future to be envisaged and for individuals to take action 1

2

3

Dr Keith Baker, School of Public Policy, Oregon State University, USA. Keith Baker is an Assistant Professor in the School of Public Policy, Oregon State University. His interests include the governance of nuclear power, energy policy and public administration. World Nuclear Association, ‘World nuclear power reactors & uranium requirements, October 2014’ (2015), available at: www.world-nuclear.org/info/Facts-and-Figures/World-Nuclear-PowerReactors-and-Uranium-Requirements T. Aven and O. Renn, Risk Management and Governance (Springer, 2010).

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to realise or prevent a particular future. The construction and operation of an NPP is an extremely risky venture. This is because NPPs are often subject to massive cost construction overruns (construction risk) and are very vulnerable to fluctuations in the price of electricity. The WNA observes that repaying construction costs and servicing debt account for about 70 per cent of the price of electricity produced from nuclear power.4 In contrast, about 80 per cent of the price of electricity generated from natural gas or coal can be accounted for by the cost of the fuel itself. As such, nuclear power is often rendered unprofitable by changes in the price of gas and coal (revenue risk). However, the economics of nuclear power are such that once a plant has fully amortised, it will return considerable profit. The problem is that many NPPs will simply not generate enough profitable electricity in their operational lives. If commercial energy utilities are to invest in nuclear power, they must be confident that construction and revenue risks can be mitigated. In a situation of governance, policy goals are realised through decentred actors but government retains considerable authority due to its control of the legal system. Government can shape the obligations upon energy utilities, the scale of the costs they will incur, where costs will be incurred and how costs can be recovered. Governments practise governance by changing regulatory rules and can organise the institutional environment to alter how utilities perceive the risks associated with particular decisions. A REVIVAL OF NUCLEAR POWER IN FOUR COUNTRIES The energy industry in the US can be broadly divided between regulated and liberalised markets since the deregulation of the market in 1992. In liberalised or deregulated markets, there is competition between utilities and electricity is traded as a commodity in wholesale markets, whilst in regulated markets, utilities have a monopoly of generation and supply. However, regulated utilities do trade power directly with one another to ensure that they comply with federal legislation that mandates open markets.5 In many regulated states, cost pass-through is allowed and a surcharge can be imposed on consumers to fund future capacity investments. The US federal government has sought to govern by addressing construction and revenue risk through a system of limited loan guarantees and offering production tax incentives for newly installed capacity.6 The loan guarantees will cover up to 80 per cent of the costs but to qualify each new NPP must make use of significantly improved technology and applicants must have made large investments themselves.7 As stepwise or radical improvement in nuclear power is difficult and expensive, this has limited the scope of the guarantees.

4

5 6 7

World Nuclear Association, ‘Economics of nuclear power’ (2013), available at www.worldnuclear.org/info/Economic-Aspects/Economics-of-Nuclear-Power FERC Order 888, Federal Energy Regulatory Commission, 1996. Energy Policy Act 2005, Pub L. 109–58. Federal Register (2007). 72 FR 60116.

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There is some nuclear new-build in the US and new reactors are under construction at Vogtle in Georgia and VC Summer in South Carolina. The unfinished reactor at Watts Bar II in Tennessee is also being completed. It is likely that Watts Bar II is being completed to take advantage of tax incentives. Vogtle and VC Summer may be taking advantage of loan guarantees by being the first to adopt modern reactor technology and are being constructed in regulated states where cost pass-through is allowed. Cost pass-through at the state level is likely to be more significant than federal guarantees overall as these are not subject to restrictions or limits on the capital available. This is supported by the fact there is no new-build in liberalised states where the price of electricity is closely linked to the cost of coal and gas. In Finland, the French company Areva is building a new NPP at Olkiluoto 3 under a turnkey contract for Teollisuuden Voima Oyj (TVO). Areva is a publicly owned nuclear manufacturing company whilst TVO is a consortium of energy utilities and industrial concerns with business interests in energyintensive industries. TVO has benefited from the fact that Areva was the beneficiary of export guarantees from the French government as successive French governments have sought to support their nuclear manufacturing industries. Export guarantees and the prospect of demonstrating new technology encouraged Areva to enter into a turnkey contract. This contractual scheme insulated TVO from construction risk. Furthermore, Finnish law allows the owners of a power plant to buy electricity at wholesale cost for their own industries but to sell any surplus at market rates. The construction of Olkiluoto 3 was incentivised by Finnish law but it might be argued that TVO would not have commissioned Olkiluoto 3 if the French government had not agreed to support Areva’s acceptance of a turnkey contract. Nearly 75 per cent of French electricity is supplied by fifty-eight nuclear reactors operated by the state-owned Électricité de France (EDF). A new nuclear plant is currently under construction at Flamanville 3 but the plant is behind schedule and over budget. This is consistent with the history of the French nuclear power programme.8 French governments have long regarded the capacity to build and operate nuclear power plants as necessary for the security of the French electricity supply. Although the French government does not direct the day-to-day operations of EDF, there are extensive links between the company and government through which the government seeks to influence decision-making. As EDF is state-owned, underwritten by the French taxpayer and subject to an extraordinary degree of political interference, it does not really make investment decisions on the basis of construction and revenue risks. Instead, the French government and EDF appear to assess nuclear power in terms of the consequences that it assures against. Britain’s electricity industry was privatised in 1990 and the British government defers to the commercial decisions of the energy industry. The British 8

A. Grubler, ‘The costs of the French nuclear scale-up: a case of negative learning by doing’, Energy Policy 38(9) (2010), 5174–88.

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government believes that high gas prices will predispose utilities to invest in new NPPs. As such, government must encourage industry by ensuring that the regulatory system and institutional environment does not increase construction risk (and cost) by causing delays. To this end, the British government has variously streamlined regulation and centralised the planning laws. These steps have proven insufficient and securing low-carbon energy supplies has become increasingly urgent as coal-fired power plants are decommissioned and existing nuclear capacity ages. This has forced the British government to underwrite construction costs through loan guarantees and impose complicated price-setting mechanisms and capacity payments to guarantee the revenue streams of nuclear operators.9 CONCLUSION The institutional and regulatory environment in which an energy utility operates was observed to play a considerable role in shaping how construction and revenue risks are controlled. It was found that governments sought to influence the decisions of utilities by changing the regulatory regime and restructuring the institutional environment. However, the case studies indicated that to govern successfully governments must have a direct stake in the outcome of the programme. The US federal government is largely a bystander in electricity provision whereas state governments have an immediate interest. Likewise, the Finnish government was not invested in the construction of Olkiluoto 3. In contrast, the French government had a direct stake in both Flamanville 3 and Olkiluoto 3 due to state ownership of Areva and EDF. The British government has generally eschewed involvement in energy policy since privatisation. However, when commercial companies have failed to deliver, it has intervened directly to control construction and revenues. It may be that overseeing nuclear power requires government to impose itself as a government rather than seeking to work through networks.

9

2013 Energy Act, Ch. 32, Electricity Market Reform (General) Regulations 2014, S.I. 2014/2013.

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ENERGY POLICY: THE ROLE OF NUCLEAR POWER S. D. Thomas1

One of the puzzling features of energy policy debates over the past fifty years has been the credulity of policy-makers to promises made for nuclear power. Successive generations of policy-makers have been convinced that this time, things will go well. New technologies will deal with the problems that exist; solutions to the waste disposal issue will emerge; the problem of public acceptance can be dealt with by education; and nuclear power is the only way to deal with the latest energy policy challenge. These challenges range from overreliance on unstable countries for hydrocarbon fuel to the need to phase out fossil fuels to combat climate change. This continued credulity is well illustrated by the UK. Following the perceived success of the first-generation nuclear power plants, UK governments have launched policies to stimulate programmes of nuclear ordering on five occasions,2 from 1965 up to the attempt launched in 2006. The result of the

1

2

Steve Thomas was a member of the energy policy group at the Science Policy Research Unit at Sussex University from 1979 to 2000. Since then, he has led energy research in the Public Services International Research Unit at Greenwich University. His main research areas are economics and policy for nuclear power; liberalisation and privatisation of energy industries; and corporate policies of energy companies. In 1965, the UK government launched a reactor programme of five new stations based on the Advanced Gas-Cooled Reactor (AGR). In 1971, the AGR was replaced as the national reactor choice by the Steam Generating Heavy Water Reactor. But none were ordered before 1977 when it was replaced by a dual-reactor strategy based on AGRs and Pressurised Water Reactors (PWRs). In 1979 Margaret Thatcher announced a programme of ten reactor orders, one per year, using PWR technology but only one was built. In 2006, Tony Blair announced a programme of around ten new reactors, but by 2015, agreement on the terms for only two reactors had been reached and no firm order had been placed.

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first four attempts was eight nuclear power plants, which have an appalling economic record. In January 2015, it was unclear whether any new reactors would result from the latest attempt. This experience begs three questions: • How and why has nuclear power failed? • What are the attractions of nuclear power to politicians? • How are advocates of nuclear power able to exert influence over politicians? We focus particularly on economics. Other aspects of nuclear power policy, such as safety, waste disposal and proliferation, are important, but it is arguably poor economic performance that has been the main factor behind the decline in ordering since 1980. THE FAILURE OF NUCLEAR POWER TECHNOLOGY The expectation with successful technologies is that real costs will fall over time. This will result from ‘learning by doing’; technical change; economies of scale (building units with larger output); and economies of number (building in larger numbers). These effects have consistently been expected to reduce nuclear costs, but real costs have only ever risen. Even in France, where around fifty reactors were ordered in a period of a decade, ideal conditions for learning, economies of number and technical change, real costs consistently increased.3 There is no analytical evidence that explains this increase, but the common perception is that it is driven by the need to add safety systems to remedy the design weaknesses revealed by major accidents. A concerted attempt worldwide to relaunch nuclear ordering started around 2000 and was based on the promise of ‘Generation III+’ designs.4 It was the claims made for these designs that persuaded the USA and the UK to launch major policy initiatives to restart nuclear ordering. The Bush Nuclear 2010 programme was announced in 2002 and included a ‘roadmap’ to allow the first reactors from this initiative to be in service by 2010. The roadmap stated: ‘New Generation III+ designs . . . have the advantage of combining technology familiar to operators of current plants with vastly improved safety features and significant simplification is expected to result in lower and more predictable construction and operating costs’.5 It was claimed the design could be built for about $1,000/kW, so that a typical reactor with an 3

4

5

A. Grubler, ‘The costs of the French nuclear scale-up: a case of negative learning by doing Energy Policy, 38(9) (2010), 5174–88. There is no clear definition of what constitutes a Generation III+ reactor design but generally there is an expectation that they would rely more on ‘passive safety’ as opposed to relying on engineering systems to keep the reactors under control in accident situations. See, for example, US Department of Energy, ‘DOE seeks public-private partnerships to demonstrate ‘one-step licensing’ of new U.S. nuclear power plants’, Press Release (21 November 2003), available at http://www.electricityforum.com/news/nov03/privatenuclear.html

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output of 1,500 MW would cost $1.5 billion.6 Construction started on the first four reactors in 2013 and there is little expectation that there will be any orders beyond these four. By 2015, no Generation III+ plant was in service and the claims made were in tatters. Twelve Generation III+ reactors7 were under construction8 and all were over time and budget. The worst is the Olkiluoto plant in Finland, which was expected to be built in four years. In 2015, after ten years of construction, it was reported to be three years from completion and nearly three times over budget at about $7,000/kW. In 2013, the UK agreed to build two reactors of the same design as Olkiluoto at a cost (in 2012 figures) of about $8,000/kW.9 Whilst there has been some inflation since 2000, the latest figures appear to represent a fivefold real increase in the figures forecast only fifteen years ago. It is likely to be at least twenty years before the lessons of Fukushima are fully embodied in new reactor designs. It is implausible that these lessons will do anything but increase real costs. Despite this, the UK government seems untroubled and determined to force through a deal at whatever cost. Finnish utilities are equally unperturbed and in 2015 were negotiating to buy a reactor from Russia, while the US government is still offering incentives for new orders. WHAT IS THE APPEAL OF NUCLEAR POWER TO POLITICIANS? Politicians often have misconceptions about nuclear power, particularly its cost and how large a role nuclear power could play in the energy economy. Even in France where nuclear power accounts for about 80 per cent of electricity generation, it only provides less than 20 per cent of total energy supplies. These misconceptions lead policy-makers to believe that nuclear power could be a cheap way to meet a large proportion of our energy needs and replace fossil fuels. Nuclear power appears attractive because it is seen as an ‘indigenous’ energy source reducing dependence on imported fuel and contributing to security of supply. Whether nuclear power should be seen as indigenous is a moot point. However, the continued failure of nuclear projects to be built to time and cost and their often poor reliability suggests they do not improve security of supply. Nuclear projects are also large and prestigious, bringing high-skill jobs and prosperity, and thus have political value. Again, this is illusory as long-term high-skill jobs are limited, with most employment temporary for the duration of the construction phase and often disruptive to local economies. 6

7

8

9

As late as 2003 Westinghouse was estimating the cost of its AP1000 design in the range $1,000– $1,200/kW. See www2.lakelandcc.edu/nora/events/iuser/faculty/images/members/AP1000,%202.pdf There are seven reactors of a new Russian design under construction in Russia and Belarus which the vendor claims meet the same standards as the Generation III+ designs, but this design has only been reviewed in Russia so the claims have not been independently verified. Eight reactors of the Westinghouse AP1000 design, four each in China and the US, and four of the Areva EPR design two of which are in China and one each in France and Finland Department of Energy and Climate Change, ‘Initial agreement reached on new nuclear power station at Hinkley’, Press Release (21 October 2013), available at www.gov.uk/government/news/ initial-agreement-reached-on-new-nuclear-power-station-at-hinkley

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NUCLEAR LOBBY There is a common perception that there is a powerful, well-organised and well-funded lobby influencing politicians to make decisions in favour of nuclear power. It is hard to imagine how the latest UK nuclear programme would have been possible without such a lobby. Twenty to thirty years ago many countries would have a structure that could credibly constitute such a lobby. The elements would include large influential electric utilities with scope to pass on costs to consumers which saw nuclear as a challenging, interesting and prestigious project; a national nuclear R&D organisation with high prestige and influence amongst civil servants and politicians; a ‘national champion’ engineering company that would supply major components; and a military lobby that saw a civil nuclear programme as a way to maintain skills needed for military nuclear technology. In France, such a structure still exists, and twenty-five years ago it existed in the UK, but well before the latest UK programme was announced in 2006 all the elements had disappeared except for the military connection. WHAT IS THE FUTURE FOR NUCLEAR POWER? The fact that nuclear power is still talked about as a major energy option is remarkable. Many felt that another major accident after Three Mile Island would be enough to destroy the industry, yet despite two more serious accidents, the industry remains. The perception that nuclear power is ‘cheap’ persists despite all the evidence to the contrary. So it would be unrealistic to assume that the demise of the current attempt to relaunch nuclear power will destroy its hold on policy-makers. However, there are fundamental problems that mean it will be difficult to mount a new nuclear revival. The workforce is aging and with few nuclear engineers being produced, dealing with existing facilities will be a major challenge. The experience with Generation III+ reactors must have shown that there is no future in further development of existing technologies. However, radical new designs, such as fast reactors and thorium cycle reactors are little closer to deployment than they were forty years ago. The failure to demonstrate that safe solutions are possible for radioactive waste is increasingly damaging and technologies talked about as promising forty years ago, such as transmutation, seem no closer to deployment.

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FINANCING NEW NUCLEAR POWER STATIONS Simon Taylor1

INTRODUCTION Nuclear power stations lie at one end of the spectrum of infrastructure investments, being exceptionally long lived and highly capital intensive. They also carry unusually high construction risks. Private investors are therefore very reluctant to finance new nuclear stations without guarantees or other risk mitigation. The only credible supplies of the guarantees are states. New nuclear stations have been financed in the US in recent years and a major UK project is at an advanced stage but has not yet reached final investment decision at the time of writing. The financing arrangements of these projects are formally different but on closer inspection provide quite similar risk mitigation, suggesting there are common challenges in attracting private capital. NUCLEAR GENERATION: CHARACTERISTICS AND POSSIBLE MARKET FAILURE Nuclear power stations are typically large (usually 1,000 MW or more) and capital intensive (about 70 per cent of total costs arise at the investment stage), with the assets lasting for sixty years with decommissioning even later. 1

After studying economics at Cambridge, Oxford and LSE, Dr Simon Taylor spent nine years as an equity analyst at a number of investment banks, including BZW, JPMorgan and Citigroup, where he was involved in several major equity transactions and takeovers and led research teams covering the European and global utilities sectors. In 2001 he became Deputy Head of European Equity Research at JPMorgan where he had management responsibility for the technical and quantitative research teams and for the technology, media and telecoms sectors. He joined Cambridge University’s Judge Business School in 2007 as Lecturer in Finance and is the Director of the Cambridge Master of Finance degree. He is a Research Associate of the Energy Policy Research Group. In 2009 he was awarded a Cambridge University Pilkington Teaching Prize. His book on the history of nuclear power in the UK will be published in 2016.

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Other low-carbon generation such as wind and solar is even more capital intensive but can be built on a smaller scale. The asset lifetime is not as long as nuclear nor is the construction risk so serious. Nuclear is therefore something of an extreme case but no single aspect of it is unique. Private investment in infrastructure is constrained by the inherent risk of investing a lot of capital upfront and having to wait many years to get it back. The timing exposes investors to the risk that future revenues fall short of what is needed, either because of commercial risk (power prices are lower than forecast) or the risk of regulatory or political interventions. Investors ideally want a price guarantee and some form of contractual assurance that there will be no change in the market, political or regulatory rules that would damage their future investment. The difficulty of governments credibly making such a guarantee, especially over many decades, is a potential barrier to all infrastructure projects and nuclear in particular. All of this is made worse by the particularly high risk in nuclear construction. The historic construction record of nuclear power in many countries is very poor. In the US in particular, the industry acquired a reputation for repeated delays that led to actual construction costs hugely exceeding the original budget. Again this is a problem in infrastructure more generally, especially with politically motivated ‘megaprojects’ where the promoters have an incentive to downplay costs until the project is committed. But nuclear is in a class of its own. The problems of the 1970s were in large part a result of repeated legal challenges from opponents, compounded by the high inflation rates of that period. Moreover there is little evidence of the learning-by-doing that is a normal feature of investment in other industries, even in the relatively systematic and trouble free French nuclear programme. None of these problems is strictly a market failure in the normal sense of the term (externalities and public goods that lead to under-provision of certain goods and services without corrective taxation, regulation or other state intervention). Private investors are acting quite rationally if they judge nuclear investment to be unacceptably high risk without additional incentives. EXAMPLES OF NEW NUCLEAR FINANCED BY THE PRIVATE SECTOR Finland It is not surprising that new nuclear construction is mostly found in cases where there is state support or outright ownership. One exception is the European Pressurised Water Reactor (EPR) at Olkiluoto 3 in Finland where the project is backed by a privately owned utility which in turn has long-term power purchase contracts from a consortium of industrial customers. That project depended on laying off the construction risk on the project manager, the French company Areva. The construction having gone badly over time and budget, Areva is the subject of very high compensation claims which would threaten to bankrupt the company if it were not majority owned by the French government.2 So even in this case there is a state backstop to the risk. 2

M. Stothard, ‘Areva’s new boss promises shift in strategy’, The Financial Times (15 March 2015).

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United States New nuclear construction in the United States is limited to states with regulatory rate bases, in which the costs, including some degree of construction risk, are borne by the customer, subject to regulatory approval. Southern Company’s Georgia Power subsidiary started construction in 2013 of the Vogtle 3 Westinghouse AP1000 reactor near Waynesboro, Georgia, a state which continues to regulate electricity generation so that power costs, including construction and financing are passed through to ratepayers. On top of that the project received $3.46 billion of federal loan guarantees.3 These guarantees assure bank lenders that they will be repaid whatever happens to the plant. Construction risk remains with Georgia Power but it can pass on cost increases to rate payers so long as it can persuade the regulator that they are justifiable as opposed to being the result of incompetence. SCANA Corp subsidiary South Carolina Electricity and Gas started building Summer 2 and 3, two AP1000s at Jenkinsville, South Carolina, another regulated state, in 2013. Both these projects are insulated against power price risk and to some extent construction risk because they are in regulated states. SCANA in March 2015 petitioned the Public Service Commission of South Carolina for additional capital costs to be allowed in the rate base (that is, paid by customers).4 By contrast the South Texas new nuclear station proposed by the company NRG was cancelled after falling market power prices and the Fukushima nuclear disaster. This would have been a merchant plant, exposed to the wholesale power market. France France has the highest absolute and relative amount of nuclear generation in the world (though China is catching up in terms of absolute capacity). A new EPR is under construction at Flamanville in Normandy. It is reported to be years behind schedule and billions of euros over budget.5 The risk is borne by the sponsor EDF, which has a de facto captive market for its power and can spread the costs over a very large business. Being 85 per cent owned by the French government, it also has some assurance that it will be allowed to make an acceptable return. UK The UK has a deregulated power market and all conventional new generation investment in the last twenty years has been built with full exposure to power price risk and construction risk. The commercial risk has been arguably mitigated 3

4

5

G. Power, ‘Construction financials’ (2015), available at www.georgiapower.com/about-energy/ energy-sources/nuclear/construction-financials.cshtml SCANA (2015) ‘South Carolina Electric & Gas Company requests update to construction and capital cost schedules for new nuclear units’, Press Release (12 March 2015), available at www. scana.com/docs/librariesprovider15/pdfs/press-releases/03-12-2015-south-carolina-electric-ampgas-company-requests-update-to-construction-and-capital-cost-schedules-for-new-nuclear-units .pdf?sfvrsn=0 Bloomberg, ‘EDF has welding problems at Flamanville reactor, watchdog says (30 August 2010), available at www.bloomberg.com/news/articles/2010-08-30/edf-has-welding-problems-at-flamanville -epr-reactor-french-watchdog-says

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by the majority being built by vertically integrated power companies though early indications from the Competition and Markets Authority investigation into the UK energy sector do not seem to find much benefit from vertical integration.6 British energy policy is now heavily driven by the Climate Change Act of 2008 which requires the government to cut UK carbon emissions by 80 per cent by 2050, through a series of five-year carbon budgets.7 Low carbon investment which would not be economic without support including nuclear power now gets a mixture of financial incentives. The proposed Hinkley Point C 3,200 MW twin EPR project in Somerset is awaiting the final investment decision of its investors (chiefly EDF). The project has three main supports from the government: 1. a thirty-five-year fixed-price (in real terms) power price contract 2. a sovereign guarantee for debt raised by the project 3. a legal contract to indemnify investors against early closure of the station on any other grounds than safety.8 The construction risk will remain with the investors, who are also required to put up £8 billion of contingent equity on top of the £16 billion of funding for the station. This is to protect the government from having to actually pay out on the debt guarantee.9 Hinkley Point C would be the fifth EPR to be built (the others are Olkiluoto in Finland, Flamanville in France and two in China – see Table 43.1). None of the others has yet been completed and all are behind schedule, two of them (Finland and France) very badly. So the Table 43.1 Comparisons of risk bearing among current and likely new nuclear projects Reactor

Country

Status

Construction risk Power price risk Debt guarantee?

Olkilotuo 3

Finland

Under construction

Contractor (Areva)

Customers

None

Flamanville 3

France

Under construction

Sponsor (EDF)

Customers (via regulation)

No

Vogtle

USA

Under construction

Customers

Customers (via regulation)

US federal government

Awaiting final decision

Sponsor (EDF and others)

Customers (mediated by government)

UK government

Hinkley Point C UK

6

7 8

9

CMA, ‘Energy market investigation. Updated issues statement’ (18 February 2015), available at https://assets.digital.cabinet-office.gov.uk/media/54e378a3ed915d0cf7000001/Updated_Issues_ Statement.pdf S. Taylor, The Fall and Rise of Nuclear Power in Britain – A History (UIT, 2016). EDF Energy, ‘Update on the UK nuclear new build project (‘NNB’) (13 October 2013), available at http://shareholders-and-investors.edf.com/fichiers/fckeditor/Commun/Finance/Publications/Annee /2013/EDF_NNB_EquityPresentation_2_va.pdf S. Taylor, ‘A financial analysis of the Hinkley Point C project’, EPRG Working Paper (2015), available at www.jbs.cam.ac.uk/faculty-research/faculty-a-z/simon-taylor

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construction risk is real, though the project sponsor EDF is confident that lessons from the earlier projects, plus advanced computer modelling, will ensure this one is built on time and budget. The contract is underwritten by the government but the power will be purchased by a separate central buyer on behalf of customers. The power price contract (technically a contract for difference but with the substance of a fixed price contract) takes away commercial risk from the project. It is similar in substance to the long-term power contracts underpinning the Olkiluoto EPR in Finland. The UK lacks credible long-term power purchasers, having much less energy-intensive industry than Finland so a purely private-sector route was not possible. The debt guarantee is not specific to nuclear but is available to a range of infrastructure projects (not just energy). The scheme, backed by the UK Treasury, was justified by the temporary disruption to credit markets after the global financial crisis of 2007–9. But in the case of nuclear it is doubtful than even in ‘normal’ times that a nuclear project could raise bank debt at the construction phase without some form of guarantee. The contractual indemnity against politically motivated early closure of the station attempts to reduce the regulatory or political risk that to some extent afflicts any long-term project. In a country with strong rule of law such as the UK it has a reasonable chance of success under normal contract law but it remains to be seen whether it can be enforced successfully. WHAT THIS TELLS US ABOUT FUTURE NUCLEAR FINANCING Several other nuclear projects are under development in the UK but there is a widespread expectation that they would also get the support offered to Hinkley Point C, though probably with a lower power price. Given that Hinkley is several years behind schedule and has still unresolved negotiations among the prospective investors (which include two Chinese nuclear companies), the conclusion is that even with a highly supportive government, cross-party political support and one of the most sophisticated legal and financial systems in the world, financing a new nuclear power station remains difficult.

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UK NUCLEAR NEW-BUILD PLANS IN THE LIGHT OF INTERNATIONAL EXPERIENCE Tony Roulstone1

INTRODUCTION: CONTEXT In 2015, the UK is on the edge of starting to construct its first new nuclear power station (at Hinkley Point in Somerset), more than twenty years after the start-up of the last nuclear station, Sizewell B, in 1995. Hinkley Point is expected to be the first of about a dozen reactors to be built over the next fifteen years, replacing the UK’s aging advanced gas-cooled reactors (AGR) and increasing the UK nuclear generating capacity by 50 per cent to 17 GW by about 2030. The reasons for ending nuclear construction in 1995 were a mixture of economics and politics. Similarly, the reasons for restarting nuclear build are also economic and political. This chapter discusses the factors that affected the programme design and the technology choice and compares these to some other nuclear programmes around the world as well as providing a view of the risks and costs for the UK nuclear new-build programme. 1

Tony Roulstone established and teaches on the Nuclear Energy Masters programme at the University of Cambridge, with research interests in the economics and safety of nuclear power, including a specific interest in small modular reactors. He is also a Visiting Professor of Nuclear Engineering at City University in Hong Kong. He received his degree from the University of Cambridge and has spent much of his career in the nuclear and aerospace industries, starting with UKAEA, working on fast reactor systems, and including twenty years at Rolls-Royce where he became Managing Director of the Nuclear Group in 1992. He was also the Rolls-Royce Nuclear Director of Engineering and Projects when the Vanguard nuclear submarines were being delivered and he has held senior roles both in aerospace engineering and corporate transformation in Rolls-Royce plc. He consults widely in the engineering, technology and services sectors and has completed several policy studies on enterprise and on large-scale procurement. He is a Fellow of the Institution of Mechanical Engineers and a Member of the Nuclear Institute, of the Institution of Engineering and Technology and of the Board of the UK Advanced Manufacturing Institute.

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MAIN NUCLEAR NEW-BUILD PROGRAMMES The decision in 2006 to restart the UK nuclear programme was surprising because the government had previously, in the 2003 Energy Review,2 set its face against any further nuclear power, preferring renewable energy and the yet to be developed carbon capture and storage (CCS) for low-carbon electricity. Support for nuclear in the UK was undermined in 1970s and 1980s by the problems with multiple designs, high cost and the long delays of the AGR programme. In addition, the long and contentious public enquiry for Sizewell B showed that public opinion was not fully behind nuclear power. Finally, the adoption of natural gas for electricity generation and the liberalisation of the energy market at the end of the 1980s made capital-intensive electricity such as nuclear power seem uneconomic. As a result in the 1990s, 10 GWe of natural gas generation was built instead of the planned series of reactors similar to the pressurised water reactor (PWR), Sizewell B. Two major factors that changed the argument about energy policy became clear in around 2005. First, it was recognised that the days of cheap domestic gas were numbered. The North Sea gas and oil fields were quickly becoming depleted and new fields in deeper waters were proving more difficult and more expensive to develop. The UK had become too dependent on gas. In the future gas would increasingly have to be imported and therefore supplies would be less secure. Second, the arguments about climate change and the part played by carbon dioxide emissions were becoming more pressing. The UK government could not continue with an energy policy which depended on coal and gas. It was also recognised that renewables could not on their own provide a secure and stable low-carbon electricity system. The existing nuclear power stations were expected to come to the end of their operating lives in the coming decade. Therefore a plan at least for their replacement was necessary. These arguments were laid out in the Energy White Papers in 2006 and 2008.3 PROGRAMME DESIGN The liberalisation of energy markets was seen to have been a success, delivering the lowest electricity prices in Europe and bringing forward investment in new gas-fired power stations. In addition, there had been twenty years of government seeking private finance for all but the most essential capital expenditure. The main nuclear utility, British Energy, had been privatised in 1995. When it failed in 2003, it was taken into public ownership before being sold again to EDF, the French state utility. In 2008, these factors, combined with the memory of the long and expensive AGR and PWR programmes, led the government to attempt to make the new nuclear programme wholly a private-sector activity,

2

3

Our Energy Future – Creating a Low Carbon Economy (February 2003) CM 5761, para. 4.67, available at http://webarchive.nationalarchives.gov.uk/+/http:/www.berr.gov.uk/files/file10719.pdf The Energy Challenge – Energy Review Report 2006 (July 2006) CM 6887, pp. 185 and 194; and the Nuclear White Paper 2008, Meeting the Energy Challenge CM 7296, pp. 4–7.

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without any government support or subsidy. This strategy flew in the face of the experience of nuclear investment in every other country in the world. Most countries, including the UK, have constructed their reactors using state-backed electricity utilities. The US built over 100 nuclear reactors, with private funds but mostly with state guarantees of the recovery of investment through controlled energy prices. This public-sector structure has two effects: it reduces the cost of capital, a crucial factor for nuclear, and it ensures that any costs of construction over-run and any additional engineering required by the safety regulator can be recovered. The UK position was that nuclear designs were now mature; they could be built more quickly and more cheaply than in the past, as long as proven designs were selected and the responsibility and risk was transferred to the private sector. Large, experienced nuclear utilities would be able to both fund the construction and support the commercial risk of operating the reactors. Therefore a policy of ‘no subsidy’ and ‘no public funding’ was established.4 To ensure that the government was not held to ransom by a single dominant supplier, it was expected that there would be at least two nuclear construction groups and two utilities. The very large financial demands of nuclear power meant that only the largest companies could be expected to fund such projects. When EDF bought British Energy in 2008, it was the largest nuclear utility in the world. EDF was expected to replace the AGRs with modern French reactors. Assurances were provided by both parties to that effect. The two very large German utilities E.ON and RWE came together to provide the second group – Horizon Nuclear Power. Each had bought a part of the UK electricity supply system and they both operated nuclear power stations in Germany. However, after the earthquake and tsunami-triggered nuclear accident at Fukushima in Japan in 2011, Germany turned its back on nuclear power, and E.ON and RWE sought an exit from the arrangement. Horizon was bought by Hitachi, the Japanese designer of Boiling Water Reactors. A third grouping was attracted by the promise of the UK programme – NuGen, a joint venture of GDF Suez and Iberdrola, both of which own nuclear power stations in their home markets. In the event, the turmoil following the 2007 financial crash led to the withdrawal of Iberdrola and the purchase of a controlling stake in NuGen by Toshiba, the owner of Westinghouse: the nuclear engineer and designer of AP1000. The resulting nuclear new-build programme can be seen in Table 44.1 (and see Table 44.2 for a comparison of different nuclear power programmes). 4

The Rt Hon. Chris Huhne MP, ‘Alongside the other announcements being made today on steps the government is taking to enable new nuclear power, I should like to take the opportunity to reconfirm the government’s policy that there will be no public subsidy for new nuclear power. To be clear, this means that there will be no levy, direct payment or market support for electricity supplied or capacity provided by a private-sector new nuclear operator, unless similar support is also made available more widely to other types of generation.’ Written Ministerial Statement on energy policy (18 October 2010).

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Table 44.1 UK nuclear new-build programme Investor/Operator

Site

Reactor

Capacity

EDF/CNNC /Areva

Hinkley Point

2 × EPR

3.3 GWe

Sizewell

2 × EPR

3.3 GWe

Hitachi/Horizon

Wylfa

2 × ABWR

2.7 GWe

Toshiba/GDF

Oldbury

2 × ABWR

2.7 GWe

Suez/NuGen

Moorside

3 × AP1000

3.3 GWe

SELECTION OF DESIGN As a matter of policy the UK government has not been directly involved in the choice of reactor designs. Its desire is to transfer project and commercial risk to the nuclear operators. If the operator selects a reactor type, it will have to live with the consequences. Government requires only that the design meets the requirements of the independent nuclear safety regulator ONR. This hands-off approach to managing the programme has been successful in making transparent many types of costs not previously included in the investment debate. These costs and their attendant risks include the project completion and build schedule, the operating availability risk, the back-end costs of nuclear waste and ultimately reactor decommissioning. Construction costs are high for nuclear power stations, representing at least 60 per cent of the lifetime levelised cost of electricity. Such costs must be contained if a nuclear project is to be financially viable. Any delay to construction adds to investment costs, as well as delaying the point at which revenue is first generated. Therefore control of both the capital cost and the construction schedule are crucial to the viability of any nuclear project. Very large increases in construction costs from those estimated in 2006 are now apparent. The first UK project at Hinkley Point will cost almost 2.5 times more than originally expected. Worse still, the high cost of Hinkley Point has been carried over to the second station, Sizewell C. AP1000 was intended to be cheaper than other designs as it uses much smaller quantities of steel, concrete, pumps, valves and pipework. When mature it should be cheaper, but early indications from the US are that the first-of-kind projects have costs similar to EPR. Further, the early AP1000 projects are exhibiting both schedule slippage and project cost increase. Because ABWR has previously been built in Japan and has a record of speedier construction, it is likely that ABWR construction costs will be closer to the target set in the 2006 Energy Review. PRIVATE V. PUBLIC SECTOR FUNDING OF NUCLEAR Very high capital costs have two significant effects. First, the scale of investment costs is so large (Hinkley Point C, for example, cost £24 billion, including interest)5 that they are beyond the financial resources of any single company. 5

T. Probert, ‘Why will Hinkley Point C cost £16bn?’ (4 January 2014), available at http://millicentmedia .com/2014/01/04/why-will-hinkley-point-c-cost-16bn

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Second, the predicted cost of electricity from these reactors becomes very high, much above both the current and expected market price of electricity. This exposes the operator to revenue risks which could make the project unviable. The contracted electricity price for Hinkley C of £92.50/MWh6 can be compared with the target price set in the 2006 Energy Review of £54/MWh (inflated to 2013), an increase of 65 per cent. The EPR design is particularly complex and difficult to construct.7 In France and Finland, EPR projects are taking at least ten years. With the lack of recent UK experience of nuclear construction, schedules are not expected to be shorter at least for the two reactors. The UK government’s response in the Energy Act 20138 introduced contractual features that ameliorate the commercial and financial risks for nuclear utilities. The Act provides electricity price guarantees through long-term contracts for differences (CfDs) and loan guarantees for about 60 per cent of the prospective capital costs. These actions cut the operator’s revenue risk and reduce the amount of equity that needs to be committed by the investor. Inflation-linking of the electricity price is included which is beneficial to operator pricing. In addition, there are contractual forms of insurance, or guarantees against unforeseen delays to construction. Much has changed since 2006 when the strategy for nuclear new-build was established. The previous market-based investment approach has been markedly changed in response to both the financial crisis and the very high cost of the reactors chosen. Construction risk has been made transparent and has to some degree been transferred to the private sector. Though privatesector funding remains, it is now supported by guarantees for loans and the revenue risk has been made manageable by CfDs. These lifetime contracts locking in the high prices agreed at the outset will also distort the electricity trading market. The UK programme now resembles those of the US and elsewhere in which the funding is private but the main financial risks are carried by government. If these are necessary changes, the question is: at what cost? INDUSTRIAL ASPECTS The decision to split what is a relatively small programme between three reactor vendors means that there will be little learning between the construction teams and the costs for three short runs of reactor builds will remain high. Furthermore, the UK will have to bear the higher costs of supporting

6

7

8

Department of Energy and Climate Change, ‘State aid approval for Hinkley Point C nuclear power plant DECC’, Press Release (8 October 2014), available at www.gov.uk/government/news/ state-aid-approval-for-hinkley-point-c-nuclear-power-plant F. Roussely, ‘Future of the French civilian nuclear industry’ (16 June 2010), Report Summary, 4, available at www.psr.org/nuclear-bailout/resources/roussely-report-france-nuclear-epr.pdf Energy Act 2013 Chapter 32 (18 December 2013).

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the operation of different reactor types throughout their operating lifetimes. Allowing the private sector to choose a number of different reactor types means that long-term electricity costs of nuclear will be significantly higher, perhaps 15 per cent higher than otherwise. There is a second, more strategic argument. Unlike almost all other nuclear nations, the UK decided to be a ‘taker’ rather than a ‘maker’ of nuclear power. In the past, the UK designed its own reactors and even Sizewell B, which was originally an US design, included a sizeable share of UK content and technology. The UK signalled its intent to ‘buy’ nuclear electricity rather than ‘invest’ in the nuclear industry when it sold Westinghouse to Toshiba in 2006. The benefits of having a choice between different reactor designs appeared to be more important than owning what was probably the most advanced nuclear design (AP1000), with the most experienced nuclear design team in the world. Much of current reactor technology originated from the US. The US has been careful to maintain its leadership, though developed countries with large reactor programmes have sought to acquire both manufacture and elements of the technology. Japan, France and South Korea (see Table 44.2) have all succeeded to the extent that they have built most of their own nuclear power stations and now are exporting their own variants of previously US designs. China is following a similar path having licensed reactor designs from both the US (AP1000) and France (Areva M3), first transferring manufacturing and reactor technology before designing their own variants of the reactors. Now they wish to export variants of the French reactor design. The UK new-build programme has not focused on a single reactor design, nor has it sought to ensure that key components and systems are made here. Part of the price of this hands-off programme approach is the relatively poor value of the UK content. Though perhaps 50 per cent of the total cost of the reactors will be UK-sourced, the vast majority of this will be construction and commissioning work by tradesmen and technicians. The higher-value manufactured components and systems will be imported from the global networks that the reactor vendors have established. When the 16 GWe newbuild programme is finished, any technological and industrial legacy will be limited, both for future follow-on UK reactors and for the wider nuclear export market. It seems that the UK will have provided guarantees for around £100 billion of investment, and electricity customers will repay this investment through higher prices, without the benefit of either a significant involvement in the ongoing technology or a secure place in the future nuclear component or systems manufacture. This seems to be a very steep price for the planned nuclear programme and it represents the loss of a strategic opportunity for the UK to gain a share of high-value manufacturing and of future global nuclear developments.

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Table 44.2 National nuclear programmes compared Country US

No. of reactors Strategy 100+

Wide range of BWRs and PWRs built by four different vendors working for many small utilities; most reactors different in design to each other. Financial support provided through regulated electricity prices.

Construction synergy

Operations synergy

Poor record of many design differences, small utilities unable to learn lessons and wide geographic spread.

Initially poor – consolidation of utilities and improved operating performance/costs.

Japan

48

BWR and PWR designs Scope for savings built by three vendors militated by number of based on US technology vendors and utilities. with several utilities but with strong central control.

Scope for savings militated by number of vendors and utilities.

France

58

Single state-owned utility – built standard designs based on an established Westinghouse design very quickly, with strong central control. Design was indigenised to create a capability to design and export reactors.

Good scope for synergy, perhaps impeded by the very high speed of build.

Good scope for operating synergies achieved by common design and a single operator.

Germany

19

Two utilities owned in part by local states, built modern PWRs and BWRs of their own designs – now destined to shut down by 2022.

Somewhat fractured construction landscape with three utilities and several designs.

Limited due to fractured nature of industry – mergers generated potential savings.

Russia

33

Initially own concept RBMK – now mainly LWRs of their own design and technology being standardised as VVER1000. Starting to export under BOOT commercial deal.

Scope for learning between projects with single vendor – RosAtom.

Good scope for learning between reactors.

China

21

Built a mixture of their own, French, Russian, Canadian and US reactor designs under licence – experimenting before selecting two designs for mass deployment – centrally controlled, stateowned and state-funded utilities.

Some synergy but too many designs – will be possible with mass deployment of two selected design types.

Not yet – too many designs – will be possible with mass deployment of two selected design types.

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Country

No. of reactors Strategy

235

Construction synergy

Operations synergy

India

20

State-owned and controlled. Own designs adapted from CANDU, now purchasing Russian and Western designs.

Little evidence of synergies of construction.

Little evidence – but state-run programme which could benefit.

South Korea

23

After mixture of CANDU, French and US designs have standardised on CE80+ design licensed from US, – developed as national programme, made in Korea and now being exported.

Good for CE80+derived design, organised as a national programme.

Good for CE80+-derived design, organised as a national programme.

UK

40

Twenty-four early Magnox from five vendors; fourteen AGRs from three vendors and one modern PWR. Early technical strength was eroded by privatisation of the main utility British Energy and its exposure to an electricity market which favoured vertical integration and low capital cost generating plant.

Very poor – too many designs and too many vendors. Sizewell PWR licensed from US Preparations made for indigenous programme but curtailed by the ‘dash-for-gas’.

Weak – with too many designs and vendors. Scope for synergy from centralised operators/utilities militated by a myriad of design variants.

Source: Data from WNA Reactor Database, available at http://world-nuclear.org/info/ Country-Profiles

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DELIVERING UK NUCLEAR POWER IN THE CONTEXT OF EUROPEAN ENERGY POLICY: THE CHALLENGES AHEAD Philip Johnstone1

INTRODUCTION The UK is one of the few countries in Western Europe to attempt the construction of new nuclear power, aiming to develop up to 16 GW of new nuclear capacity by 2030.2 Nuclear is widely considered to be an important low-carbon technology to mitigate against climate change and provide energy security in the energy policy landscape more generally.3 If nuclear is to take on such a role, however, then the word raised by this edited collection – delivery – and the factors required to successfully deliver new nuclear to time and budget, are crucial considerations. Nuclear’s low-carbon status is now well known, but it is practical questions of the technology’s feasibility in terms of its potential deliverability that warrants more focus. As the UK is one of the few contexts where attempts are being made to construct new nuclear in a ‘liberalised’ energy market, it is important to take stock of actions taken thus far to facilitate new nuclear and 1

2

3

Philip Johnstone is a Research Fellow at the Science Policy Research Unit (SPRU), University of Sussex. He currently works on the ESRC-funded Discontinuity in Technological Systems (DiscGo) alongside colleagues in Dortmund, Twente and Paris, a project focusing on the governance process of discontinuing certain technological trajectories. This task is a crucial one in accelerating transitions to more sustainable energy systems. Phil is a member of the Sussex Energy Group (SEG), where his work is centred around nuclear power, the democratic implications of different energy technologies and governance processes surrounding the shift towards decentralised energy systems. He is also the Tyndall Centre Coordinator for the University of Sussex. Department of Energy and Climate Change, National Policy Statement for Nuclear Power Generation (EN-6), vol. I (The Stationery Office, 2011). Intergovernmental Panel on Climate Change, Renewable Energy Sources and Climate Change Mitigation. Special Report of the Intergovernmental Panel on Climate Change (IPCC, 2012).

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how effective these have been. This brief chapter quickly reviews these actions before situating UK new-build in the multi-level governance context of the increasing ‘Europeanisation’ of energy policy, which has presented unforeseen barriers to the UK new-build programme and which will potentially make new nuclear construction projects increasingly challenging in the future. THE UK’S PROACTIVE APPROACH TO NEW NUCLEAR The UK government has been one of the most proactive in the world in addressing some of the perceived historic ‘barriers’ to nuclear development.4 This has included speeding up and streamlining the planning system in which the development of nuclear power and other nationally significant infrastructure takes place.5 Perhaps most symbolically, it has involved removing the ‘public inquiry’ – an aspect of the British planning system that had long been blamed by government and industry for slowing down nuclear development.6 The government has also designed National Policy Statements for nuclear and other areas of energy policy more broadly, to attempt to provide ‘certainty’ for potential investors.7 Licensing procedures for new reactors have also been speeded up and an independent Office for Nuclear Regulation (ONR) created.8 The UK now has one of the most supportive policy environments for nuclear developments with the creation of the Office for Nuclear Development (OND), a section of the Department of Energy and Climate Change (DECC) designed to ‘facilitate’ new nuclear.9 Another crucial step taken by the UK government was the attempt to make new nuclear (alongside other low-carbon technologies) cost competitive through electricity market reforms.10 This included the agreement of a ‘strike price’ guarantee with EDF, the main operator and investor in UK nuclear power. A guaranteed minimum price of £92.50/MWh was agreed to provide EDF safety from investment risks caused by nuclear’s significant upfront capital costs and fluctuations in future energy markets for a thirty-five-year period.11 Despite these actions, however, the Hinkley C development, which is the first new nuclear power station under construction in the UK for two decades, 4

World Nuclear Association, ‘Nuclear power in the United Kingdom’ (2015), available at www. world-nuclear.org/info/Country-Profiles/Countries-T-Z/United-Kingdom 5 HM Government, Meeting the Energy Challenge: A White Paper on Nuclear Power (The Stationery Office, 2008). 6 P. Johnstone, ‘Planning reform, rescaling, and the construction of the postpolitical: the case of the Planning Act 2008 and nuclear power consultation in the UK’, Environment and Planning C: Government and Policy 32(4) (2014), available at www.envplan.com/abstract.cgi?id=c1225 7 Department of Energy and Climate Change, National Policy Statement for Nuclear Power Generation. 8 World Nuclear Association, ‘Nuclear power in the United Kingdom’ 9 Ibid. 10 Department of Energy and Climate Change, ‘Electricity market reform’ (2013), available at www. gov.uk/government/policies/maintaining-uk-energy-security--2/supporting-pages/electricity-marketreform 11 World Nuclear News, ‘Hinkley Point C contract terms’, World Nuclear News (8 October 2014), available at www.world-nuclear-news.org/NP-Hinkley-Point-C-contract-terms-08101401.html

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as well as being one of the key developments around which the hopes of a European nuclear revival are largely based,12 has faced repeated delays,13 spiralling cost estimates14 and issues surrounding a lack of a final investment commitment from main stakeholders in the project.15 It has often been the conventional wisdom of industry and government that delays and cost increases in the 1970s and 1980s were caused by too much ‘conflict’ and an inefficient planning system.16 However, there are no longer public inquiries, the planning system has been streamlined and there is said to be a ‘political consensus’ around nuclear power in the UK.17 Therefore, it is difficult to blame these factors this time around. UNEXPECTED CHALLENGES TO THE DELIVERY OF NUCLEAR POWER IN THE UK Unlike in other national contexts, the nuclear accident at Fukushima in Japan in 2011 had no lasting effect on the UK government’s enthusiasm for constructing new reactors.18 The first shock to UK nuclear came when E.ON and RWE – both German companies – withdrew their intentions to invest in UK nuclear power,19 followed by Centrica withdrawing its interest in the Hinkley C project, citing rapidly escalating costs as the reason.20 Thus, the only player left in the game was EDF who needed to find other investment partners in order to proceed with the Hinkley C development. It is likely that Hinkley C will rely on investment from the Chinese state-owned China National Nuclear Corporation and China General Nuclear.21 12

World Nuclear Association, ‘Nuclear power in the European Union’, World Nuclear Association (27 October 2015), available at www.world-nuclear.org/info/Country-Profiles/Others/EuropeanUnion 13 T. Macalister, ‘EDF Energy delays Hinkley Point nuclear decision’, The Guardian (12 February 2015), available at www.theguardian.com/business/2015/feb/12/edf-energy-delays-hinkley-pointnuclear-decision 14 E. Gosden, ‘Hinkley Point C: the story so far’, The Daily Telegraph (12 October 2015), available at www.telegraph.co.uk/news/earth/energy/nuclearpower/11404344/Hinkley-Point-new-nuclearpower-plant-the-story-so-far.html 15 M. Stothard and C. Adams, ‘EDF delays investment decision on UK nuclear reactor plans’, Financial Times (12 February 2015), available at www.ft.com/cms/s/0/04ce991e-b28c-11e4-a05800144feab7de.html#axzz3bEzaO3V6 16 EDF Energy, ‘Response to the Energy Review to DTI’ (2005), available at www.ref.org.uk/ attachments/article/163/ref.future.proofing.10.06.pdf 17 R. Milne, ‘John Hutton: nuclear renaissance man’ Utility Week (14 September 2011), available at www.utilityweek.co.uk/news/John-Hutton-nuclear-renaissance-man/769462#.U8Ft3803dy8 18 M. V. Ramana, ‘Nuclear policy responses to Fukushima: Exit, voice, and loyalty’, Bulletin of the Atomic Scientists 69(2) (2013), 66–76, available at http://bos.sagepub.com/content/69/2/66.full 19 D. Milmo and F. Harvey, ‘Nuclear giants RWE and E.ON drop plans to build new UK reactors’, The Guardian (29 March 2012), available at www.theguardian.com/environment/2012/mar/29/ nuclear-reactors-rwe-eon-energy 20 E. Gosden, ‘Centrica exit threatens UK nuclear plans’, The Daily Telegraph (4 February 2013), available at www.telegraph.co.uk/finance/newsbysector/energy/9846895/Centrica-exit-threatensUK-nuclear-plans.html 21 World Nuclear News, ‘UK government paves way for Chinese nuclear plant’, World Nuclear News (18 June 2014), available at www.world-nuclear-news.org/NP-UK-government-pavesway-for-Chinese-nuclear-plant-18061401.html

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Problems have also been encountered regarding the ‘strike price’ agreement between the UK government and EDF. Negotiations on agreeing a strike price took far longer than initially expected,22 and then further delays were caused by the ‘unforeseen’ barrier of the European Competition Commission, who began an investigation into the Hinkley C strike price deal amid concerns that the deal constituted illegal state aid.23 Whilst the investigation in the end concluded that Hinkley C and the strike price deal could go ahead, the commission report revised the cost forecasts for the two reactors at Hinkley point from EDF’s figure of £16 billion to £24 billion.24 Further barriers that extend beyond the UK context are also present. Austria is launching a legal challenge against the Hinkley C project as the Austrian government argues that the funding mechanisms for the project could negatively impinge on EU electricity market integration and constitute illegal state aids despite the Commission’s decision.25 A German energy cooperative owned by Greenpeace is also pursuing an energy challenge which could prove a further stumbling block for Hinkley C.26 Other potentially disruptive factors largely out of the control of the UK government abound. The construction experiences of the EPR reactor design in Finland and France has been dire with lengthy delays of up to nine years and vast cost-overruns.27 Areva, also invested in Hinkley C and also a French state-owned company, faces unprecedented financial difficulties with potentially significant implications for nuclear new-build across Europe, given its key role in the nuclear supply chain.28 BROADER CHALLENGES AHEAD – WHICH DIRECTION ARE THE WINDS BLOWING IN EU ENERGY POLICY? As recognised by the World Nuclear Association,29 very few new-build projects are underway in Europe, and European energy market integration is likely to 22

T. Macalister, ‘Coalition still “optimistic” about nuclear power despite EDF and China concerns’, The Guardian (17 May 2013), available at www.theguardian.com/business/2013/may/17/ coalition-optimistic-nuclear-power-edf-china 23 European Commission, ‘State aid SA. 34947 (2013/C ) (ex 2013/N) – United Kingdom Investment Contract (early Contract for Difference) for the Hinkley Point C New Nuclear Power Station’ (2013), available at http://ec.europa.eu/competition/state_aid/cases/251157/251157_1507977_35_2.pdf 24 A. Barker and P. Clarke, ‘Brussels backs Hinkley Point C as cost forecasts soar’ Financial Times (8 October 2014), available at www.ft.com/cms/s/0/372216e6-4ec0-11e4-b205-00144feab7de. html#axzz3bEzaO3V6 25 A. Barker and P. Clarke, ‘Brussels backs Hinkley Point C as cost forecasts soar’, The Financial Times (8 October 2014), available at www.ft.com/cms/s/0/372216e6-4ec0-11e4-b205-00144feab7de.html #axzz3bEzaO3V6 26 O. Tickell, ‘Greenpeace Energy to launch legal challenge to UK nuclear subsidies’ The Ecologist (5 March 2015), available at www.theecologist.org/News/news_round_up/2780807/greenpeace_ energy_to_launch_legal_challenge_to_uk_nuclear_subsidies.html 27 P. Wynn Kirby, ‘Europe’s new nuclear experience casts a shadow over Hinkley’ The Guardian (25 March 2014), available at www.theguardian.com/environment/2014/mar/25/europes-newnuclear-experience-casts-a-shadow-over-hinkley 28 E. Gosden, ‘EDF: Areva decision not “existential” for Hinkley Point’, The Daily Telegraph (5 March 2015), available at www.telegraph.co.uk/finance/newsbysector/energy/11453149/EDF-Areva-investment-not-existential-for-Hinkley-Point.html 29 World Nuclear News, ‘Europe launches its Energy Union’, World Nuclear News (25 February 2015), available at www.world-nuclear-news.org/NP-Europe-launches-its-Energy-Union-2502151.html

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provide significant challenges for the future of nuclear power. This depends on the direction of travel that European energy market reforms take in terms of the interlinking transformations in incentivising certain low-carbon technologies over others, changing grid designs and associated changes in utility structures and business practices. The action of powerful utilities and manufacturing companies is one place to start in understanding potential policy directions regarding nuclear as opposed to other technologies. Germany’s Siemens corporation, former world leaders in the nuclear manufacturing sector, have pulled out of the nuclear sector altogether. Elsewhere, the shift towards decentralised energy systems in Germany has caused traditional utilities to significantly alter their behaviour, with the CEO of RWE declaring that due to the impressive growth of renewables, ‘the price we receive for generating power is currently so low that it is simply irresponsible to build an expensive nuclear power plant in Europe. The nuclear power chapter has come to an end’.30 E.ON, the large German utility and for decades a key player in nuclear investment and operation across the world, has ‘spun off’ its nuclear and fossil fuel portfolio to focus on investment in renewables, distribution and ‘customer solutions’, citing the changing nature of the global energy system as a key motivation.31 Whilst it is true that these are German companies responding in part by the German government’s politically motivated Energiewende which includes the phase-out of nuclear power, their decision-making potentially also points towards perception of more general changes underway in energy systems. Certainly the case of Germany demonstrates that the traditional big utility-run, centralised, load-optimised form of electricity provision (into which nuclear has traditionally fitted best) is being tested with the growth of renewables and the attempted move towards a decentralised, intelligent load- and supply-oriented structure. It is possible that small modular reactors (SMR) may provide a means for nuclear technologies to adapt to changing circumstances, however the economics are largely unknown and there is not a single SMR licensed anywhere in the world.32 The documentation surrounding plans for the Energy Union identifies a shift underway from a ‘centralised’ to a ‘decentralised’ system moving away

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A. Teichmann, ‘CEO of energy giant RWE: “The nuclear power chapter has come to an end”’, Der Spiegel (29 June 2012), available at www.spiegel.de/international/business/rwe-s-new-ceoterium-to-halt-nuclear-power-and-invest-in-renewables-a-841260.html 31 E.ON, ‘New corporate strategy: E.ON to focus on renewables, distribution networks, and customer solutions and to spin off the majority of a new, publicly listed company specializing in power generation, global energy trading, and exploration and production’, Press Release (30 November 2014), available at www.eon.com/content/eon-com/en/media/news/press-releases/2014/11/30/newcorporate-strategy-eon-to-focus-on-renewables-distribution-networks-and-customer-solutionsand-to-spin-off-the-majority-of-a-new-publicly-listed-company-specializing-in-power-g 32 G. Mackerron and P. Johnstone, ‘Small modular reactors: the future of nuclear power?’, Sussex Energy Group Blog (2 March 2015), available at https://blogs.sussex.ac.uk/sussexenergygroup/ 2015/03/02/small-modular-reactors-the-future-of-nuclear-power

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from ‘outdated business models’,33 in which barely any reference was made to nuclear.34 For large-scale nuclear there may potentially be technological and economic compatibility issues in the long run when the move towards a system based on decentralised renewables is considered. These relate to the potential challenges that greater penetration of decentralised variable renewables may pose to the traditional ‘baseload’ energy concept,35 as well as signs of rapidly improving battery storage technology which could radically reshape the structure of energy markets and the current utility model.36 All of these potential transformations could impinge on the future deliverability of nuclear power. It may be that in terms of energy choice Britain and Western Europe are out of sync. Given Britain’s reliance on European players to invest in their energy system regardless of what technological choice they go for, as well as the significant changes that may come about through a European energy market integration that if anything looks more likely to tilt in favour of renewables rather than nuclear power, the delivery of new nuclear power in the UK could become increasingly challenging, regardless of the efforts put in at the national level.

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European Commission, ‘Energy Union package: a framework strategy for a resilient Energy Union with a forward-looking climate change policy’ (25 February 2015), available at http:// ec.europa.eu/priorities/energy-union/docs/energyunion_en.pdf 34 World Nuclear News, ‘Europe launches its Energy Union’, World Nuclear News (25 February 2015), available at www.world-nuclear-news.org/NP-Europe-launches-its-Energy-Union-2502151.html 35 M. Schneider and A. Froggatt, ‘The world nuclear industry status report 2014’ (2014), available at www.worldnuclearreport.org/WNISR2014.html 36 R. Anderson, ‘Energy storage paves way for electricity independence’, BBC News (3 March 2015), available at www.bbc.co.uk/news/business-31040723

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NUCLEAR LIABILITY: CURRENT ISSUES AND WORK IN PROGRESS FOR THE FUTURE Cheryl Parkhouse1

INTRODUCTION The global nature of the nuclear industry, the potential transboundary impact of any incident2 and the intrinsic international commercial relationships in place mean that the nuclear liability regime of one state can no longer be viewed or provide adequate protection in isolation. This has led to increasingly complicated legal drafting and stipulation of complex nuclear indemnities as a prerequisite of entering into commercial transactions, in turn further fuelling the continued call for a global nuclear liability regime. The issues are not new to the nuclear industry but are becoming increasingly pertinent, particularly following the Fukushima Daiichi incident.3 1

2

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Cheryl Parkhouse is a Senior Associate solicitor in the Nuclear Unit, Burges Salmon LLP, Bristol, UK. She specialises in nuclear and environmental regulatory issues in decommissioning and newbuild projects; radioactive contaminated land, waste disposal and licensing matters; and commercial transactions including nuclear supply-chain contracts and agreements relating to various stages of the fuel cycle. Cheryl regularly advises on and has a particular interest in nuclear liability, including the negotiation of nuclear indemnities, in both on-site commercial transactions and national and international nuclear transport agreements. As experienced following the 1986 Chernobyl disaster in Ukraine. See World Nuclear Association, ‘Chernobyl accident 1986’ (updated April 2015), available at www.world-nuclear.org/info/ Safety-and-Security/Safety-of-Plants/Chernobyl-Accident For further information on the Fukushima Daiichi accident see Nuclear Energy Agency (hereafter NEA)/Organization for Economic Cooperation and Development (hereafter OECD), ‘Japan’s compensation system for nuclear damage – as related to the TEPCO Fukushima Daiichi nuclear accident’ (2012), available at www.oecd-nea.org/law/fukushima/7089-fukushima-compensationsystem-pp.pdf

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This chapter outlines some reasons behind the continued call for a global regime through a brief review of issues arising in nuclear transport and the growing international movement of nuclear supply chain skills; and the steps being taken to attempt to address this ‘patchwork’ of laws. THE INSTRUMENTS To balance and promote the economic advantages versus the potential risks of the expanding civil nuclear industry, the Paris/Brussels4 and the Vienna5 international civil nuclear liability law regimes emerged in the 1960s, subject to various amendments.6 These were later followed by the bridging Joint Protocol7 and then, much later, the 1997 Convention on Supplementary Compensation (CSC).8 These legal instruments are founded upon internationally accepted principles,9 often unique to nuclear, to facilitate efficient remedies for victims of a nuclear incident through providing easy identification of one defendant – the liable operator – and the resolution of claims in a single jurisdiction. The principles of exclusive and absolute liability of the responsible nuclear operator for damage10 arising from a nuclear incident are central to these instruments.11 Liability is legally channelled to the responsible operator as 4

The OECD’s Convention on Third Party Liability in the Field of Nuclear Energy adopted in Paris in 1960 (as amended) (hereafter the Paris Convention or PC); and the Convention Supplementary to the PC adopted in Brussels in 1963 (hereafter the Brussels Supplementary Convention’). 5 The International Atomic Energy Agency’s 1963 Vienna Convention on Civil Liability for Nuclear Damage (hereafter the 1963 Vienna Convention or VC). 6 The PC as amended by the Additional Protocol of 28 January 1964 (entering into force with the PC in 1968), the Protocol of 16 November 1982 (in force in 1988) (and to be further amended by the 2004 Protocol to Amend the PC not yet in force); and the VC by the 1997 Protocol to Amend the 1963 VC (hereafter the 1997 Vienna Protocol). 7 This entered into force on 27 April 1992, providing a bridge between the VC and PC through providing its contracting parties with the benefits of both Conventions. Contracting parties include France, the Netherlands, Germany, Italy, Latvia, the Czech Republic, Egypt and Uruguay. 8 The IAEA Convention on Supplementary Compensation for Nuclear Damage 1997 (CSC). This came into force on 15 April 2015 following Japan’s ratification as the sixth member country at the end of 2014 alongside the United States, Canada, India, Romania and the United Arab Emirates. Montenegro has also recently acceded to the instrument; see www.iaea.org/Publications/ Documents/Conventions/supcomp_status.pdf. The CSC aims to supplement the compensation amounts already available under national law of the contracting parties providing a similar tiered approach to the Brussels Supplementary Convention. Contributions of contracting states are calculated upon the basis of installed nuclear capacity per state and UN rate of assessment per MW thermal; see http://ola.iaea.org/ola/CSCND/Calculate.asp 9 These include absolute and exclusive liability of the responsible operator; minimum liability amounts; claims limited in time; mandatory financial coverage; channelling of jurisdiction; and non-discrimination. 10 ‘Nuclear Damage’ as defined by the Conventions. For example, the heads of damage for which compensation is currently provided under the PC are personal injury or loss of life; and property damage or loss (excluding the nuclear installation or any property used in connection with the nuclear installation at the time of the incident). 11 See Article 6(a) and (b) of the PC.

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determined by the Conventions regardless of any fault or negligence on its part12 to the exclusion of all other potentially liable persons and other applicable law. Claims are then channelled through the identified ‘competent courts’.13 ISSUES However, the effectiveness of these principles in practice to achieve protection for victims is undermined by many prominent nuclear states not having Treaty relations.14 The effect is that these fundamental principles do not apply at all or apply differently to different states in the commercial transaction or to potential victims of a nuclear incident.15 For example, a national of a nonContracting Party is not bound by the channelling principle in bringing its claim and is unable to rely on the remedies offered, leaving parties other than the operator open to risk of a claim; such claim subject instead to the law of the jurisdiction chosen by the injured party or other international law,16 potentially unlimited in scope and value. Even on a regional scale this has substantial impact: most Eastern European EU member states have acceded to the VC and Western European member states to the PC; one member state has signed the CSC, whilst others have not signed any instrument.17 Even for those with Treaty relations, the application of the principles as implemented into national law, financial limits available and insurance coverage vary considerably and still require bespoke contractual drafting.18 It is the impact of this ‘patchwork’ of nuclear liability law on a global scale that is coming under increasing scrutiny. A view is that effective protection and certainty, and therefore risk management in contract, for third parties, nuclear operators and contractors, can only begin to be tackled when the same principles apply to all states involved in or potentially affected by a nuclear transaction through a global regime. 12

Strict liability, meaning that victims need only show a causal link between the damage caused by a nuclear incident and not the fault or negligence of the operator. 13 The general principle is that the courts of the Contracting Party where the nuclear incident occurred (or where the installation of the liable operator is situated where the incident occurs outside Contracting Parties’ territory) are awarded jurisdiction. 14 See, for example, nuclear power states and liability conventions to which they are party: World Nuclear Association, ‘Liability for nuclear damage’ (updated April 2015), available at www. world-nuclear.org/info/Safety-and-Security/Safety-of-Plants/Liability-for-Nuclear-Damage 15 There are a number of prominent international nuclear states that have not been party to any of the international conventions and instead have had their own nuclear liability legislation in place. Such countries include the United States, Japan, Canada, India and the United Arab Emirates but which can now be found to be moving towards or which have already ratified the CSC. 16 See, for example, S. Goldenburg, ‘US sailors prepare for legal challenge over Fukushima radiation’, The Guardian (20 August 2014), available at www.theguardian.com/environment/2014/ aug/20/us-navy-sailors-legal-challenge-fukushima-radiation-tepco 17 For discussion, see European Commission, Final Report DG TREN/CC/01-2005, ‘Legal study for the accession of Euratom to the PC on third party liability in the field of nuclear energy’, produced by Gomez-Acebo & Pombo, Abogados SCP, available at http://mng.org.uk/gh/private/2009_12_ accession_euratom.pdf 18 See NEA/OECD, ‘Nuclear operator liability amounts and financial security limits’ (July 2014), available at www.oecd-nea.org/law/2014-table-liability-coverage-limits.pdf

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EXAMPLES IN PRACTICE First, the patchwork impacts significantly upon the commercial and contractual structure of international nuclear transport agreements. When nuclear material is transported between countries with Treaty relations, such as two PC states, the same legal principles will apply in each. For example, one operator will be held liable for an incident as determined by the Convention19 and will hold financial security20 to meet such liability for valid claims arising in Contracting States. Jurisdiction for such claims will be held by the competent courts, recognised by all Contracting States to receive claims for loss suffered. The Joint Protocol is also a valuable linking tool providing Treaty relations between its VC and PC signatory states. However, there is concern that ratification of this instrument is currently too limited to have any substantial effect, with significant nuclear states such as the UK and Russia not yet signatories.21 However, this changes for nuclear material transported between countries with no Treaty relations where nuclear liability is determined by (and only to the extent provided by) the national laws of the sending and receiving operator (reflecting any Convention to which the state is party) and potentially of any other state suffering harm, including potential recourse to international private/ public law remedies where applicable. The law of the sending state may not reflect the principles of the law of the receiving state potentially creating overlap (that is, where both operators or other parties could be liable for an incident occurring at the same stage of the journey,22 but each still potentially liable to different claimants) or a gap between the two legal systems (where neither operator is liable under a Convention). If the sending operator, for example, is a PC state, currently only contracting parties to the same Convention can file 19

For example, as provided by Articles 3 and 4 of the PC. As either specified in its national legislation or the national legislation of the contracting party through which the material is transported if it binds the ‘sending’ PC operator (but cannot exceed the amount imposed on national operators in that state); where the Brussels Supplementary Convention also applies, further fixed compensation tiers will also be available. 21 The latest party to ratify the instrument was France on 30 April 2014 following signature of the Joint Declaration with the United States in August 2013: NEA/OECD Nuclear Law Bulletin 92 (2013), 207, available at www.oecd-nea.org/law/nlb/nlb92.pdf. The UK is not a party to the Joint Protocol but has confirmed its intention to consider whether to enter into this once ratification of the 2004 Protocols is complete: DECC, ‘Implementation of changes to the Paris and Brussels Conventions on nuclear third party liability – Summary of responses and Government response to consultation’ (March 2012), paragraph 96, available at www.gov.uk/government/ uploads/system/uploads/attachment_data/file/42757/4874-parisbrussels-government-responseto-consultation.pdf 22 For example, when transporting from a PC state to a VC state which are not party to the Joint Protocol, in general terms, the sending PC operator is liable under the PC from the point of loading onto the form of transport up to unloading (or as implemented in the national law of the sending operator – for example, see Sec. 7 Nuclear Installations Act 1965) whilst, for the same journey, under the VC, the receiving VC operator is also liable from the same point of loading onto the transport at the PC port (and beyond). Therefore, in the event of nuclear incident occurring during the transport leading to damage in both Vienna and PC Contracting States, separate claims in separate courts under the different conventions would potentially be brought for the same incident. 20

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claims to the competent court, potentially exposing the operator or other parties (such as the owner of the material or consignor) to claims made elsewhere under different jurisdictions. Therefore, in assessing the legal drafting required to counter such risks where possible, issues that must be addressed include the potential liable party or parties under each applicable regime (including both under nuclear law and otherwise, such as tort law) at each point of the journey; and the potential scope, origin, validity and jurisdiction of potential claims (and the laws applicable to each). Second, the patchwork has also impacted the development of international nuclear markets for skills and innovation. An example is where contractors are nationals of one state that does not have Treaty relations with the host state within which they work, such as US nationals working in the UK decommissioning market. Therefore, notwithstanding the implementation of the nuclear liability principles into UK national law, non-Treaty states are not bound by the channelling and operator exclusive principles leaving non-operator parties (such as contractors working on site) open to risk of claims being heard in other jurisdictions where such claims are not barred. The current limited heads of damage23 of the international conventions also contribute to this unease, perceived a significant risk in not realistically reflecting or protecting against all actual claims that could arise from a nuclear incident. Any claims falling outside of the Conventions become subject to the law of the jurisdiction chosen,24 potentially with unlimited liability and generous damages. These issues are often cited by US contractors in particular providing works and services in the UK,25 where the risk of victims issuing claims in the US is perceived as high enough to require (subject to heavy negotiation) allencompassing indemnities. SOLUTIONS? The eagerly awaited implementation of the 2004 Amending Protocols is recognised to go some way in reducing the liabilities falling outside the current liability regime. The amendments include a substantial increase in the heads of damage26 for which claims can be channelled to the operator and, perhaps more significantly for the examples above, a widening of the geographical scope permitting citizens of qualifying non-contracting states27 to also bring claims 23

These are personal injury, death and property damage pending the 2004 Amending Protocol coming into force. 24 Potentially leading to ‘forum shopping’ of jurisdictions by the claimant. 25 See, for example, O. F. Brown II, ‘Nuclear liability: a continuing impediment to nuclear commerce’ (The Uranium Institute, 24th Annual Symposium, 1999), available at www.world-nuclear. org/sym/1999/brown.htm 26 The current heads of damage of personal injury, loss of life and damage to property will be extended to include: economic loss arising from personal injury or property damage; the costs of reinstatement measures of a significantly impaired environment; loss of income deriving from a direct economic interest in any use or enjoyment of the environment, incurred as a result of significant impairment of that environment; and the costs of preventive measures, and further loss or damage caused by such measures, paragraph B of the 2004 Amending Protocol. 27 Paragraph C of the 2004 Amending Protocol.

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against the liable operator under the Convention. Similar amendments have also been made to the Vienna regime but ratification to date has been limited. This limits the potential effectiveness of the instrument and impacts upon further ratification of the Joint Protocol currently continuing to render its application one-sided and unequal. On a regional level, in 2005 the European Commission announced its aim to harmonise the nuclear liability rules28 within the expanded EU through an impact assessment and study29 and later workshop in 2010.30 This was based on the recognition that, compared with recent and ongoing developments in the field of nuclear safety or radioactive waste management, the nuclear liability regime was compounded by low adherence to the revised VC or to the CSC and the delays in ratifying the 2004 Amending Protocols. The focus was placed upon initiatives of harmonisation through: (1) mutual recognition by member states of the existing instruments;31 and (2) the creation of a new instrument under Article 98, Euratom Treaty.32 Other considerations included liability insurance coverage; limited versus unlimited liability; state aid and competition law; and jurisdiction and enforcement of judgments.33 28

Nuclear Illustrative Programme, presented under Article 40 of the Euratom Treaty for the Opinion of the European Economic and Social Committee, Communication from the Commission to the Council and the European Parliament, COM(2006)844 final, 12 July 2007. 29 European Commission, Final Report DG TREN/CC/01-2005, ‘Legal study for the accession of Euratom to the PC on third party liability in the field of nuclear energy’. 30 Jointly organised by the Brussels Nuclear Law Association and the European Commission. The workshop was attended by a large number of people, consisting of both proponents of accession to the Joint Protocol (through the Paris or VCs) and a wider global regime under the CSC. 31 However, whilst the majority of stakeholders welcomed harmonisation, it was recognised that both of these options carried a number of issues. For example, VC states have been reluctant to sign the PC and commit to higher levels of compensation whilst the proposal for all EU member states to sign the Joint Protocol has highlighted unease that this will not remedy the large difference between the compensation levels available under the VC and the PC (which indeed become larger once the 2004 Amending Protocols are implemented). It was also felt that this latter option would not overcome the lack of confidence by some member states for the VC states to retain their minimum liability levels. Whilst ratification of the CSC by Romania has also placed it on the European agenda, there is currently uncertainty as to whether it is an appropriate option for the member states that are at a similar level of development and the priority provision for the distribution of compensation with half allocated for the treatment of victims outside the installation state has met with some reluctance stating that this would only add immense complexity to already complicated regimes in place. 32 A new Euratom Treaty instrument enabling European law to step in and legislate where the Conventions confer an issue to the national law of the contracting parties. This also faced hurdles, such as the power of the Community to act and the diverse application of national laws requiring individual consideration. For example, in order to create a consistent definition of property damage, the individual aspects of property law in each member state would need to be reviewed and compared with some form of common ground established, seriously interfering potentially unnecessarily with fundamental concepts of member states’ national law. 33 This relates to the compatibility of Brussels I (Regulation EC No 44/2001 on jurisdiction and the recognition and enforcement of judgments in civil and commercial matters); Rome II (Regulation 864/2007 on the law applicable to non-contractual obligations); and the Euratom Treaty.

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A Nuclear Liability Expert Group was then established34 followed by a European Commission public consultation in July 2013 on nuclear liability, focusing on existing instruments and views on potential changes through an EU-wide strategy.35 The consultation outcomes were announced and discussed at a further workshop in 201436 with a proposal that a communication on nuclear liability may be issued by the European Commission.37 On an international level, the Fukushima Daiichi accident triggered the IAEA’s Action Plan on Nuclear Safety again calling for the establishment of a global liability regime in 2013.38 This was endorsed by all member states at the 55th General Conference,39 and in 2012 INLEX40 produced recommended actions41 calling for both nuclear and non-nuclear states to adopt one or more of the international nuclear liability instruments and to create treaty relations with as many states as possible. Other recommendations included frequent reviews of available compensation and bolstering the scope of the existing

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Its work was divided into three working groups to review claims handling and related matters; insurance amounts and capacity; and the international conventions, with each producing a series of recommendations: See M. Beyens, ‘The EU tentative to harmonise nuclear liability among the EU member states in nuclear law in progress’, INLA Congress – Buenos Aires, Argentina, 2014 for a detailed description and discussion on the EU developments. 35 For a brief overview, see Burges Salmon ‘European Commission consultation on nuclear liability’, Stop Press (August 2013), available at www.burges-salmon.com/sectors/energy_ and_utilities/nuclear/publications/stop_press_european_commission_consultation_on_ nuclear_liability.pdf 36 ‘Taking nuclear third party liability into the future / fair compensation for citizens and level playing field for operators’, workshop, January 2014, jointly organised by the Brussels Nuclear Law Association and the European Commission. 37 The discussion focused on three key issues: the cross-border aspects of claims management; the relation between the insurance market’s capacity, the financial coverage of nuclear liability and electricity costs; and the implementation in EU member states of the international conventions in the field of nuclear third-party liability. However, due to the European elections following the workshop, the approach of the newly appointed European Commission was delayed. All presentations made at the conference are available at: http://ec.europa.eu/energy/nuclear/events/20140120_ nuclear_third_party_liability_and_insurance_en.htm 38 IAEA Action Plan on Nuclear Safety GOV/2011/59-GC(55)/14 of September 2011, available at www.iaea.org/About/Policy/GC/GC55/Documents/gc55-14.pdf 39 This called upon them ‘to work towards establishing a global nuclear regime that addresses the concerns of all states that might be affected by a nuclear accident with a view to providing appropriate compensation for nuclear damage . . . [and] . . . to give due consideration to the possibility of joining the international nuclear liability instruments as a step towards achieving such a global regime’. 40 IAEA, ‘International Expert Group on Nuclear Liability’, available at http://ola.iaea.org/ola/ inlex-group.html 41 ‘Recommendations on how to facilitate achievement of a global nuclear liability regime as requested by the IAEA Action Plan on Nuclear Safety by INLEX’, IAEA Action Plan on Nuclear Safety – Nuclear Liability, GOV/2011/59-GC(55)/14, available at http://ola.iaea.org/ola/documents/ActionPlan.pdf. See also the Director General’s report ‘Progress in the implementation of the IAEA action plan on nuclear safety’ (August 2012), GOV/INF/2012/11-GC(56)/INF/5, available at www.iaea.org/About/Policy/GC/GC58/GC58InfDocuments/English/gc58inf-7_en.pdf

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liability principles.42 Further developments have taken the form of the G20 leaders’ Declaration;43 international bilateral joint statements between France and the USA;44 and France and Russia.45 The recent entry into force of the CSC46 is, however, an enormous achievement, particularly as it brings major nuclear states previously not party to any international instrument into the international nuclear liability arena. It is strongly championed as the one instrument capable of creating a global regime,47 but this is however still heavily dependent upon increasing Treaty relations through wider ratification of the instrument and/or through the support of complementary regional instruments, such as the Joint Protocol. However, now that the CSC is in force, there is high potential for more states to sign up, substantially strengthening its influence. The significance of the link between and practical impacts of this instrument and the Paris/Vienna/ Joint Protocol regimes is already attracting much attention and thought, potentially enabling it to create, in time, the foundation for a common global nuclear liability regime. CONCLUSION Whilst significant steps have been achieved to date providing wider and more far-reaching protection from the risks of a nuclear incident,48 nuclear liability remains a fascinating and complex subject in commercial transactions.

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For example, the NEA of the OECD also strongly emphasised its objective ‘to contribute to the moderni[s]ation of the international nuclear liability regime and encourage the strengthening of treaty relations between interested countries to address liability and compensation for nuclear damage’: NEA, ‘The strategic plan of the NEA 2011–2016’, available at www.oecd-nea.org/nea/ Strategic-plan-2011-2016.pdf 43 The G20 Leaders’ Declaration, St Petersburg Summit, September 2013, para. 97, available at https://g20.org/wp-content/uploads/2014/12/Saint_Petersburg_Declaration_ENG.pdf 44 France and the USA have long been strong opponents on their recommended approaches, with France strongly championing the PC/Joint Protocol and the USA the CSC. However, in August 2013, both countries signed a Joint Statement on Civil Liability for Nuclear Damage to reconcile their differences and encourage other states to sign up to either the Paris or Vienna regime or the CSC. NEA/OECD Nuclear Law Bulletin 92 (2013), 207, available at www.oecd-nea.org/law/ nlb/nlb92.pdf 45 In November 2013, France and Russia signed the Franco-Russian Nuclear Power Declaration stating that both states ‘attach great importance to the development of a universal international regime on civil liability for nuclear damage aimed at fair compensation in case of nuclear damage and urge states that have not yet done so to accede to the relevant international legal instruments’. France ratified the Joint Protocol on 30 April 2014. See NEA/OECD, Nuclear Law Bulletin 92 (2013), 209, available at www.oecd-nea.org/law/nlb/nlb92.pdf 46 On 15 April 2015. 47 It is open to all countries that incorporate the basic principles of nuclear liability law into their domestic law and that adopt a common approach on compensation, the definition of nuclear damage and the jurisdiction for claims. 48 See also OECD/NEA, ‘Progress towards a global nuclear liability regime’, Nuclear Law Bulletin 93, 9, available at www.oecd-nea.org/law/nlb/nlb93.pdf

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At least in the short to medium term, the creation of a global regime in practice will continue to be through the strengthening and wider application of the existing instruments; increased ratification of the CSC; and developing the links, such as the Joint Protocol, between them rather than through ratification of one single instrument alone. However, for example, the Joint Protocol’s effectiveness in turn is also wholly dependent upon its ratification by more states and, more significantly, by VC states of the 1997 VC to mirror the principles of the 2004 Amending Protocols once in force. Any protection offered by any bridging mechanism aiming towards a global regime can only be as effective as the level of reciprocal protection that each nuclear state on both sides of the ‘bridge’ has implemented into its national laws.

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THE PRESENT STATUS OF NUCLEAR THIRD-PARTY LIABILITY AND NUCLEAR INSURANCE Stephen F. Ashley,1 William J. Nuttall2 and Raphael J. Heffron3

An important issue relating concerns of nuclear safety to the power of national governments lies in the area of liability and nuclear insurance. 1

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Stephen F. Ashley is a Research Associate in the Department of Engineering and Innovation at the Open University. He received his BSc in Physics from Staffordshire University in 2003 and his PhD in Nuclear Structure Physics from the University of Surrey in 2007. Following a switch to nuclear-energy related research in 2011, his most recent research position was funded as part of the EPSRC (UK) funded project entitled NREFS (see n. 1 above). This project is part of the RCUK-India civil nuclear collaboration and his research has centred on looking at the role of nuclear insurance and law following the events at Fukushima Daiichi. This chapter was written from research undertaken as part of the RCUK-India civil nuclear collaboration project entitled ‘Management of Nuclear Risk Issues: Environmental, Financial and Safety (NREFS)’. Correspondingly, the authors would like to acknowledge financial support from the Engineering and Physical Sciences Research Council (UK) under grant no. EP/K007580/1. William J. Nuttall is a Professor of Energy in the Engineering and Innovation at the Open University. Following a first class degree in Physics from the University of East Anglia in 1987 he won a Fulbright Postgraduate Student Award to the Massachusetts Institute of Technology to study for a PhD in Physics. On returning to the UK in 1993 he worked as a scientist at Keele and Birmingham universities and then for the Institute of Physics in science policy. He joined the teaching faculty of Cambridge University in 2002. In Cambridge he taught Technology Policy and held a shared post between Judge Business School and Cambridge University Engineering Department. He is author of Nuclear Renaissance Technologies and Policies for the Future of Nuclear Power (Taylor and Francis, 2005), co-editor of several other books and an author of more than fifty journal articles. In 2011 Professor Nuttall was elected Fellow of the Institute of Physics. He is also a Fellow of Hughes Hall Cambridge. Raphael Heffron is a Senior Lecturer in Energy and Natural Resources Law at Queen Mary University of London. Raphael is a trained Barrister-at-Law and was called to the Bar in July 2007 in the Republic of Ireland. He read for his PhD at Trinity Hall, University of Cambridge. His research interests are in energy law and policy, and in particular electricity markets, energy subsidies, low-carbon energy, energy justice and Arctic energy law. Of importance is the aim to understand the legal challenges involved in planning for new energy infrastructure projects.

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Internationally, liability regimes for civil nuclear facilities are generally covered through conventions. The purpose of such conventions, when originally formulated, involved protecting the operator against the risk of potentially uninsurable third-party liabilities. The two most prominent third-party conventions across the world are (1) the 1960 ‘Paris Convention’4 devised by the Organization for Economic Co-operation and Development (OECD) that is typically in force in those countries and (2) the 1963 ‘Vienna Convention’5 devised by the International Atomic Energy Agency (IAEA) that is in force mainly in nonOECD countries. Since the early 1960s, both conventions have undergone revisions6 although various countries are yet to ratify these most recent revisions. Furthermore, supplementary conventions have also been developed, most notably the 1992 ‘Joint Protocol’ that provides linkages between the Paris and Vienna conventions, which is useful in the instance of transboundary cases.7 At the heart of third-party liability regimes is the notion of strict liability (that is, the victim does not need to prove fault or negligence against the operator) and exclusive liability (that is, all claims are legally channelled to the operator). Exclusive liability means that the operator is responsible for all third-party losses arising from nuclear activities on their licensed site, even if the fault is traced to an external supplier. Hence the operator is incentivised to ensure high standards throughout the supply chain. Strict and exclusive liability is a cost burden placed upon nuclear power plant operators, requiring mandatory financial coverage through insurance. In contrast, other industrial systems operators, including those in the energy sector, are generally governed by tort law. It is noted that certain exemptions apply in these conventions, namely damages that arise from Acts of War. Acts of God are typically not exempt. Another aspect of these conventions is that the liability may be limited both financially and temporally. Third-party losses above that threshold are 4

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Organization for Economic Co-operation and Development, Convention on Third Party Liability in the Field of Nuclear Energy of 29th July 1960, as Amended by the Additional Protocol of 28th January 1964 and by the Protocol of 16th November 1982, 1982, available at http://www.oecdnea.org/law/nlparis_conv.html International Atomic Energy Agency, Vienna Convention on Civil Liability for Nuclear Damage (1963), available at www.iaea.org/Publications/Documents/Infcircs/1996/inf500.shtml Organization for Economic Co-operation and Development, Protocol – To Amend the Convention on Third Party Liability in the Field of Nuclear Energy of 29 July 1960, as Amended by the Additional Protocol of 28 January 1964 and by the Protocol of 16 November 1982 Paris Convention on Nuclear Third Party Liability – Latest Status of Ratifications or Accessions Protocol to Amend the Convention of 31 January 1963 Supplementary to the Paris Convention of 29 July 1960 on Third Party Liability in the Field of Nuclear Energy, as Amended by the Additional Protocol of 28 January 1964 and by the Protocol of 16 November 1982 (2004), available at www. oecd-nea.org/law/brussels_supplementary_convention.pdf; International Atomic Energy Agency, Protocol to Amend the Vienna Convention on Civil Liability for Nuclear Damage (1998), available at www.iaea.org/Publications/Documents/Infcircs/1998/infcirc566.pdf International Atomic Energy Agency, Joint Protocol Relating to the Application of the Vienna Convention and the Paris Convention (1992), available at www.iaea.org/sites/default/files/ publications/documents/infcircs/1992/infcirc0402.pdf

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not covered by the industry or their private insurers, but rather are covered directly by government. There is sometimes said to be a quid-pro-quo in that the nuclear industry receives a special benefit to offset its greater obligations; namely that the operator is shielded from large-scale risk by a limit to its third-party liability.8 For instance, in 2014, TEPCO’s forecast for compensation from the accident at Fukushima Daiichi in 2011 stood at €35.7 billion.9 In the case of Japan, the operator (with few exceptions) has unlimited liability; although with the instance of Fukushima Daiichi, assistance from the government was required. The United Kingdom manages nuclear liabilities according to the 1960 Paris Convention and 1963 Brussels Supplementary Convention, which is legislated in the Nuclear Installations Act 1965.10 Presently the United Kingdom is undergoing a process to ratify the 2004 Revised Paris Convention and Revised Brussels Supplementary Convention by amending the Nuclear Installations Act 1965 through secondary legislation made under Section 76 of the Energy Act 2004.11 This would raise the liability cap in the UK from £140 million to £1.2 billion. It would also affect the heads of damage (that is, the definitions of loss) that may be compensated, and may affect the priority and mechanism in which different heads of damage are subsequently handled. Prior to 2015, the majority of nuclear power plants operating in the world were not covered by international conventions but instead by national legislation. Third-party liability is covered in the United States by the 1957 PriceAnderson Act.12 In Japan, third-party liability is covered by the 1961 Act on Compensation for Nuclear Damage and the 1961 Act on Indemnity Agreements for Compensation of Nuclear Damage.13 India covers its third-party liability under the Civil Liability for Nuclear Damage Act, 2010.14 8

M. G. Faure and K. Fiore, ‘An economic analysis of the nuclear liability subsidy’, Pace Environmental Law Review 26(2) (2009), 419, available at http://heinonline.org/HOL/Page?handle=hein. journals/penv26&id=423&div=&collection= 9 TEPCO, New Comprehensive Special Business Plan (15 January 2014), available at www.tepco. co.jp/en/press/corp-com/release/betu14_e/images/140115e0206.pdf 10 HM Government, Nuclear Installations Act 1965 (1965), available at http://www.legislation. gov.uk/ukpga/1965/57/pdfs/ukpga_19650057_en.pdf 11 HM Government, Implementation of Changes to the Paris and Brussels Conventions on Nuclear Third Party Liability, March 2012, available at www.gov.uk/government/uploads/system/uploads/ attachment_data/file/42757/4874-parisbrussels-government-response-to-consultation.pdf 12 US Government Printing Office, Price-Anderson Act, 1957, available at www.gpo.gov/fdsys/ pkg/STATUTE-71/pdf/STATUTE-71-Pg576.pdf; Ian Hore-Lacy and World Nuclear Association, ‘Price-Anderson Act of 1957, United States’, The Encyclopedia of Earth (7 December 2009), available at www.eoearth.org/view/article/155347 13 As detailed in Organization for Economic Co-operation and Development, Japan’s Compensation for Nuclear Damage – As Related to the TEPCO Fukushima Daiichi Nuclear Accident (2012), available at www.oecd-nea.org/law/fukushima/7089-fukushima-compensation-system-pp.pdf 14 Ministry of Law and Justice, The Civil Liability for Nuclear Damage Act, 2010 (2010), available at http://lawmin.nic.in/ld/regionallanguages/THE%20CIVIL%20LIABILITY%20OF%20 NUCLEAR%20DAMAGE%20ACT,2010.%20(38%20OF2010).pdf

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Whilst the United States’ and Japan’s conventions are generally in line with international conventions, India’s third-party liability convention does not impose exclusive liability. Such provisions have proven to be a major obstacle for the international community to invest in nuclear projects in India. Component manufacturers need assurance that the operator subsumes third-party nuclear liabilities via the provisions of exclusive liability. Otherwise, it may be impossible for these companies to obtain the necessary financial security. One convention that aims at being a global nuclear liability regime is the 1997 Convention on Supplementary Compensation for Nuclear Damage (CSC), which has been signed by nineteen countries (including the USA, Japan and India), ratified by six countries (including the USA and Japan), and was brought into force on 15 April 2015.15 The CSC, under the auspices of the IAEA, is a free-standing instrument that aims to overarch both Paris and Vienna Conventions. However, the requirement of exclusive liability in Annex 1 of the CSC is at odds with India’s Act on nuclear liability.16 Since the March 2011 accident at the Fukushima Daiichi plant in Japan, the European Union has been concerned with inconsistencies relating to third-party liability conventions between member states. Most notably the issues surround claims management (especially in instances where claims are trans-boundary); EU member states that are not members of any third-party nuclear liability conventions (as of 2015, there are five); and the variation in the amount of financial security required across all member states that are party to the Paris or Vienna Convention, ranging from €5.6 million for Italy to €2.5 billion for Germany. As part of the conventions, financial security is required and generally provided through insurance. A special event-limited catastrophe cover has been suggested that would prospectively offer $20 billion upwards, with a premium costing tenths of a cent per kilowatt hour.17 Such cover may satisfactorily bridge the gap between present liability limits and the total costs of large nuclear accidents. Whilst nuclear third-party liability conventions were designed to offer uniformity, the range of conventions in force today is far from uniform. How this patchwork arrangement can (and should) be made consistent is very much a live policy issue, especially in Europe. With India’s disregard to exclusive liability, vendors of nuclear technologies may face significant difficulties in exporting technologies. In the light of this, it will be interesting to see how new-entrant 15

IAEA, ‘Convention on supplementary compensation for nuclear damage (latest status)’, available at www.iaea.org/Publications/Documents/Conventions/supcomp_status.pdf. NB A seventh country, Montenegro, has adopted the CSC and brought it into force on 16 July 2015. 16 A. Sengupta and S. Ambast, ‘A dangerous recourse? A critical relook at Sec. 17 of the Civil Liability for Nuclear Damage Act, 2010’, International Journal of Nuclear Law 3(4) (January, 2012), 292–307. 17 M. Tetley, ‘Nuclear insurance: yesterday, today, tomorrow’, in Nuclear Inter Jura Congress (INLA, 2014), available at www.aidn-inla.org.ar/wp-content/uploads/2014/10/59-M-TETLEYNuclear-Insurance-yesterday-today-tomorrow.docx

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nuclear countries will develop and/or adopt such conventions, especially in Asia. All in all, the future of third-party nuclear liability may end up not being based on global ideals but on regional cooperation backed up by robust and available insurance. One question that the nuclear industry has to ascertain is whether the lack of a global third-party nuclear-liability regime will, in both the short term and the long term, inhibit the growth of the nuclear industry? In comparison to other energy sectors, such as oil and gas, third-party nuclear-liability regimes are well developed. It remains to be seen how the lessons learnt in developing nuclear-liability regimes can be successfully applied to form robust, comprehensive and fair third-party liability regimes for all parts of the energy sector.

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SMALL MODULAR REACTORS: THE FUTURE OR THE SWANSONG OF THE NUCLEAR INDUSTRY? Giorgio Locatelli1 and Tristano Sainati2

INTRODUCTION Small modular reactors (SMRs) are nuclear reactors with electric power output of less than 300 MWe. Several SMR designs are currently at different stages of development around the globe as detailed by the International Atomic Energy Agency (IAEA).3 This chapter focuses on Light Water SMR for deployment in the next decade, but some insights are applicable also to GENIV designs, available in the medium to long term.4 SMRs are designed for simplicity, enhanced safety and modularity, but they are historically not considered as economically competitive with large 1

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Dr Giorgio Locatelli is a Lecturer in the School of Civil Engineering at the University of Leeds. He has a Bachelor’s and a Masters degree in Mechanical Engineering and a PhD in Industrial Engineering, Economics And Management from Politecnico di Milano. His main research topic is infrastructural megaprojects, particularly in the energy sector with a focus on the nuclear industry. He is the author of more than eighty international publications, mostly focused on energy megaprojects. He also works as a consultant and visiting academic for several institutions including the International Atomic Energy Agency. Tristano Sainati is a PhD student and Assistant Lecturer of Industrial Engineering at the University of Lincoln. He has a Bachelor’s and Masters degree in Engineering from Politecnico di Milano. He has some years of experience as a researcher both at the University of Lincoln and at Politecnico di Milano. IAEA, ‘Advances in small modular reactor technology developments. A supplement to IAEA Advanced Reactors Information System (ARIS)’ (2014), available at www.iaea.org/NuclearPower/Downloadable/SMR/files/IAEA_SMR_Booklet_2014.pdf G. Locatelli, M. Mancini and N. Todeschini, ‘Generation IV nuclear reactors: current status and future prospects’, Energy Policy 61 1503–20.

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reactors (LRs) because of a misguided application of the economy-of-scale principle.5 According to this, the unitary capital cost of a nuclear reactor decreases with increasing size. This is due to the unitary reduction of unique set-up costs in investment activities, the more efficient use of raw materials and the exploitation of higher performances which are a characteristic of larger equipment. However, the economy of scale applies if and only if the comparison is one LR versus one small reactor of a similar design, as has largely been the case in the past. This is no longer true today where SMRs have very different designs and characteristics from their large-scale counterparts.6 SMRs are designed to be factory manufactured, transportable and suitable for the production of heat, desalinated water and other by-products that industrial sectors require. In SMR the term ‘modular’ refers to a single reactor that can be grouped with others to form a large nuclear plant and whose design incorporates mainly pre-fabricated modules assembled on site. Whilst current LRs also incorporate factory-fabricated components or modules, a substantial amount of fieldwork is required to assemble components into an operational plant. Regarding economics, Hayns and Shepherd7 investigated the whole lifecycle of SMRs and presented a bottom-up cost estimation model for a 300–400 MWe pressurised water reactor, finding a competitive economic merit. Shropshire8 focuses on scenarios in line with EU expectations, with an indication that the actual competitiveness of SMRs for these markets is yet to be fully demonstrated, but that they show potential to achieve competitive costs in other electricity market areas. Boarin9 shows that a ‘modular’ investment project in multiple SMRs may be able to offset most of the loss of economies of scale. In this context, in the range of uncertainty that affects the model’s inputs, LRs and SMRs record a substantially comparable cost-effectiveness. The possibility of staggering the units’ deployment over time makes SMRs an affordable option for investors with limited financing capabilities and a chance to contain the average capital exposure. The LRs, as their counterparts, give a better economic performance where market conditions are less volatile and where overnight capital costs have higher incidence on total capital costs, including financing costs.

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D. T. Ingersoll, ‘Deliberately small reactors and the second nuclear era’, Progress in Nuclear Energy 51 (2009), 589–603; M. D. Carelli, P. Garrone, G. Locatelli, M. Mancini, C. Mycoff, P. Trucco and M. E. Ricotti, ‘Progress in nuclear energy economic features of integral, modular, small-to-medium size reactors’, Progress in Nuclear Energy 52(4) (2010), 403–14. G. Locatelli, C. Bingham and M. Mancini, ‘Small modular reactors: a comprehensive overview of their economics and strategic aspects’, Progress in Nuclear Energy 73 (2014), 75–85. M. R. Hayns and J. Shepherd, ‘SIR – reducing size can reduce cost’, Nuclear Energy 30 (1991), 85. D. Shropshire, ‘Economic viability of small to medium-sized reactors deployed in future European energy markets’, Progress in Nuclear Energy 53(4) (2011), 299–307. S. Boarin, G. Locatelli, M. Mancini and M. E. Ricotti, ‘Financial case studies on small- and medium-size modular reactors’, Nuclear Technology 178 (2012), 218–32.

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NON-FINANCIAL PERSPECTIVE: IMPACT ON ECONOMY, SOCIETY AND ENVIRONMENT The former US Secretary of Energy Dr Steven Chu has highlighted the importance of SMRs for the USA: If we can develop this technology in the U.S. and build these reactors with American workers, we will have a key competitive edge . . . Their small size makes them suitable to small electric grids so they are a good option for locations that cannot accommodate large-scale plants. The modular construction process would make them more affordable by reducing capital costs and construction times. Their size would also increase flexibility for utilities since they could add units as demand changes, or use them for on-site replacement of aging fossil fuel plants. Some of the designs for SMR use little or no water for cooling, which would reduce their environmental impact.10 As is clear from this quotation, the nature of energy policy planning requires enlarging the range of parameters influencing strategic decisions, moving from technical, economic and financial, to social, environmental and political. Locatelli11 provides a list of these non-financial factors (impact on industrial system, spinning reserve management, design robustness and so on), and guidelines and algorithms for their quantification and integration to support the identification of a long-term investment decision. Results show that SMRs are a promising alternative to improve a country’s sustainability and energy independence, even when the adverse impact of nuclear options has been accommodated. SMRs are interesting also for the integration of other facilities for cogeneration purposes. A key advantage of SMRs is the intrinsic modularity (here intended as fractionated power) of an SMR site. In particular, it is possible to operate all the primary circuits of the SMR fleet at full capacity and switch the whole thermal power of some of them (or use the electricity produced) for the cogeneration of suitable by-products. This is a remarkable advantage compared to LRs that need to fraction the steam leading to ‘off-design operations’ and inefficiencies. Locatelli12 provides an account demonstrating the feasibility, for certain scenarios, of coupling SMRs with a desalination plant. In the short term, another interesting application is district heating, where the extracted steam from high- and/or low-pressure turbines is fed to heat exchangers in order to produce hot water or steam, which is delivered to the consumer. 10

S. Chu, ‘America’s new nuclear option’, The Wall Street Journal (23 March 2010), available at www.wsj.com/news/articles/SB10001424052748704231304575092130239999278 11 G. Locatelli and M. Mancini, ‘The role of the reactor size for an investment in the nuclear sector: an evaluation of not-financial parameters’, Progress in Nuclear Energy 53(2) (2011), 212–22. 12 G. Locatelli, S. Boarin, F. Pellegrino and M. E. Ricotti, ‘Load following with small modular reactors (SMR): a real options analysis’, Energy 80 (2015), 41–54.

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REGULATION The licensing process is a key issue for the deployment of SMRs. Sainati13 lists some key topics that should be considered while overviewing the challenge of licensing SMRs, outlined below. Regulatory harmonisation and international certification One of the key debates concerning licensing SMRs concerns regulatory harmonisation. In the nuclear industry, there are few major reactor vendors, contractors and nuclear manufacturer suppliers. However, the nuclear industry operates internationally (several countries are interested in SMRs), and licensing processes and nuclear regulations are country-specific.14 Consequently, reactor vendors cannot ‘produce a standard plant’ and simply ship/build identical units all over the world. A necessary precondition for the deployment of identical units in more than one country is the harmonisation of law and licensing processes. Despite the fact that most nuclear stakeholders would benefit from regulatory harmonisation, it is extremely difficult to make significant progress in this direction in the short to medium term because of the heterogeneity of the following:15 • legal systems and jurisprudence • institutional systems • licensing process structures and underlying principles. The fragmentation at country level of legal systems and jurisprudence, institutional systems and licensing process structures constrains SMR standardisation. Since each government has power over only its country, short-term harmonisation is unlikely. Duration and predictability of the licensing process The existing licensing processes that have been designed for LRs are characterised by long construction periods. LRs require various assessments that take time and are performed in parallel with their construction. SMRs are designed for a shorter construction; consequently the ‘parallel’ LR time could be longer than the SMR construction schedule time, preventing the expected time saving. Emergency Planning Zone The emergency planning zone (EPZ) is the area surrounding a nuclear facility where special regulatory requirements apply (for example, specific emergency 13

T. Sainati, G. Locatelli and N. Brookes, ‘Small modular reactors: licensing constraints and the way forward’, Energy 82 (2015), 1092–5. 14 M. Tronea, ‘European quest for standardisation of nuclear power reactors’, Progress in Nuclear Energy 52(2) (2010), 159–63. 15 International Atomic Energy Agency, ‘Governmental, legal and regulatory framework for safety’ (2010), available at www-pub.iaea.org/MTCD/publications/PDF/Pub1465_web.pdf

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preparedness procedures need to be available, the demographic density needs to be lower than a specific limit and so on). Each country prescribes the regulatory requirements associated with its own EPZ. The IAEA16 suggests an EPZ radius of between 5 and 25 km (for reactors having a power higher than 100 MW). Many vendors of SMRs advocate a smaller radius because of the improved safety concepts of SMRs (compared to LRs) and because of the limited radioactive material they store. However, from a legal point of view this is not yet an option. Manufacturing licence The manufacturing licence was introduced by the US Nuclear Regulatory Commission for certifying the processes of critical nuclear suppliers. It is not a substitute for the LP but rather speeds up the LP because the manufacturers are known and certified by the regulatory body. SMRs would benefit from this manufacturing licence. Nowadays, however, the idea of a ‘reactor certified in the factory’ and then shipped and operated in the field is not feasible. The reactor owner cannot avoid nuclear operator liability in any way and is ultimately and solely responsible for nuclear safety. The plant must still be certified in the site at the end of construction. Even if all the ‘mechanical components’ are certified in the factory, the LP applies to another unit of analysis: the system installed at the site. In other words, the LP relies on the nuclear power plant (NPP) in a specific site and not on its parts. Even if the components are certified, the LP requires the appraisal of the specific context, that is, the site, the NPP, the interaction between the operator and the NPP and so on. The need for a new legal and regulatory framework Another issue is the need for the development of specific laws, regulations and licensing processes for SMRs. This approach is already common for small nuclear research facilities. Three main challenges inhibit the adoption of a completely new legal and regulatory framework: • It requires a significant review of legal and regulatory frameworks. • It implies a complete rethink of licensing processes, which in turn implies a redefinition of the institutional framework. • It implies a reduction of licensing protections in institutional and democratic terms (such as exemption from public inquiry processes). This would be difficult to justify to citizens in many countries. CONCLUSIONS Modern SMRs are a relatively ‘new product’ in the nuclear industry since they are not a scaled-down version of more traditional LRs, but rather a new concept in nuclear power generation. SMRs exploit the ‘economy of multiples’ 16

International Atomic Energy Agency, ‘Method for developing arrangements for response to a nuclear or radiological emergency’ (2003), available at www-pub.iaea.org/books/IAEABooks/6750/ Method-for-Developing-Arrangements-for-Response-to-a-Nuclear-or-Radiological-Emergency

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rather than the ‘economy of scale’. However, modern SMRs have not yet been built, so investors and policy-makers face high uncertainty leading to a high investment risk. Nevertheless, the first movers would potentially have a huge advantage in this new market. Tailoring the licensing procedures for SMRs as part of a strong political commitment by a number of countries and at the same time is essential. Their political commitment would require a set of legal reforms, significantly modifying the architecture and principles governing licensing processes. This is unlikely to happen in the short term and represents one of the main obstacles preventing the widespread adoption of SMRs.

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COHERENT PROMOTION OF RENEWABLES UNDER A CARBON EMISSIONS CAP Philippe Thalmann1

The German energy transition, with its massive subsidisation of variable renewable electricity generation (wind, solar and so on) leading to its dramatic expansion, has spurred controversy proportional to its ambitions. This chapter focuses on just one critique addressed against it: that it is actually bad for the climate. This critique was levelled prominently by Professor Joachim Weimann of the Otto-von-Guericke University in Magdeburg and Professor Robert Stavins of Harvard University’s Kennedy School.2 They argue that promoting solar and wind electricity does not reduce any CO2 emissions because coal-fired plants forced to reduce their production would merely sell unused emissions allowances to some other emitter. The total level of emissions is always equal to the cap, whatever measure is taken to reduce abatement costs. Moreover, by depressing the price of emissions allowances, subsidising renewables actually forces other, cheaper mitigation technologies out of the market, which reduces important future mitigation options. It even helps the dirtiest generation technology, old lignite power plants. In the end, Weimann blames the German promotion of renewables for being the main if not only cause of the difficulties of the European Union Emission Trading Scheme (EU ETS). 1

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Philippe Thalmann obtained a diploma in Economics from the University of Lausanne in 1984 and a PhD in Economics from Harvard University in 1990. Since 1994, he has been Professor of Economics at the Swiss Federal Institute of Technology, Lausanne. He teaches and publishes on the economics of the housing, property and construction markets, and the economics of the environment, climate change and sustainable development. J. Weimann, ‘Der CO2-Emissionshandel im Zeitalter der Energiewende’, Orientierung zur Wirtschafts- und Gesellschaftspolitik 138 (2013), 39–45; R. N. Stavins, ‘The problem with EU renewables’, The Environmental Forum 31(3) (2014), 14.

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A part of the argument may seem paradoxical: if promoting renewables frees emissions allowances by taking electricity demand away from coal-fired plants, how could that lead coal-fired plants to produce more electricity? That is not possible as such, of course, but promoting renewables could still help coal-fired plants. Imagine a merit order curve that starts with coal-fired plants with gradually rising marginal generation costs, including the carbon price, until it reaches the level where gas-fired plants become the cheaper option. Promoting renewables with guaranteed market uptake leads to a leftward shift of the electricity demand for coal- and gas-fired plants. Gas-fired plants are forced first to reduce their production, which frees emissions allowances (and is bad for system stability as gas-fired power plants can ramp up production the fastest). Their price goes down, which helps coal-fired plants take away some production from the remaining gas-fired plants. In fact, the share of natural gas in the German electricity mix was about the same in 2014 as in the early 2000s, while the share of renewables grew from 6.6 per cent to 25.8 per cent.3 The increase in renewable energy production (+120 TWh) really accounted for the increased total generation (+34 TWh) and it replaced nuclear generation (−73 TWh). Total coal-based generation actually declined by 26 TWh. When renewables replace nuclear power, which is of course one of the purposes of their promotion in the context of a phasing-out of nuclear power, they have no impact whatsoever on the carbon price. Weimann and Stavins’ argument that promoting a particular abatement technology under an emissions cap is both inefficient and ineffective is quite convincing in a perfect world, a world where the central planner efficiently sets an overall cap for CO2 emissions and gradually lowers it as mitigation options are improved. A world where market actors anticipate smoothly rising carbon prices and invest in abatement technologies accordingly. A world where mitigation options compete on a level playing field. In such a world, one instrument – the EU ETS – is all that is needed for one goal: a smooth reduction path for CO2 emissions. In the real world, all these assumptions are invalidated. First, there is no central planner setting emission caps efficiently; instead there is a political system where shortterm industrial and employment interests weigh more heavily than the interests of future generations. As a result, the cap is set much higher than it would be by a forward-looking altruistic planner.4 The consequence is a low carbon price. A business cycle downturn, which reduces the demand for carbon-intensive goods, further depresses the carbon price when the cap is not adjusted, and of course it cannot be tightened when the economy is already struggling. All this leads to low and volatile carbon prices, which discourage emitters from investing in the research, development and deployment of long-term abatement options. There is too little investment in these options compared to the perfect world, which justifies compensatory support by the public sector. 3 4

See www.ag-energiebilanzen.de See also R. Pearse and S. Böhm, ‘Ten reasons why carbon markets will not bring about radical emissions reduction’, Carbon Management 5(4) (2015), 325–37.

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The support for renewables is even more warranted when carbon-intensive alternatives benefit from subsidies for other reasons (regional support for coal extraction and transportation, for instance). And it is more warranted when the technologies face a steep learning curve with spillover effects. The German promotion of variable renewables lowered the cost of these technologies and led to the spread of their diffusion outside the area too under the European emissions cap. This is possibly the most significant contribution of Germany to slowing down climate change. Finally, the political system that will set the next caps is likely to follow a more ambitious emissions reduction path now that more abatement options are available at lower costs. In short, promoting renewables was not necessarily inefficient in the real world and it was certainly not ineffective at a global level. There remains Weimann and Stavins’ argument that it was ineffective at the level of the area under the European emissions cap, at least as long as it does not lead to a change in the cap. In a perfect world, emissions will always reach the cap. In the real world of the EU ETS, the over-allocation of emissions allowances was so massive in the first two phases that the cap could not be reached. When the cap is not reached, any instrument that encourages abatement actually leads to a reduction in emissions. Now one could argue that the promotion of renewables in Germany led to such a decrease in the demand for certificates that it is really responsible for the over-allocation. At least it would have had an effect on CO2 emissions. That, however, would be giving too much credit to the expansion of renewables in Germany and Weimann does not make that argument. Still, it is true that promoting renewables contributes to the glut of emissions allowances. This shows that the promotion of renewable power is most effective when it is accompanied by the withdrawal of allowances. Of course, it is difficult to determine how many. To the extent that renewables replace nuclear power, no allowances are freed. When they replace thermal power plants, the quantity of CO2 emissions saved depends on the technology replaced. It need not be the most carbon-intensive technology, as shown earlier. Funding the withdrawal of allowances is a lesser issue when they are so abundant that they trade almost for free. In conclusion, the promotion of electricity generation from renewables cannot be rejected simply because it would be inefficient and ineffective in an ideal world with simple goals and perfect markets. There are many good arguments in favour of such a policy in the real world. Nevertheless, it should be designed carefully and it can be made more effective if the emissions allowances it liberates are taken out of the market.

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RENEWABLE ENERGY POLICIES CHANGE CARBON EMISSIONS EVEN UNDER EMISSIONS TRADING Johannes Jarke1 and Grischa Perino2

Electricity generation within the European Union and the United States is currently going through a massive transformation away from fossil fuel combustion towards renewable sources of energy. This process is spurred on by a set of public policies involving both quotas (or ‘portfolio standards’) and subsidies – the latter typically in the form of feed-in tariffs (FITs), which are essentially minimum prices or piece-rate subsidies for electricity produced from renewables.3 The first FIT schemes were introduced in the US by the Public Utility Regulatory Policies Act (PURPA), part of the 1978 National Energy Act (NEA), but the most prominent example is the German Renewable Energy Act (Erneuerbare-Energien-Gesetz, EEG). The EEG tariff across technologies reached 18 eurocents/kWh in 2013 while the average spot price of electricity was about 4 eurocents/kWh, resulting in a net subsidy of €20.36 billion.4 The 1

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Johannes Jarke is a postdoctoral researcher and lecturer at the University of Hamburg. He studied Economics at the universities of Heidelberg and Mannheim and received his honours PhD in 2013. He works in the field of applied micro- and experimental economics with a special interest in regulation and informal governance of commons and sharable assets. Grischa Perino is a Professor of Economics at the University of Hamburg and a Research Professor at the Hamburg Institute of International Economics (HWWI). He has previously taught at the universities of East Anglia and Cambridge and received his PhD in 2007 from the University of Heidelberg. His research interests are in the area of environmental regulation and innovation. Secretariat of the Renewable Energy Policy Network for the 21st Century, Renewable Energy Policy Network for the 21st Century, Renewables 2013 – Global Status Report (2013), available at www.ren21.net/Portals/0/documents/Resources/GSR/2014/GSR2014_full%20report_low%20 res.pdf Bundesministerium für Wirtschaft und Energie, EEG in Zahlen: Vergütungen, Differenzkosten und EEG-Umlage 2000 bis 2015 (Bundesministerium für Wirtschaft und Energie, 2014).

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EEG has been rated as the world’s most effective policy in accelerating the deployment of renewables,5 and many countries within and outside the EU have enacted similar policies. Abatement of carbon emissions in an effort to combat global warming is the dominant objective behind these public policies. The electricity sector is by far the largest carbon emitter, accounting for about two-fifths of total carbon emissions in the EU and the US,6 and is therefore a natural first-order target for climate policy. THE PROBLEM OF OVERLAPPING POLICIES Renewable energy promotion, however, is not the only regulatory programme applied to the electricity sector. Within the EU it is also subject to the EU Emissions Trading System (EU ETS), and in parts of the US to similar cap-and-trade schemes such as the California-Québec Agreement (the remainder of the Western Climate Initiative) and the Regional Greenhouse Gas Initiative (RGGI). Researchers and practitioners have argued that renewable energy policies have no effect on carbon emissions at all if the electricity sector is also regulated by such a cap-andtrade scheme (CAT) because, assuming that the cap is binding, emissions are fixed by the volume of permits.7 Additional instruments applied to the electricity sector merely reallocate emissions between sources and, by moving them away from where abatement is cheapest, raise total abatement costs. This has been used to argue against such policies, such as the FIT scheme in Germany, or the explicit targets for renewables in the EU complementing carbon abatement targets.8 Indeed, there is nothing wrong with this argument if the electricity sector is considered in isolation from the rest of the economy, but if economy-wide adjustments are taken into account the argument has been shown to be incomplete. AN ECONOMY-WIDE VIEW Within a parsimonious model of an economy (a so-called ‘general equilibrium model’) that explicitly considers the industries outside the CAT and their linkages to the electricity sector, we show that renewable energy policies indeed 5

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S. Jacobsson and V. Lauber, ‘The politics and policy of energy system transformation – explaining the German diffusion of renewable energy technology’, Energy Policy 34(3) (2006), 256–76; J. Lipp, ‘Lessons for effective renewable electricity policy from Denmark, Germany and the United Kingdom’, Energy Policy 35(11) (2007) 5481–95. US Energy Information Administration, Electric Power Annual 2012 (US Energy Information Administration, 2013); International Energy Agency, CO2 Emissions from Fuel Combustion – Highlights (International Energy Agency, 2014). C. Fischer and L. Preonas, ‘Combining policies for renewable energy: is the whole less than the sum of its parts?’, International Review of Environmental and Resource Economics 4(1) (2010), 51–92; M. Fowlie ‘Emissions trading, electricity restructing, and investment in pollution abatement’, American Economic Review 100(3) (2010), 837–69; L. H. Goulder, ‘Markets for pollution allowances: what are the (new) lessons?’, Journal of Economic Perspectives 27(1) (2013), 87–102; C. Böhringer, ‘Two decades of European climate policy: a critical appraisal’, Review of Environmental Economics and Policy 8(1) (2014), 1–17. C. Böhringer, A. Löschel, U. Moslener and T. E. Rutherford, ‘EU climate policy up to 2020: an economic impact assessment’, Energy Economics 31 (2009), 295–305.

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alter economy-wide carbon emissions even if the electricity sector is under a CAT.9 The basic intuition is simple: all existing CATs cover only a fraction of all carbon-emitting industries. For example, the EU ETS applies to electricity and some other major industries, and covers only about 45 per cent of total carbon emissions produced in the EU’s economy.10 For practical reasons significant carbon-emitting sectors such as transportation remain outside. However, it needs to be taken into account that in such settings renewable energy policies lead to changes of carbon emissions produced in industries outside the CAT, mediated by demand shifts on the factor markets (capital and labour) and the associated price adjustments. Specifically, raising the FIT generally reduces aggregate carbon emissions, but it is also the case that the funding mode of the subsidy is a critical moderator of this effect. INTER-INDUSTRY LEAKAGE First, consider a FIT that is funded from general government revenues (raised by taxation). Raising the FIT unambiguously reduces economy-wide emissions in this case. The total effect is a cumulative compound of three leakage effects: the main effect stems from the fact that the expanding renewable electricity sector bids away factors of production (labour, capital) from the industries outside the CAT. As a result the latter reduce output and hence emissions, all else being equal. This effect is overlaid by two second-order effects, which both follow from the adjustment of the permit price. In response to an increase of the FIT, the renewable electricity sector grows and bids away factors of production from the other sectors. Off equilibrium, that is, before prices adjust, this gives firms in those sectors an incentive to reduce output and correspondingly carbon emissions. But then the demand for permits declines below the cap, and so there will be an excess supply of permits. As a result, the permit price will fall and conventional electricity firms respond by substituting from other factors of production into carbon (that is, increasing their carbon intensity) until the permit market is cleared again. By arriving at the new equilibrium there will be no reduction of emissions in the industries under the cap, but a reduction of labour and capital input and output in conventional electricity production. Two adjustments follow from this. First, the electricity price falls, which incentivises consumers to substitute away from other goods into electricity. This adjustment tends to decrease output and emissions in the industries outside the cap. Second, factors of production laid off in the conventional electricity sector are absorbed to some extent by industries outside the cap, which tend to increase output and emissions correspondingly. It can be shown that the two indirect effects are smaller than the main effect and hence that total emissions decline in response to an increase in the expansion of the renewable energy sector.

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The results presented here are formally derived in: J. Jarke and G. Perino, ‘Do renewable energy policies reduce carbon emission? On caps and inter-industry leakage’, WiSo-HH Working Paper 21, University of Hamburg 2015. 10 European Commission, The EU Emissions Trading System (Publications Office of the European Union, 2013).

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LEVY FUNDING Things are somewhat different if the FIT is not funded by taxation but by a levy on electricity. This is the case, for example, in the UK, Germany (the EEG-Umlage) and Ireland. Under this funding mode electricity users have to pay a surcharge on every unit of electricity consumed. Thus, a raise of the FIT directly increases the end-user price through the surcharge and hence incentivises consumers to substitute away from electricity into other goods produced outside the CAT, which increases total carbon emissions. Because of this effect, a FIT overlapping a CAT always induces higher emissions if it is levy-funded than if it is tax-funded while keeping all other parameters fixed. A larger renewables sector requires a larger total subsidy payment which in turn leads to a larger price distortion. An increase in the distortion in electricity prices translates into a more pronounced substitution away from electricity and a larger increase in emissions outside the CAT compared to a tax-funded FIT. Hence, the larger the renewable electricity sector has already grown the bigger the impact of the funding mechanism on aggregate carbon emissions. Even more importantly, while a raise of the FIT always reduces emissions under tax funding, it can increase emissions under levy funding. While further empirical analysis is necessary, initial computational results and anecdotal evidence suggests that this might already be the case in Germany.11 Thus, if – as seems likely – the environmental performance of the FIT scheme is a policy objective, tax funding of the FIT is preferable because it avoids the levy-induced incentive to substitute into goods that are produced outside the CAT. FLANKING DEMAND-SIDE POLICIES In addition to regulation of the electricity-production side, many governments have further instruments in place targeting the electricity-consumption side. Here we consider two important cases. First, a number of governments have set explicit target quotas and respective subsidy schemes to support the diffusion of technologies that use electricity instead of fossil fuels as an input. Interesting examples with mounting practical importance are electrically powered vehicles or power-to-gas (P2G) and power-to-heat (P2H) technologies. Such policies not only reduce carbon emissions directly, but they reinforce the emission-reducing effect of a FIT. Furthermore, as a secondary effect, the FIT also renders the adoption of such technologies more attractive because the electricity price falls.12 Thus, there is a pronounced synergy between supporting ‘green’ electricity and expanding the use of electricity to replace fossil fuels outside the power sector.

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Johannes Jarke and Grischa Perino, ‘Do renewable energy policies reduce carbon emission?’, WiSo-HH Working Paper Series, Working Paper No. 13 (2015), available at www.wiso.unihamburg.de/fileadmin/einrichtungen/forschungslabor/WorkingPaper_21_Jarke_Perino.pdf 12 This is not necessarily true under levy funding, because the end-user price can increase in response to a raise of the FIT (if the levy increases more than the net electricity price declines and users of such technologies are not exempt from the levy).

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Second, many jurisdictions also have measures with the objective of improving the efficiency of final electricity consumption in place.13 Such policies reduce emissions independently of the FIT, because they create a direct incentive for consumers to substitute into electricity, and hence away from goods produced outside the CAT. CONCLUSION In this chapter we reviewed research that rejects the widely held tenet that renewable energy promotion policies have no effect on carbon emissions if the electricity sector is subject to a cap-and-trade scheme. Specifically, it shows that such policies generally do have a net impact on carbon emissions through interindustry leakage effects. The results also have ramifications for the empirical assessment of renewable energy policies. A current widely adopted approach is the ‘virtual emission reductions’ (VER) statistic, which is the counter-factual quantity of emissions that would have been generated if the additional amount of green electricity were supplied by conventional means.14 The inter-industry effects reviewed above show that the VER statistic is a biased estimate of actual emission reductions in response to a FIT raise. Thus, obtaining reliable estimates of the effects of renewable energy policies requires the identification of leakage effects throughout an economy, which is arguably more challenging than the calculation of VER. Furthermore, there might be considerable long-term effects of changing the energy mix in an economy. In the long run, the cap on sector-wide emissions imposed by a CAP is no longer exogenously given. Usually they are renegotiated every five to ten years, as is currently the case for Phase IV of the EU ETS. Deliberately changing the energy mix in the power sector affects baseline emissions, marginal abatement costs and the relative importance of vested interests and lobbying groups. Understanding these links between these issues is an important avenue to better understand the true effects of supporting renewable energy on total long-run greenhouse gas emissions in regions subject to a CAP.

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See, for example, the EU Energy Efficiency Directive (2012/27/EU) or the 2013 US Climate Action Plan. 14 C. Marcantonini and A. D. Ellerman, ‘The cost of abating CO2 emissions by renewable energy incentives in Germany’, EUI Working Paper 2013/05 (European University Institute, 2013). Umweltbundesamt, Emissionsbilanz erneuerbarer Energieträger: Bestimmung der vermiedenen Emissionen im Jahr 2012 (Umweltbundesamt, 2013).

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THE RENEWABLE TRAJECTORY: AVOIDING THE TEMPTATION OF CHEAP OIL Michael LaBelle1

A trajectory of renewable energy technologies (RET) muscling out carbon energy technologies (CET) is becoming ingrained in many countries. However, falling oil prices threaten to derail this trajectory, but only if short-term benefits overrule long-term gains. That said, because of significant investments by both the private and public sector, RET will continue to gain ground against traditional fossil fuel technologies. Government funding for energy research and deployment was historically influenced by the price of oil. The price of a barrel of oil halved between the summer of 2014 and the winter of 2015. This holds significant ramifications for overhauling our global energy system. The current era of low oil and gas prices differs from previous eras. Many countries are already substantially invested in RET. In the past twenty years, due to the tremendous deployment of RET, a self-perpetuating funding and project deployment process exists. The sustained growth of RET, despite low oil prices, is a fundamental shift in our global energy system.

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Michael LaBelle is an Assistant Professor at Central European University, CEU Business School and Department of Environmental Sciences and Policy. He teaches courses on Sustainability, Innovation and Energy Technologies. His research is centred on the interaction of government institutions and private companies and how they foster innovation in energy technologies and contribute to a low-carbon future. Professor LaBelle’s current research concentrates on the development of shale gas in Europe, smart energy technologies and how policies and regulations influence innovation in the energy sector. His previous work assessed the efforts of institutions in the European Union to encourage the use of new low- or zero- carbon technologies in the energy sector, including energy efficiency measures.

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Smartphones and access to energy unite the seven billion people of the world. In 2014, 1.4 billion people owned a smartphone, while another 1.4 billion people lacked access to electricity.2 Each of us is affected by energy prices, whether we use that energy for cooking, heating or recharging modern necessities. Global economic growth is boosted by a fall in oil prices. A 10 per cent fall in oil prices results in a 0.2 per cent growth in global gross domestic product (GDP).3 Price fluctuations of hydrocarbons – mainly oil and gas – reverberate down to every consumer in the world. The current oil glut owes its genesis to a variety of factors, from overproduction of oil by traditional producers and slow economic growth to technological advances in extracting more oil and gas from the earth. Oscillating funding for research development and deployment (RD&D) in energy technologies is linked to the cyclical price of oil. However, in the past fifteen to twenty years there has been an emphasis on deploying RET rather than just funding research. Governments now incentivise consumers, investors and even themselves to integrate new energy technologies into energy systems – even if these are not perfect. Laboratory solar cells of the 1970s saw a huge cash infusion corresponding with oil’s price spike.4 The result? They stayed in the laboratory. In the 1990s technology and policy both advanced. Policy incentives evolved to deploy solar PV systems, thereby fostering a significant sector growth. Governments and market actors are now equipped with a range of push–pull policies, like feed-in tariffs, tax breaks and RET quotas for power producer portfolios.5 Even international institutions like the World Bank and the European Bank for Reconstruction and Development (EBRD) play an active role in financing RET projects. Ultimately, scaling up technology goes together with improving access to financing and consumers (push–pull policies). This joint strategy results in less costly production and installation.6 Demonstrating this drop is the cost curve of solar PV: ‘The average price for a utility-scale PV 2

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H. Leonard, ‘There will soon be one smartphone for every five people in the world’, Business Insider (13 July 2013), available at www.businessinsider.com/15-billion-smartphones-in-theworld-22013-2; and Global Energy Assessment, ‘Global Energy Assessment: toward a sustainable future’ (2012), available at www.iiasa.ac.at/web/home/research/researchPrograms/Energy/GEASummary-web.pdf The Economist, ‘Winners and losers’, The Economist (25 October 2014), available at www. economist.com/news/international/21627642-america-and-its-friends-benefit-falling-oil-pricesits-most-strident-critics E. Moe, ‘Vested interests, energy efficiency and renewables in Japan’, Energy Policy 40(1) (2012), 260–73 R. Wüstenhagen and E. Menichetti, ‘Strategic choices for renewable energy investment: conceptual framework and opportunities for further research’, Energy Policy 40(1) (2012), 1–10. D. Cardwell, ‘Solar and wind energy start to win on price vs. conventional fuels’, The New York Times (23 November 2014), available at www.nytimes.com/2014/11/24/business/energy-environment /solar-and-wind-energy-start-to-win-on-price-vs-conventional-fuels.html; see K. Branker, M. J. M. Pathak and J. M. Pearce, ‘A review of solar photovoltaic levelized cost of electricity’, Renewable and Sustainable Energy Reviews 15(9) (December 2011), 4470–82.

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project dropped from about $0.21 per kilowatt-hour in 2010 to $0.11 per kilowatt-hour at the end of 2013.’7 Funding and deployment of the RET RD&D pipeline requires a range of actors and financial instruments. The end stage of a successful energy technology is the marketplace, where competition against other energy technologies results in a battle over price per kWh. Consumers choose technology for a variety of factors, but ultimate success is not determined by upfront cost. Rather, full commercialisation is reliant on crossing the Valley of Death. The ‘Valley of Death’ refers to stages where technologies may fail to develop further if financial assistance or market access is not provided.8 Navigating to full commercialisation requires funding at many stages from early R&D government grants for basic research, then building into demonstration projects (this kind of funding is known as push policies). Eventually a technology fills a market niche, then it may scale up gaining wider market access. In addition, consumers can be incentivised to buy – either by themselves or with government incentives (this is known as pull policies). Over the long term, funding sources shift from government grants, venture capital and private equity to a range of publicly available financing options.9 Government policies play an essential role in moving RET through this pipeline. Figure 51.1 demonstrates a basic flow of innovative technology taking the earth’s resources, converting them and ‘upgrading’ to a usable commodity facilitated by governments to reach a market.

Figure 51.1 Basic innovation process for energy 7

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Energy.gov, ‘U.S. utility-scale solar 60 percent towards cost-competition goal’, Energy.gov (12 February 2014), available at http://energy.gov/articles/us-utility-scale-solar-60-percent-towardscost-competition-goal M. J. Burer and R. Wüstenhagen, ‘Which renewable energy policy is a venture capitalist’s best friend? Empirical evidence from a survey of international cleantech investors’, Energy Policy 37(12) (2009), 4997–5006. Ibid., 4998.

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Historic state funding of energy technologies differs greatly between countries. The US government is a strong supporter of fossil fuel RD&D. Between 1948 and 2014, the US Department of Energy funded $49.3 billion into fossil fuels RD&D projects, compared to $22.96 for renewable energy. However, in the ten-year period 2005–14, fossil energy received $10 billion with RET receiving $7.87 billion.10 More broadly, for member countries in the International Energy Agency (IEA), RD&D funds for CETs between 1974 and 2010 were consistently higher than RETs. A pattern is clear: fluctuations in renewable energy RD&D funding track the price curve of oil.11 Thus, the historical expectation is that funding for renewables will drop off due to low oil prices. However, we have hit a historic technological tipping point. The economic crisis beginning in 2008 resulted in governments spending more on energy research (both RET and CET), although the price of oil initially dropped. This funding burst was intended as an economic stimulus in developed and developing countries. Nonetheless, by 2013 funding had declined to almost 2008 levels in developed countries.12 In contrast to economically developed countries, developing countries distinguished themselves by maintaining higher levels of energy RD&D funding. In 2013, funding was on par with 2011, and well above 2008 levels – the height of developed countries stimulus funding.13 RET now represents a sustained investment area with clear economic and social benefits and governments are willing to support and encourage deployment. Recent turnover in global energy technology is pronounced in favour of RET: in 2004, renewable power capacity represented only 10 per cent of new global power capacity; by 2010, 34 per cent of new power capacity was RET.14 This RET policy shift is equivalent to the jump in RD&D funding during the 1979 OPEC oil embargo (and the solar cells are not trapped in laboratories!). Both periods represent global shifts in energy markets and national energy policies, away from oil and towards RET. Nonetheless, in 2010 RET only accounted for 5.4 per cent of global power generation. Importantly, following on from the 1970s oil crisis, countries changed their energy portfolios. Oil for power generation was removed, replaced by natural gas, coal and RET. In many developing countries, increasing levels of RET 10

F. Sissine, ‘Renewable energy R&D funding history: a comparison with funding for nuclear energy, fossil energy, and energy efficiency R&D’, Congressional Research Service (10 October 2014), 3, available at www.google.hu/url?sa=t&rct=j&q=&esrc=s&source=web&cd=4&ved =0CDIQFjAD&url=https%3A%2F%2Fwww.fas.org%2Fsgp%2Fcrs%2Fmisc%2FRS22858. pdf&ei=eX62VOSSMIr1Utz1g8AP&usg=AFQjCNE7rL6WPXBWmUENnSg97ZfDkKwHgA &sig2=47ChLMTZnZSNqt-sdejF5w&bvm=bv.83640239,d.d24&cad=rja 11 International Energy Agency, ‘Global gaps in clean energy RD&D: update and recommendations for international collaboration’ (2010), 157, available at www.iea.org/publications/freepublications/publication/global_gaps.pdf 12 Bloomberg, ‘Global trends in renewable energy investment 2014’, Frankfurt School-UNEP Centre/BNEF (2014), 16, available at www.unep.org/pdf/Green_energy_2013-Key_findings.pdf 13 Ibid., 16. 14 Global Energy Assessment, ‘Global Energy Assessment: Toward a Sustainable Future,’ 16.

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allow a break from oil price swings. In many countries oil and its products are subsidised by governments. This drains central funds, with no differentiation based on the ability to pay. Distributed local RET systems differentiate and can replace traditional kerosene lighting and diesel generators.15 The 2014 Nobel Prize in Physics was won by Japanese scientists who invented the technology for the LED blue light spectrum, enabling white LED light to become low cost and widespread.16 Small solar cells can now power LED lights. LEDs also draw less electricity from centralised systems. LEDs teamed with solar PV provide a lower-cost option and superior performance over traditional oil-based energy sources. The award was explicitly given because of the impact in developing countries. Successful energy technologies scale in size while costs per unit decrease as more RET are manufactured and deployed. Just as there is a learning curve in producing new technologies, society and policy-makers go through their own learning curve involving discovery, acceptance and promotion of new technologies. The innovation pipeline emerges into a commercial marketplace, where technologies begin in niche markets then take decades to scale up.17 Accelerating this evolutionary process takes government support and commitment even when oil prices slide. Full commercialisation of RET is dependent on local conditions. Each country needs to choose and build its own energy system. Social acceptance, political support and industry backing (including financing) are necessary. RET are distributed in forests, fields and oceans. Research in the 1970s has given way to increasing deployment since the 1990s. It is now up to policy-makers and society to accelerate this trajectory and increase RET in our energy mix. The declining cost of fossil fuels will test this commitment. We can consciously choose a sustainable energy system over an unsustainable system.

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S. Pachauri, D. Urge-Vorsatz and M. LaBelle, ‘Synergies between energy efficiency and energy access policies and strategies’, Global Policy 3(2) (2012), 187–97; B. Sills, N. Obiko Pearson and S. Nicola, ‘Farmers foil utilities using cell phones to access solar’, Bloomberg (11 March 2012), available at www.bloomberg.com/news/2012-04-11/farmers-foil-utilities-using-cell-phones-toaccess-solar.html 16 G. Naik, ‘Nobel Prize in Physics awarded for invention of new light source’, Wall Street Journal (7 October 2014), available at http://online.wsj.com/articles/nobel-prize-in-physics-awarded-forinvention-of-new-light-source-1412677155 17 H. Unger, ‘Innovation and market entry in the energy industry: lessons for fuel cells and new technologies’, Journal of Business and Economics Research 8(10) (2010), 63–71; A. Smith and R. Raven, ‘What is protective space? Reconsidering niches in transitions to sustainability’, Research Policy 41(6) (2012), Special section on sustainability transitions, 1025–36.

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IMPACT OF RENEWABLE PORTFOLIO STANDARDS ON IN-STATE RENEWABLE DEPLOYMENT IN THE US Gireesh Shrimali1

INTRODUCTION Policy-makers in the United States have sought to stimulate renewable energy (RES-E) deployment to improve ambient air quality by reducing pollutants from fossil fuel combustion, to reduce emissions of greenhouse gases which contribute to climate change, and to stimulate job growth and industrial productivity.2 While the cost of electricity generation from many renewable energy sources has been declining, renewable energy technologies are not currently competitive with other technologies for electricity generation in many markets, and therefore renewable energy deployment often depends on government intervention.3 In the United States, there are many federal-level policies in support of renewable energy, such as the production and investment tax credit. However, there is a lack of coordinated and comprehensive action by the federal government, as evidenced by the absence of a nationwide cap-and-trade programme or a clean energy standard. On the other hand, many state and local governments have taken initiatives to increase renewable energy capacity and generation,4 with most of the fifty states enacting some form of policy to encourage the use 1

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3

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Dr Gireesh Shrimali is a Faculty Fellow at Stanford University, United States. This chapter is based on a Working Paper: Gireesh Shrimali, Steffen Jenner, Felix Groba, Gabriel Chan and Joe Indvik (2012), ‘Have renewable portfolio standards really worked?’, available at http://papers. ssrn.com/sol3/papers.cfm?abstract_id=2166815 R. Schmalensee, ‘Evaluating policies to increase the generation of electricity from renewable energy’, M.I.T. Center for Energy and Environmental Policy Research Working Paper 2011-008 (2011). R. Green and A. Yatchew, ‘support schemes for renewable energy: an economic analysis’, Economics of Energy and Environmental Policy 1(2) (2012), 83–98. K. H. Engel and B. Y. Orbach, ‘Micro-motives for state and local climate change initiatives’, Harvard Law and Policy Review 2 (2008), 119–37.

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of renewable energy in their state.5 State-level initiatives are wide-ranging and include renewable energy incentives, integrated resource planning programmes and cap-and-trade programmes.6 Renewable portfolio standards (RPS) are a type of quantity regulation that mandate energy suppliers to ensure that a certain fraction of their total electricity sales is from electricity generated from renewable energy sources. Energy suppliers can meet their quota by producing renewable energy, buying renewable energy credits from other suppliers or paying a penalty. According to the Database of State Incentives for Renewables and Efficiency,7 twenty-one states and the District of Columbia have a mandatory RPS programme. Ten other states have legislated RPS schemes with effective start dates in the future. States use other policies as well. Sixteen states have used public benefit funds to support renewable energy programmes. In most states, these programmes raise revenue by charging consumers an additional fee on their electricity bill to fund, among other energy programmes, renewable energy investments. Seven states have required a green power option, which requires energy suppliers to provide consumers the option to buy electricity from renewable energy sources. In fortytwo states, net metering mechanisms have been adopted, allowing households that generate their own electricity to only pay for the difference between their own generation and their own consumption – even if generation and consumption do not occur at the same moment. Net metering typically favours small and distributed RES-E generation. Though states use multiple policies, renewable portfolio standards are considered a flagship renewable energy policy tool. As a result of decentralised policy-making, the individual state policies as well as renewable power deployment show a great deal of heterogeneity. While a number of factors might explain both the growth of renewable energy and the disparity in renewable capacity among states, policies adopted by state governments, including changes in the regulatory environment for electricity, are expected to play an important role. Given the length of time over which state RPSs have been in place, ex-post analysis of the effectiveness of RPSs in achieving their stated goal of increasing RES-E penetration is possible. Much work has been done to assess the effectiveness of RPS policies in increasing renewable deployment. However, results are contradictory, and vary from showing the impact of RPS policies on renewable deployment as positively significant8 to insignificant9 to negatively significant.10 Thus, there is a 5

DSIRE, ‘DSIRE RPS data spreadsheet’ (January 2012), available at www.dsireusa.org A. Wasserman, ‘WRI Fact Sheet: U.S. Climate Action in 2009–2010’, World Resource Institute Fact Sheet (January 2010), available at http://pdf.wri.org/factsheets/factsheet_us_climate_action_ in_2009-2010.pdf 7 DSIRE, ‘DSIRE RPS data spreadsheet’. 8 F. C. Menz and S. Vachon, ‘The effectiveness of different policy regimes for promoting wind power: experiences from the States’, Energy Policy 34(14) (2006), 1786–96. 9 S. Carley, ‘State renewable energy electricity policies: an empirical evaluation of effectiveness’, Energy Policy 38(8) (2009), 3071–81. 10 G. Shrimali and J. Kneifel (2011), ‘Are government policies effective in promoting deployment of renewable electricity resources?’, Energy Policy 39(9): 4726–4741. 6

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strong need to explain why these contradictory results exist and investigate as to what is the robust impact of RPS policies on renewable deployment. We explain and reconcile the differences in the results presented in the literature by examining differences in datasets, analytical techniques and the time period over which the impact of policies is examined. RESULTS We used a panel – fifty states over 1990–2010 – of renewable deployment and market dynamics to capture the heterogeneity in state RPS design and state characteristics. We ran time-series cross-sectional regressions with fixed effects. We found that most of the differences in results may be due to the previous literature using fundamentally different datasets. In particular, we found that the robust positive impact of RPS policies found by Yin and Powers11 was likely driven by irreconcilable discrepancies in the EIA’s generator-level dataset due to a change in classification methodology in the late 1990s. Furthermore, the estimation was most likely biased because non-utilities were only represented after 2000, thus producing a big ‘jump’ in the dependent variable. After the inconsistencies in the data were corrected, we found that differences in econometric models could no longer explain differences in substantive policy conclusions. We uses a measure of RPS stringency that, by adjusting for existing capacity, captured the incentives of electricity-generating resources to add new RES-E capacity to their portfolio. We found that this measure was actually negatively correlated with renewable share. Given that RPS policies are one of the most popular policy tools to support RES-E development at the state level, this finding was surprising. Carley,12 Delmas and Montes-Sancho,13 Dong,14 and Shrimali and Kneifel15 also found negative effects of RPS policies on RES-E development. Only Menz and Vachon,16 who estimated an inappropriate econometric model, and Yin and Powers,17 who presumably used an incorrect dataset, found statistically significant positive effects. We observed that, to a large extent, the negative and significant relationship between indicators of RPS design and RES-E deployment was driven by a single outlier state, Maine. When we dropped Maine from our sample, we still observed a negative correlation between the RPS stringency measure and renewable share, but the link was no longer statistically significant, even at the 10 per 11

H. Yin and N. Powers, ‘Do state renewable portfolio standards promote in-state renewable generation?’ Energy Policy 38(2) (2010), 1140–9. 12 Carley, ‘State renewable energy electricity policies’. 13 M. A. Delmas and M. J. Montes-Sancho, ‘U.S. state policies for renewable energy: context and effectiveness’, Energy Policy 39(5) (2011), 2273–88. 14 C. G. Dong, ‘Feed-in tariff vs. renewable portfolio standard: An empirical test of their relative effectiveness in promoting wind capacity development’, Energy Policy 42(3) (2012), 476–85. 15 Shrimali and Kneifel, ‘Are government policies effective?’. 16 Menz and Vachon, ‘The effectiveness of different policy regimes’. 17 Yin and Powers, ‘Do state renewable portfolio standards promote in-state renewable generation?’.

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cent level. We also explained how the connection of Maine to the Maritimes and Northeast gas pipeline by the end of 1999 made it such a special case that it was worth excluding from the dataset. Most importantly, we found that a reasonable amount of the impact on renewable share attributed to the RPS stringency could actually be explained by other RPS policy features. In addition, the apparently negative and significant impact of RPS stringency on renewable share could actually become positive and significant when RPS features were included in addition to the removal of Maine. Though this result came with many caveats, it revealed that we may be getting closer to a ‘more complete’ analysis of the impact of RPS policies on renewable share. In this process, we observed that the presence of renewable energy certificate (REC) unbundling had a statistically significant and positive impact. In fact, this impact is about 2 to 3 per cent – in states with REC unbundling there is 2 to 3 per cent higher renewable share than in states with bundled REC trading, everything else held constant. Among other notable impacts, we observed that there was typically more renewable development in a state if more of the neighbours had implemented RPS. However, the presence of alternative compliance payment results in less RES-E deployment – a counterintuitive finding, given that the presence of penalties should theoretically result in higher deployment. Finally, we found that the presence on restrictions on where the underlying electricity can be delivered from reduced renewable deployment. In addition to RPS, we examined the impact of other major renewable policies. Similar to Menz and Vachon18 and Yin and Powers,19 we found that the public benefit funds did not have a statistically significant impact. Further, similar to Delmas and Montes-Sancho,20 Menz and Vachon,21 Shrimali and Kneifel,22 and Yin and Powers,23 we found that mandatory green power options had an economically and statistically significant and positive impact – the presence of a mandatory green power option increased renewable deployment by about 4 per cent. However, we also observed that the impact of this policy was reduced when it was present along with the RPS. Finally, we found that net metering policies had a significant and negative impact on renewable deployment, another counterintuitive finding in the first place. However, net metering schemes are mostly capped at levels of 10 to 250 kW and/or at around 1 per cent of peak – a level not captured by the EIA data that requires a 1 MW minimum in plant size. It could thus be that net metering schemes work effectively but the increase that can be attributed to this policy is just too small to alter the overall distribution of the renewable share.

18

Menz and Vachon, ‘The effectiveness of different policy regimes’. Yin and Powers, ‘Do state renewable portfolio standards promote in-state renewable generation?’. 20 M. A. Delmas and M. J. Montes-Sancho, ‘U.S. state policies for renewable energy’. 21 Menz and Vachon, ‘The effectiveness of different policy regimes’. 22 Shrimali and Kneifel, ‘Are government policies effective?’. 23 Yin and Powers, ‘Do state renewable portfolio standards promote in-state renewable generation?’. 19

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We also examined the impact of RPS (and other policies) on technologyspecific renewable deployment. We showed that the supposedly negative impact of RPS stringency is primarily driven by an equivalent result for biomass, again driven by the outlier state, Maine. Once Maine was removed from the sample, the RPS stringency parameter became insignificant. In fact, the same result was repeated for wind and solar, indicating that RPS had had no impact that we could statistically discern on most renewable technologies. Examining the results for other policies, we observed that public benefit funds actually had a statistically significant positive impact on biomass deployment, indicating that this policy may primarily support biomass. Finally, the results for mandatory green option and net metering were primarily driven by the corresponding results for wind, indicating that these policies had primarily impacted wind. Finally, we corroborated our regression results with a matching analysis24 that also found economically significant decreases in renewable deployment in states that enacted an RPS relative to similar ‘synthetic’ states that do not adopt an RPS. Over time, we estimated that the divergence between states that did enact an RPS and those that did not was growing, with RPS states falling further behind in terms of RES-E deployment. We could interpret this as providing evidence that states that are similar to states that do enact an RPS are still finding ways to deploy renewables through means other than an RPS. Interpreting these results causally, over this time period, renewables are being deployed in states with and without RPS’s, but on average, states that do not use an RPS appear to have deployed renewables more rapidly. We believe that our work is the most comprehensive work on the empirical effectiveness of RPS schemes to date. We hope that this work can inform policy-making; however, we do not believe that this work should have the final word. The dataset does not seem to have enough variation to tease out the impact of all RPS features. Many of our results would need to be re-examined as we gain more experience with RPS schemes in the US and other parts of the world.

24

D. Rubin, Matched Sampling for Causal Effects. (Cambridge University Press, 2006).

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53

RENEWABLE SUPPORT POLICIES IN EUROPE: EVALUATION OF THE PUSH–PULL FRAMEWORK FOR WIND AND PV IN THE EU Ruben Laleman1

INTRODUCTION Policies based on the push–pull framework have proven to be efficient and effective in order to bring new (sustainable) technologies to the market. Basically, the framework consists of two phases. In the first stages of technology development, investments should focus on research, development and demonstration in order to improve efficiency and quality and also to reduce the costs of a given technology. In a second phase, once the technology is close to market competition, deployment subsidies can be used to promote ‘learning by doing’ and initiate market uptake, increase consumer feedback, further reduce costs and increase the market share. The basic structure of this framework is generally accepted and frequently mentioned in the scientific literature2 and in documents of the International 1

2

Dr Ruben Laleman obtained a Masters degree in Life Science Engineering at Ghent University in 2008, an additional Masters in Business Economics in 2009 and a PhD in Applied Economics in 2015, both from the same institution. He is a member of the Centre for Environmental Economics and Environmental Management (CEEM) and co-organiser of the ‘Economics of Electricity Markets’ international summer school at Ghent University. He has published articles in leading academic energy journals such as Renewable Energy and Renewable and Sustainable Energy Reviews. His research interests are focused on energy policy, renewable energy, energy transition and electricity markets. G. F. Nemet, ‘Demand-pull, technology-push, and government-led incentives for non-incremental technical change’, Research Policy 38(5) (2009), 700–9; V. Costantini, F. Crespi, C. Martini and L. Pennacchio, ‘Demand-pull and technology-push public support for eco-innovation: The case of the biofuels sector’, Research Policy 44(3) (2015), 577–95; M. Peters, M. Schneider, T. Griesshaber and V. H. Hoffman, ‘The impact of technology-push and demand-pull policies on technical change – Does the locus of policies matter?’, Research Policy 41(8) (2012), 1296–1308.

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Energy Agency3 (IEA). The European Commission also acknowledges the merits of such a push–pull framework. In a policy document on renewable energy the commission mentions that ‘The push of such measures, complemented by the pull of market deployment . . . brought some key technologies to maturity’.4 However, in contrast to what the EU Commission would like to claim, new research has indicated that, in the case of PV and wind, the application of the push–pull framework was far from optimal. The available data suggests that the budgets which have been assigned to research, development and demonstration (RD&D) for PV and wind were very small compared to the deployment subsidies.5 Some EU member states, mainly Germany, have invested a lot in the promotion of technologies that were not yet mature. These generous deployment subsidies have been criticised by some researchers.6 In this short chapter I will evaluate in what way the above-mentioned push– pull framework applies to wind and PV support policies in the EU in the period 2007–11. I will compare the evolution of recent investments in RD&D (based on data from the International Energy Agency) with investments in the ‘pull’ of wind and PV technologies, namely feed-in tariffs and green certificates. INVESTMENTS IN RD&D IN PV AND WIND IN THE EU The best available estimates on RD&D budgets of EU member states for PV and wind can be found on the website of the IEA.7 Based on this data an overview of the evolution of RD&D budgets assigned to these two technologies since the 1980s is obtained. Figure 53.1 shows a remarkable trend: total RD&D budgets in the 1980s were in fact higher than the budgets at the start of this century. In the period 1980–1990 the average annual RD&D spending on PV and wind was about €92 and €74 million respectively. This decreased to €90 million (PV) and €60 million (wind) in the period 1995–2005. It is only since 2005 (fifteen years after the first IPCC report) that a strong increase in RD&D budgets for these technologies can be observed. As we will see in the next section, the massive deployment of PV and wind technologies in the EU started in the period 2007–11. As it normally takes five to ten years for RD&D investments to result in commercial breakthroughs, it can be assumed that the RD&D ‘boom’ since 2005 did not have a big impact on the PV and wind technologies that were promoted in 2007–11. 3

4

5

6

7

IEA, ‘Good practice policy framework for energy technology research, development and demonstration (RD&D)’ (2011), available at www.iea.org/publications/freepublications/publication/ good_practice_policy.pdf EU Commission, ‘Renewable energy: a major player in the European energy market’, COM(2012) 271 final (2012), available at http://ec.europa.eu/energy/renewables/doc/communication/2012/ comm_en.pdf R. Laleman and J. Albrecht, ‘Comparing push and pull measures for PV and wind in Europe’, Renewable Energy 61 (2014), 33–7. M. Frondel, N. Ritter, C. M. Schmidt and C. Vance, ‘Economic impacts from the promotion of renewable energy technologies: the German experience’, Energy Policy 38(8) (2010), 4048–56. IEA, ‘RD&D online database, 2014’, International Energy Agency, available at www.iea.org/ statistics/RDDonlinedataservice

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Figure 53.1 RD&D budgets in the EU for PV and wind (based on data from the International Energy Agency) INVESTMENTS IN DEPLOYMENT OF PV AND WIND IN THE EU The costs of PV and wind deployment have increased a lot in the past years because of European and national policies targeting the promotion of renewable energy (see Figure 53.2). Most striking is the spectacular rise in PV deployment costs which increased from less than €1 billion in 2007 to more than €15 billion in 2011. In contrast, wind subsidies have increased at a more modest pace, from about €4.3 billion in 2007 to €8.4 billion in 2011. A big share of these subsidy costs can be attributed to Germany. In 2011, according to the data, about €2 billion was spent on PV feed-in tariffs in Germany alone, or roughly a quarter of the total cost in the EU. Recent estimates regarding the promotion of renewables in Germany find a total cost of €16 billion for all renewables (biomass, hydro, PV, wind) for the year 2013.8 RESULTS The above discussion indicates that much more money was directed to subsidising existing technologies (pull) compared to investments in research to find more efficient technologies (push). Table 53.1 shows the discrepancy between push and pull measures in the renewables sector in the EU in the period 2007–11. On average, over this five-year period, the total amount of money that went to demand pull policies for wind and PV respectively was fifty-three and thirty-eight times higher than the amount of money directed to supply-push (RD&D). This is can be seen from the average pull/push ratios shown in the last column of Table 53.1. However, as mentioned before, RD&D efforts do not result in commercial breakthroughs in only a few months: it often takes five to ten years for this to happen. It is therefore more accurate to compare the average pull budgets from 8

‘Germany’s energy transition: sunny, windy, costly and dirty’, The Economist (18 January 2014), available at http://www.economist.com/news/europe/21594336-germanys-new-super-ministerenergy-and-economy-has-his-work-cut-out-sunny-windy-costly

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Figure 53.2 Deployment costs for PV and wind in the EU Sources: European Renewable Energies Federation, ‘Prices for renewable energies in Europe: Report 2009’ (2009), available at www.erec.org/fileadmin/erec_docs/Documents/EREF%20Prices%20for% 20Renewable%20Energies%20in%20Europe%20-%20Report%202009.pdf, and ‘Prices for renewable energies in Europe: Report 2011–12’ (2012), available at www.eref-europe.org/wp-content/ uploads/EREF-Price-Report-2012.pdf; EWEA, ‘Wind in power: 2012 European statistics’ (2013), available at www.ewea.org/fileadmin/files/library/publications/statistics/Wind_in_power_annual_ statistics_2012.pdf; EPIA, ‘Connecting the sun’ (2012), available at www.epia.org/news/publications/ connecting-the-sun, and ‘Global market outlook for photovoltaics 2013–2017’ (2013), available at www.epia.org/fileadmin/user_upload/Publications/GMO_2013_-_Final_PDF.pdf

Table 53.1 Pull/push ratio for wind and PV in the EU € million

2007

2008

2009

2010

2011

Average

Wind

80

88

108

196

150

124

PV

134

168

176

174

177

166

Pull

Wind

4,324

5,192

6,317

7,353

8,417

6,321

PV

836

3,320

5,000

8,890

15,265

6,663

Pull/Push

Wind

54

59

61

38

56

53

PV

6

20

28

51

86

38

Push

2007 to 2011 with the push efforts in 2002–6, thus incorporating a five-year time lag between pull and push. We could also compare these pull budgets with RD&D efforts for 1997–2001, but as Figure 53.1 shows, RD&D budgets are relatively constant from 1986 until 2004, therefore a longer lag time would not have any major impact on the overall conclusions. As the results from Table 53.2 show, taking into account a five-year time lag between RD&D efforts (push) and deployment spending (pull) results in even higher pull/push ratios. This is an indication that the strong pull of technologies in the years 2007–11 was not prepared for by investment in research in the preceding years to improve these technologies.

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Table 53.2 Pull/push ratio for wind and PV in the EU with a five-year time lag for RD&D efforts € million Push

Pull

Pull/Push

2002

2003

2004

2005

2006

Average

Wind

55

50

49

73

84

62

PV

87

87

84

112

116

97

2007

2008

2009

2010

2011

Average

Wind

4,325

5,192

6,317

7,353

8,417

6,321

PV

836

3,320

5,003

8,889

15,265

6,663

2007/2002

2008/2003

2009/2004

2010/2005

2011/2006

Average

Wind

78

103

128

101

100

101

PV

10

38

60

80

132

69

CONCLUSIONS Effective and efficient technology-innovation policies consist of strong investments in RD&D to find new, promising technologies in the early development stages and, after some years, a roll-out of deployment subsidies once these technologies are close to market competition. However, the above discussion illustrates that this long-term vision was not present in Europe’s renewable energy strategy. Instead, many member states started promoting renewables without sufficient investments in research in the preceding years. A more balanced pullpush framework would probably have resulted in lower overall deployment costs, especially for PV technologies. Despite the criticism towards renewable energy policies, the above discussion should not be interpreted as a recommendation for a total phase-out of deployment subsidies for renewables. It should be stressed that renewables – from an environmental economics perspective – are in fact eligible to receive some form of subsidies to compensate for the many benefits associated with them (energy independence, lower environmental impact). However, the design of renewables support schemes must nevertheless be critically evaluated, in order to improve the cost efficiency of future policies targeted to the promotion of renewable energy. Finally, I would like to end by pointing out that fossil fuel subsidies are unfortunately still present in many developed and developing countries. Banning such a wasteful form of support would be very efficient and wise, and should be a priority for all policymakers and stakeholders worldwide.

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A VIEW FROM THE GLOBAL WIND INDUSTRY Jim Platts1

Windpower Monthly, the internationally recognised journal of note of the global wind energy industry, is now thirty years old. With its sister quarterly, WindStats Report, it records all the technical developments and supply chain innovations of the wind turbine research; development and supply industry; all the project planning and financing tribulations of the wind farm development and operation industry; the complexities of developing the electricity grid to reach these locations and to integrate in this variable kind of power; and the unending problems of political shifts and alterations to the rules of the game concerning what are necessarily very large infrastructure developments but which are handled differently in every country in the world. As of December 2014, the global industry’s forward pipeline of wind farm projects in planning amounted to 460 GW, of which around 300 GW will probably be built. Closer to the present, the forward order books of the ten largest wind turbine manufacturing companies globally – indicative of a twoyear forward view – totalled 58.5 GW capacity, around 30 GW per year, which will mostly be onshore wind farms using their well-established wind turbine designs in the 2–3 MW range, of 90–110 m diameter, the companies collectively manufacturing and installing around 12,000 wind turbines a year.2 The two largest wind energy companies globally, Vestas and Siemens, each have around 12 GW on their forward order books, representing around 6 GW each 1

2

In the 1980s Jim Platts created the designs, the manufacturing processes, the team and the company that made all the wind turbine blades in the (now the Vestas global blade technology centre on the Isle of Wight). Now based in the University of Cambridge’s Institute for Manufacturing, he teaches manufacturing design and leadership and supervises many industrial projects globally. S. Campbell, ‘Concentration on consolidation’, Windpower Monthly (December 2014), 22.

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a year – over 2,000 wind turbines of this size each a year which means a manufacturing rate of some ten wind turbines a day each. Wind energy represented $76 billion in infrastructural investment globally in 2013. INTEGRATED SUPPLY CHAINS The major companies in the wind energy industry head supply chains have been together for over thirty years, developing together the technologies, the skilled workforces and the very substantial factories needed to make the blades, the gearboxes, the generators, the high-voltage power systems, the control systems, the towers and the large mobile cranes to assemble these turbines on site, all working in synchronised rhythm at this rate of production. Over 200,000 people are involved globally and they are rightly proud of what they achieve every day. Henrik Stiesdal, retiring from his role as CTO of Siemens Wind Power after thirty-five years in the industry,3 comments that this core of the industry is now well developed and future progress is mostly going to come from steady evolution of the technology, not from any kind of sudden transformational change, mostly because the depth of understanding of the total system needed to get every bit right is now so high that no outsiders are likely to understand enough to be able to contribute well to the overall story. An assessment of outside efforts to suggest improvements4 shows levels of funding totalling around 0.1 per cent of the industry’s own internal annual spend and thus far less than its own internal annual research, development and demonstration budget. IT’S THE LOCATION, STUPID! As of October 2014 Germany had over 35 GW of wind energy capacity installed onshore with only 628 MW offshore, but Germany has problems.6 Most of its wind energy capacity is in north-west Germany, some 1,000 km from the load centres in south-east Germany. Grid development has not been progressing at anything like the rate of installation of this new generation capacity nor is upgrading the grid a simple task. Much of the grid was built almost half a century ago to fit a very simply structured ‘top-down’ electricity supply requirement, radiating out from large power stations generating at high voltage and cascading down through middle-voltage one-way distribution systems to low-voltage consumer delivery networks. Wind farms represent low- or medium-voltage dispersed generation sources wanting to send electricity the other way. Not only does this overload the system, it creates flow requirements and monitoring, switching and control requirements that never existed before, 5

3

4

5 6

J. Quilter (2014), ‘Stiesdal on new records, old turbines and growth’, Windpower Monthly (December 2014), 48. R. Davidson (2014), ‘High-profile failures cast doubt on VC funding’, Windpower Monthly (December 2014), 11. Windicator (2014), ‘Global index’, Windpower Monthly (October 2014), 44. D. Robb (2014), ‘Helping Germany’s transmission grid keep up with wind capacity growth’, WindStats Report, Q4 2014, 4–6.

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all over the grid. Even simulating what might be required and exploring different design options is a major task, never mind organising and doing it all and sorting out who pays for what and why. Germany frequently has to route its NW–SE power flows out of Germany, through the grids of neighbouring countries and back into Germany to maintain its supply. So the solution to the grid development problem is already using European-level cooperation and requires solving at European level. But the 628 MW offshore represent a different problem, as do the offshore wind farms of neighbouring countries. By 20137 Siemens had completed four offshore wind farms – of 576, 690, 800 and 864 MW – with bespoke transformers and cabling for each, running at 250, 300, 320 and 320 KV, because these were all separate projects running to uncoordinated schedules with no continuity of supply-chain work possible between them. And these were all close inshore AC transmission projects. They did not involve the much more complicated conversion to high-voltage DC transmission required for wind farms being planned much further out to sea. They did involve substantial sub-sea work on major seabed foundations for each turbine (for instance 900 tonnes of sub-sea steel for the above-sea Siemens 3.6 MW turbine and tower weighing 480 tonnes, all with a twenty-year life8) and all transmission cabling deeply trenched into the seabed. This is expensive electricity – €128–42/MWh compared to €60–80/MWh from onshore wind turbines – and Germany has paused in its offshore wind development work. Its forward cost projections for these close inshore wind farms is €91/MWh by 2023 and €100/MWh for far offshore9, with the wind turbines themselves representing only 31.8 per cent of the costs. A comparable US study suggests costs 12 per cent higher than this. There appears to be a steady retreat from exploratory investment in UK offshore wind farms too. Centrica withdrew from the £2 billion offshore Norfolk Race Bank wind farm project in 2013 citing failure to secure adequate consumer-funded subsidies for it and, with their co-developers, closed the Celtic Array offshore wind farm project as ‘uneconomic’, taking a £40m write-down on it, and in 2014 have also sold their stake in the Barrow project to Dong Energy, so Centrica has no forward offshore wind farms in its pipeline.10 THE NEED FOR RHYTHM AND FLOW Cost effectiveness in manufacturing comes from a long-experienced workforce working to a well-established rhythm in a highly tuned flow process. Progress in understanding and incremental improvements in component design and 7

S. Knight, ‘Cabling standards hold key to cutting costs’, Germany Offshore – Windpower Special Report (April 2013), 7–8. 8 A.-S. Arrou-Vignod, ‘Energy balance estimation of offshore guyed tower wind turbines’, MPhil thesis (2012), Institute for Manuafacturing, University of Cambridge, 76. 9 D. Milborrow, ‘Offshore costs: cost of wind continues to fall’, Windpower Monthly (November 2014), 45. 10 T. Webb, ‘Wind stops blowing for Centrica’, The Times (20 December 2014), 50.

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manufacture continue to increase the cost effectiveness in lower wind speed locations such as southern Germany, with the wind turbines still coming from the existing factories. There is a square/cube law that says that larger wind turbines are fundamentally less cost effective whatever you do. Developing larger wind turbines is very expensive and they would need a very large and stable forward flow of orders to make it cost effective to invest in the physically larger factories needed to manufacture them. No such future is in sight. At its global blade technology development centre on the Isle of Wight in the UK, Vestas has made and tested an 80-metre blade and made three blades for its prototype V164 turbine. Its holding position is that this small but very skilled team could make more 80-metre blades if needed, at no further investment.11 This would be one blade every few days, not a few blades every day. This is ‘making’, not ‘manufacturing’. The UK also has problems onshore. Ecotricity, a major UK wind farm investor, has withdrawn from onshore wind development, explaining that the planning process has become unworkable, with changing terms of planning, environmental assessments and financial support every few months. Eric Pickles (the government minister concerned) has intervened in fifty-three wind farm projects, calling in the applications so that he can make the final decision. Out of twenty-five decisions made thus far, twenty-two have been rejections; in seven cases the recommendation of an independent inspector that the wind farm should be built was overruled.12 TIMESCALE, SCALE AND SCOPE ‘Infrastructure’ is in some ways not a ‘market’ at all. It is the single greatest gift that any generation bequeaths to its grandchildren. Its ubiquitous, reliable presence is testimony to the magnitude of the gift. Achieving it requires the cohesive investing of the skills to create it, the will to finance it and the sustaining of transparent rules of the game that engender shared insight, understanding and commitment, and are fair to all. Building prototype wind farms and electricity systems that will only last twenty years, in the North Sea, far from where the electricity is needed, might be heroic engineering, but is it infrastructure?

11

J. Quilter, ‘MHI-Vestas £200 million UK plan remains short on detail’, Windpower Monthly (December 2014), 19. 12 B. Webster (2014), ‘Wind farms owner gives up over political interference’, The Times (25 November 2014), 6.

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THE NEW CONCEPT OF COMPETITIVE BIDDING ON PHOTOVOLTAIC IN THE GERMAN RENEWABLE ENERGY ACT 2014 Joachim Sanden1

INTRODUCTION Competitive bidding processes are progressively replacing feed-in tariffs and simple quotas. The goal is to limit market distortions caused by public budgets and to secure a better allocation of support.2 Germany has successfully promoted feed-in-tariffs for many years and has now shifted towards bidding. However, the introduction of auctions for renewable energy procurement as a market-based instrument will raise some difficult legal questions. BACKGROUND AND DETERMINANTS It seems to be crucial that auctions are adapted to the specific market context. Otherwise, the bidding will deliver sub-optimal results with the risk of destroying 1

2

Professor Joachim Sanden is Extraordinary Professor at Leuphana University Lüneburg, Germany and Vice Director-General of the Directorate-General for Environmental Protection, Ministry of Urban Development and Environment of the Free and Hanseatic City of Hamburg, Germany. He is Visiting Research Fellow at the Centre for Conflict, Rule of Law and Society, University of Bournemouth, UK. His main area of expertise is in public law. R. de Vos and C. Klessman, ‘How to design a successful auction for renewable energy projects’, Energy Post (22 May 2014), available at www.energypost.eu/design-successful-auction-renewableenergy-projects; F. Schmitz-Grethlein, ‘Das Ausschreibungsmodell als Mittel zur Markt- und Systemintegration erneuerbarer Energien – Anforderungen an die Auktionsverordnung’, in S. von Kielmannsegg (ed.), Die EEG-Reform (Nomos, 2015), pp. 47, 49; D. Mayr, J. Schmidt and E. Schmid, ‘The potentials of a reverse auction in allocating subsidies for cost-effective roof-top photovoltaic system deployment’, Energy Policy 69 (2014), 555–65; L. Butler and K. Neuhoff, ‘Comparison of feed-in tariff, quota and auction mechanisms to support wind power development’, Renewable Energy 33(8) (2008), 1854–67.

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renewable energy markets. This is evidenced by negative past experiences with auctions in several countries.3 Renewable energy including photovoltaic (PV) deserves high importance in the legal debate. To think about the energy supply (in German, Energiewende4) is a societal responsibility. The German federal government still, therefore, promotes the necessary expansion of renewables, especially wind and PV. The most recent step in a very long chain of legislative acts to promote energy from renewable sources, starting in 1991, is the 2014 Amendment,5 which came into force on 1 August 2014. The position of renewables in Germany is currently as follows:6 renewables deliver 24 per cent of the total electricity production (152.2 billion kWh of 634.4 billion kWh). The share of PV is 47 per cent. The share of renewables is less than that of brown coal (25.5 per cent), but greater than that of black coal (19.5 per cent), atomic energy (15.3 per cent), gas (10.4 per cent) and others (5.2 per cent). In January 2015, German wind installations produced more than 10 billion kWh (including 0.2 billion kWh offshore).7 The compensation rate8 until 2014 (on average) was 32 eurocents/ kWh for photovoltaics. NEW PATHWAY OF COMPETITIVE BIDDING Demand for competitive bidding The EU’s framework for subsidies of member states to further boost renewable energy (PV) consists of different regulations. Beyond the de minimis aid regulation,9 the subsidy paid by the government should be in line with Commission Regulation (EU) No 651/2014 of 17 June 2014.10 This regulation allows investment in, among other things, the promotion of renewable energy. In Article 42, 3

P. del Río and P. Linares, ‘Back to the future? Rethinking auctions for renewable electricity support’, Renewable & Sustainable Energy Reviews 35 (2014), 42–56. 4 R. Scholz, M. Beckmann, C. Pieper et al., ‘Considerations on providing the energy needs using exclusively renewable sources: Energiewende in Germany’, Renewable and Sustainable Energy Reviews 35 (2014), 109–25. 5 Gesetz für den Ausbau erneuerbarer Energien (Erneuerbare-Energien-Gesetz − EEG 2014), 21 July 2014 (Federal Law Gazette I, p. 1066), last amendment by Article 1 of the Act of 22 December 2014 (Federal Law Gazette I, p. 2406). 6 Agentur für Erneuerbare Energien, ‘Arbeitskreis Energiebilanzen’ (May 2014), available at www. unendlich-viel-Energie.de 7 German Association of Energy and Water Industries (BDEW), ‘Windstrom-Erzeugung im Januar auf Rekordhöhe’ (13 February 2015), available at www.bdew.de/internet.nsf/id/DCA5E9FBA2 03364FC1257DEB002F8A68 8 See German Association of Energy and Water Industries (BDEW), ‘Erneuerbare Energien und das EEG: Zahlen, Fakten, Grafiken’ (24 February 2014), 65, available at www.bdew.de/internet.nsf/ id/83C963F43062D3B9C1257C89003153BF/$file/Energie-Info_Erneuerbare%20Energien%20 und%20das%20EEG%20%282014%29_24.02.2014_final_Journalisten.pdf 9 Commission Regulation (EU) No 1407/2013 of 18.12.2013 on the application of Articles 107 and 108 of the Treaty on the Functioning of the European Union to de minimis aid, OJ No. L 352/1 of 24.12.2013. 10 European Commission, Regulation (EU) No 651/2014 of 17 June 2014 declaring certain categories of aid compatible with the internal market in application of Articles 107 and 108 of the Treaty, OJ No. L 187/1 of 26 June 2014.

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we find rules on ‘Operating aid for the promotion of electricity from renewable sources’. According to Article 42 (2), ‘aid shall be granted in a competitive bidding process on the basis of clear, transparent and non-discriminatory criteria which shall be open to all generators producing electricity from renewable energy sources on a non-discriminatory basis’. The European Commission should be notified of all other measures which exceed the thresholds or are intended to finance other aspects, and it must be shown evidence of the compatibility with the state aid regulations (Article 107 TFEU), in particular with the Communication from the Commission.11 The new guidelines set procurement, regardless of other countries’ experiences,12 as a key principle for the promotion of renewable energies determined (‘competitive bidding’). They plan a test phase for the years 2015 and 2016. In this phase, 5 per cent of the national development path must be managed by procurement.13 As of 2017, it will be necessary in principle to upgrade the entire promotion of renewable energies and cogeneration to tenders. Member states may not derogate from this process unless they are able to demonstrate the existence of the criteria laid down in Article 127. The new bidding concept in EEG 2014 and beyond What the German federal government14 tried to achieve with the EEG 2.0/2014 was quite simple, regarding the planned 35 per cent share of the renewables. The government was – with regard to EU climate targets and the efforts to limit the costs – due to set targets for the (planned) controlled expansion of renewable energies. By 2025, the share of renewable energies should be between 40 and 45 per cent, and by 2035 between 55 and 60 per cent. Therefore, the 11

European Commission, ‘Communication from the Commission: guidelines on state aid for environmental protection and energy 2014–2020, C(2014) 2322’, available at http://ec.europa.eu/ competition/sectors/energy/eeag_en.pdf; P. Nicolaides, ‘The new guidelines on state aid for environmental protection and energy, 2014-2020’, Lexxion State Aid Blog (2 May 2014), available at www.lexxion.eu/training/stateaidblog/2014/05/02/133-the-new-guidelines-on-state-aid-forenvironmental-protection-and-energy-2014-2020; P. Nicolaidis and M. Kleis, ‘A critical analysis of environmental tax reductions and generation adequacy provisions in the EEAG 2014–2020’, European State Aid Law Quarterly 13(4) (2014), 636; E. Szyszczak, ‘Commission communication on guidelines on state aid for environmental protection and energy 2014–2020’ (9 April 2014), available at http://ssrn.com/abstract=2464290; Raf Callaerts, ‘State aid for the production of electricity from renewable energy resources’, European Energy and Environmental Law Review 24(1) (2015), 17–26. 12 G. Elizondo Azuela, L. Barroso, A. Khanna, X. Wang, Y. Wu and G. Cunha, ‘Performance of renewable energy auctions: experience in Brazil, China and India’, The World Bank, Policy Research Working Paper Series: No. 7062, 2014; D. R. Walwyn and A. C. Brent, ‘Renewable energy gathers steam in South Africa’, Renewable and Sustainable Energy Reviews 41(1) (2015), 390–401; T. Altenburg and T. Engelmeier, ‘Boosting solar investment with limited subsidies: rent management and policy learning in India’, Energy Policy 59 (2013), 866–74, at 870. 13 European Commission, ‘State aid approval decision of 23 July 2014 on the revised EEG 2014’: ‘In addition, during a transitional phase covering the years 2015 and 2016, aid for at least 5% of the planned new electricity capacity from renewable energy sources needs to be granted in a competitive bidding process on the basis of clear, transparent and non-discriminatory criteria (point 127 of the EEAG)’, 239. 14 Federal Ministry for Economic Affairs and Energy, ‘Erneuerbare-Energien-Gesetz 2014’, available at www.bmwi.de/DE/Themen/Energie/Erneuerbare-Energien/eeg-2014.html

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government defined concrete volume targets (so-called development corridors) for the annual expansion of each EE technology. For solar energy, the annual additional construction is 2.5 GW (gross). Regarding European plans for competitive bidding, the German EEG 2014 now contains in Article 55 a regulation on the set-up of an appropriate procedure. Authorised by Article 87, 88, 93 and 95 EEG 2014, the Federal Ministry of Economic Affairs and Energy (BMWi) presented two drafts for an ordinance regulating auctions. In these auctions, the governments select candidate companies for financial support for freestanding PV power plants. After some criticism, the government passed the decree on 28 January 2015.15 The new ordinance (FFAV) enlarges the land considered suitable for PV power plants that want to participate in the auctioning process as of 2016, but cuts back on the volume of the auctions.16 Instead of 600 MW annual capacity, only 400 MW shall be auctioned on average in the period 2015 to 2017. The first auction, managed by the Federal Network Agency for Electricity, Gas, Telecommunications, Post and Railway (Bundesnetzagentur), will start in April 2015; the subsequent ones will take place in August and December. To reach the PV target (2,500 MW/year, cf. Article 3 (4) EEG 2014), the new ordinance limits the average auctioning volume in the years 2015 to 2017 to 400 MW/year on average (Article 1 FFAV). In 2015, 500 MW will be auctioned, in 2016 400 MW and in 2017 300 MW. Concerning the size of the bids, the FFAV refers in Article 8 to a maximum (not a minimum) of each single bid and follows the idea of pay-as-bid (not uniform pricing).17 Article 13 FFAV describes the criteria of the surcharge value. The Bundesnetzagentur is obliged, according to Article 14 FFAV, to publish the surcharge and the amount of the surcharge value. Regulating which land is suitable for freestanding PV power plants taking part in auctions is also important. The starting point is that bids – the maximum is 10 MW/project – can be made for plants on sealed surfaces, conversion areas and near railways and motorways. This is a fairly restrictive regulation, which may lead to the problem of not having enough sites for PV installations. In 2015, observers estimate the demand at 1,000 per hectare.18 The new ordinance

15

Verordnung zur Einführung von Ausschreibungen der finanziellen Förderung für Freiflächenanlagen sowie zur Änderung weiterer Verordnungen zur Förderung der erneuerbaren Energien, 6 February 2015, Federal Law Gazette (11 February 2015), 108. 16 M. Lang and A. Lang, ‘New ministerial draft of ordinance on competitive bidding for financial support for PV power redefines suitable land, cuts back on volume’ (26 January 2015), available at www.germanenergyblog.de/?p=17797; Ralf Köpke, ‘Das solare Ausschreibungsmodell im Überblick’, Energie & Management (24 February 2015), available at www.energie-und management.de/?id=84&no_cache=1&terminID=108503 17 F. Schmitz-Grethlein, ‘Das Ausschreibungsmodell als Mittel zur Markt- und Systemintegration erneuerbarer Energien – Anforderungen an die Auktionsverordnung’, in S. von Kielmannsegg (ed.), Die EEG-Reform (Nomos, 2015), pp. 47, 51; W. Lehnert, ‘Direktvermarktung und Netzintegration von Strom aus erneuerbaren Energien im EEG 2014: Gesetzliche Vorgaben und Rechtspraxis’, Zeitschrift für Umweltrecht (2015), 277, 285. 18 J. Staude, ‘Solar-Bürokratiemonster entworfen’, Klimaretter Info (17 January 2015), available at www.klimaretter.info/politik/hintergrund/17992-das-solar-buerokratiemonster-entworfen

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makes it possible, as of 2016, to address land managed by the Federal Fund for the Management of Real Estate. Furthermore, ten projects will take place annually on land that is located in a less-favoured farming area.19 The idea is to guarantee that the development of farming and other greenfield sites by new PV installations is limited. This has been a clear demand of lobbying groups such as the German Farmers’ Association in political discussion of recent months. Now, it will be the task of local general landscape planning to consider the different approaches to landscape use. However, the new ordinance does not solve the other serious problems of competitive bidding. In the renewable-energy sector, the implementation risk (for example, for PV installations) is higher than in traditional energy plants.20 The problem focuses on auctions because money is granted before the bidding installations are built. One possible solution is high prequalification requirements for the bidding participants. The FFAV contains the precondition of paying €4/kW as a first deposit (bid bond) before bidding (Article 7). Half of the sum is needed in the case of already existing decisions under the building code that the installation is permitted according to planning law. If the bidder receives a positive decision, he is obliged to pay a second deposit (€50/kW, Article 15). Even bigger companies will be able to fulfil these requirements and administrative burdens. Additional penalties (Article 30) secure the implementation. However, a sufficient number of bidders (on the same level) is a necessity for effective bidding (see Article 2, Para. 5 EEG 2014 describing the goal of securing a variety of actors). Furthermore, the authorities should try to avoid strategic bidding (agreement on prices) by the bidding companies. Finally, but significantly, the new ordinance is unclear about the ways and preconditions for taking legal action.21 OUTLOOK: EEG 3.0 COMING SOON The current EEG 2014 will soon change.22 EEG 3.0 (expected in 2016) will create a legal framework to determine the amount of grant available for renewable energy technologies from the end of 2016, in general by competitive tender. It will be necessary to introduce tenders on technologies other than PV, except electricity from renewable and mine gas, by the year 2016. Based on the new ordinance FFAV, on 24 February 2015 the German federal government announced the first pilot project tenders dealing with PV on free areas. The first investors had the chance to submit their applications until 19

See the definition in Directive 86/465/EEC concerning the Community list of less-favoured farming areas within the meaning of Directive 75/268/EEC. 20 de Vos and Klessman, ‘How to design a successful auction’. 21 F. Huerkamp, ‘Ausschreibungen für PV-Anlagen: Ende der “Planwirtschaft” beim Strom?’, Wirtschaftswoche Green (6 February 2015), available at http://green.wiwo.de/ausschreibungenfuer-pv-anlagen-ende-der-planwirtschaft-beim-strom 22 Federal Ministry for Economic Affairs and Energy, ‘Zentrale Vorhaben, Energiewende für die 18. Legislaturperiode’, 4, available at www.bmwi.de/BMWi/Redaktion/PDF/0-9/10-punkte-energieagenda,property=pdf,bereich=bmwi2012,sprache=de,rwb=true.pdf

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15 April 2015. As part of the transition of support for renewable energy to tender for other technologies, the experience of the pilot tender will be evaluated and in particular it will be decided how the context for developing freestanding PV systems will look in 2018. The plan of the German government is to gain experience with the new instrument of competitive bidding for the pilot projects. As for political pressure by the European Commission, the auctioning system shall in principle become mandatory in 2017 for all kinds of renewable energies.23 The results of this model experiment should flow directly into the next amendment of the EEG (3.0).

23

Lang and Lang, ‘New ministerial draft of ordinance on competitive bidding’; Köpke, ‘Das solare Ausschreibungsmodell im Überblick’.

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LEGAL CERTAINTY FOR GREEN ENERGY PROJECTS: SURE, BUT AT WHAT PRICE? Wouter Vandorpe1

LEGAL CERTAINTY AND FIXED PARAMETERS IN ASSESSING ENERGY PROJECTS In evaluating the viability of an energy project, it sometimes comes down to one thing: legal certainty. Legal certainty is a principle that provides (private) players with the ability to regulate their conduct through law for a certain and longer period of time. If investors, producers and consumers are able to have a positive view of the possibilities or restrictions imposed by law, and how and when this law might change, they will be better able to avoid difficulties, miscalculation or liability in their actions related to the project. This seems obvious in theory, but is often a delusion in practice. Energy law directly impacts on the business case of energy projects. Before giving a green light to a project, the investor or responsible energy manager will fill in the numbers in its business case sheet, not only on a financial, tax or economic level, but also on a legal level, that is, giving law a financial value. In a legal due diligence on energy projects, questions usually arise on licences, grid connections, typical building/environmental permission issues and assessing clauses in energy contracts, but the most tricky parameter to judge upon generally is the level of subsidy a (green) energy project would obtain from an authority. The level of legal certainty on these ‘legal’ parameters will contribute to determining the value, outcome and timing of investments, and could influence, 1

Wouter Vandorpe is a Brussels-based energy and utilities lawyer at Fieldfisher (Field Fisher Waterhouse LLP), Senior Associate Energy Practice and scientific researcher at the Catholic University of Leuven, Belgium (Institute for Environmental and Energy Law, KU Leuven). This contribution is written in the author’s own name.

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as a legitimate way of ‘shopping’ by the investor, the investment strategy of a company in a particular state. Therefore, at first sight, it would seem better or more convenient to be able to impose simple, fixed parameters on support (‘You will receive X euros from the government for Y years.’). But if such a system turns out to be unpayable or otherwise economically flawed, such fixed parameters could turn out to be inadequate, and variable parameters are at times more reliable. The example of Belgium shows why. THE EARLY SIMPLE, FIXED GREEN CERTIFICATE MECHANISMS From the first EU Energy Package (which entered into force in 1998 for electricity and 2000 for gas), the European Commission allowed member states to choose their green energy support scheme: a feed-in tariff scheme, a green certificate system or a mix of both. Belgium, by means of the federal state and its three regions,2 chose a green certificate (GC) system,3 requiring suppliers to submit each year a number of certificates for a specific percentage of supplied electricity volumes (eventually leading up to the target fixed for 2020, which is 13 per cent for Belgium), and giving producers of green electricity the possibility of selling the green certificates to suppliers (on a GC ‘market’), or to the state (via the grid operators) for a fixed minimum price. In the first years of green support, the system was applied in a very simple way, for example in the Flemish Region, where a GC showed that 1,000 kWh (1 MWh) of electricity had been generated from a renewable energy source and the minimum support was fixed to one price throughout the whole support period. Such one-on-one guaranteed support is simple, fixed and easy to calculate in a business plan, and could therefore, at first sight, bolster legal certainty. THE EXCESSIVE COST OF SUCH MECHANISM AND UNCERTAIN MEASURES AS A REACTION Very soon after the introduction of this system, however, the level of minimum support for various technologies proved to be too high to recover investment costs (for example, for years, for PV technology, minimum support of €450/ MWh over a period of twenty years had been guaranteed). The grid operators, paying the minimum support, were faced with costs of several billion euros for the system. In addition, a surplus of certificates was created, which affected the value of the GC and, more broadly, the investment climate itself. It was clear that a uniform, fixed and simple financial methodology could no longer be applied to all projects, regardless of the underlying technology (solar, wind, biomass, biogas, hydro). 2

3

In Belgium, competences regarding energy policy are divided between the Federal Authority and the Regions. The regional aspects of energy policy include, among other things, the new energy sources (with the exception of those relating to nuclear energy) and the rational use of energy. On the difference between feed-in tariff schemes, green certificates schemes, see Commission, ‘Communication on the support of electricity from renewable energy sources’, COM(2005) 627 final, SEC(2005) 1571, from 5.

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In order to put a halt to this excessive regime, even though the different Belgian governments could not directly reclaim the acquired rights of guaranteed minimum support already given to the projects, multiple measures were taken at short notice: • For new projects, the level of minimum support was very rapidly decreased, with few transitional measures (such as minimum support for solar PV technology from €450 to €90/MWh in less than two years): this is at the limit of legal certainty. • New ways of imposing a levy/tax/tariff on the existing projects were developed: injection, distribution or capacity tariffs were imposed, but the bulk of these tariffs have been annulled by the courts, since these again touched upon the legal certainty principle. NEED FOR ADJUSTMENT: THE GREEN CERTIFICATE SYSTEMS WITH MORE FLEXIBLE PARAMETERS A revision was completed in 2012, linking the duration and amount of green support to variable parameters of production cost, profit and the value of the GC: the less profit an investor makes, the more GC he or she will receive and vice versa. Each technology has been given a certain percentage of envisaged return on investment (ROI) at the end of the run (varying from 5 per cent for PV installations to 12 per cent). This turned out to be a positive development: the new mechanism has made the green support system less expensive and more viable in the long run, therefore augmenting legal certainty and simply making more sense. Nonetheless, multiple issues remain in relation to this new system. For example in the Flemish region the following problems remain: • The new system consists of very complex formulae, and parameters are influenced by the market. • Low GC prices and low minimum support have significantly reduced the number of investments on various technologies (especially PV). • The support is still undergoing regular adaptations, now every six months (for existing and new projects), although such adaptations are more predictable, since these are linked to a general concept of investment cost, operation cost and objective market parameters. • A new and more complete support revision is to be announced in 2016, which has the ambitious goal of further simplifying a costeffective green support system but which could challenge investors and affect the current acquired rights of producers in relation to green certificates. GOOD OR BAD? Did the excessive support of the early days kick-start the number of green projects, and stimulate interest in and the development of the market? Certainly, but at what price? The initial expansionary effect has now gone and the cost

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of it will still be borne for years (through tariffs and other levies, at least up till 2019). It could also mortgage a more rapid evolution of the Belgian green energy sector until 2020. Some investors today are still nostalgic about the early days, when they could deal with simple calculations and clear business plans. But more than the legal certainty of an individual project, the legal certainty of the Belgian green support system seems economically healthier now. Of course, some of the pioneering projects will still receive an excessive minimum support for many years – but that is probably the price to be paid for legal certainty.

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THE FUTURE OF HYDROELECTRIC POWER IN THE UNITED STATES: THINKING SMALL Dan Tarlock1

INTRODUCTION: THE STATIC STATE OF UNITED STATES HYDRO Hydroelectric energy (hydro) is the oldest major source of non-carbon renewable energy in the United States. It currently supplies 42 per cent of the 7 per cent of US domestic energy production generated by renewable resources.2 For at least four reasons, increased hydro generation would seem to be a major element of any US climate change and energy security policy designed to help the country transition to the production of sustainable, non-carbon-based energy. First, hydro is relatively clean because it does not cause air pollution or substantial greenhouse gas emissions. Second, hydro capacity is relatively reliable and substantial undeveloped capacity exists. Third, hydro can help wean the United States from its post-World War II dependence on imported and often politically unstable hydrocarbon sources of energy. Fourth, despite criticisms of the environmental and social impacts of large dams,3 increased hydro is a 1

2

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Dan Tarlock is Distinguished Professor of Law at the Chicago-Kent College of Law in the Illinois Institute of Technology and holds an AB and LLB from Stanford University. He has taught and written in the fields of environmental, land use, energy, natural resources and water resources law. He has also participated in the Water Science and Technology Board of the National Research Council-National Academy of Sciences’ assessments of aquatic ecosystem restoration on large river systems. US Energy Information Administration, Frequently Asked Questions, available at http://perma. cc/856X-NJWF See World Communication On Dams, ‘Dams and development: a new framework for decision making’ (2000), available at www.unep.org/dams/WCD/report/WCD_DAMS%20report.pdf; K. Matsui, Native Peoples and Water Rights: Irrigation, Dams, and the Law in Western Canada (McGill-Queen’s Native and Northern Series, 2009) and T. Scudder, The Future Of Large Dams: Dealing With Social, Environmental, Institutional And Political Costs (Earthscan, 2005), p. 61.

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worldwide trend. Many nations in Africa, Asia, Latin America and Canada are investing heavily in new hydro facilities. The Energy Information Administration (EIA) projects that worldwide hydroelectricity-generating capacity will grow at a rate of 2 per cent through the years 2008–35.4 The United States has been a leader in hydroelectric production and technology, but hydro is now treated as the stepchild of renewable energy law and policy. The current expert consensus answer is that increased hydro generation is not projected to be a major component of any carbon or non-carbon United States energy future, but that for the foreseeable future hydro’s share will be flat or experience only modest increases.5 To borrow from equilibrium ecology, hydro has reached its climax stage.6 Initially, the static state of US hydro is paradoxical because the International Energy Agency (IEA) estimates that the United States has tapped only 16 per cent of its potential hydropower production.7 There are three answers to this paradox. First, hydro is both a non-carbon strategy to reduce greenhouse gas emissions and a victim of global climate change.8 Hydroelectric production is sensitive to changes in stream flows. For example, a 1 per cent decrease in the flow of the Colorado River, which helps supply Los Angeles with electric power, can reduce the hydroelectric production of the system’s dams by 3 per cent.9 Second, the result of federal and state restructuring of the electric utility industry in the United States has led to less investment in 4

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US Energy Information Administration, Annual Energy Outlook 2011 (EIA, 2011). Under a reference case scenario, the projected growth rates of installed hydroelectricity-generating capacity from 2008 to 2035 for the United States is 0.1 per cent. US Energy Information Administration, available at www.eia.gov/oiaf/aeo/tablebrowser/#release=IEO2011&subject=9IEO2011&table=22-IEO2011®ion=0-0&cases=Reference-0504a_1630 This is the conclusion reached by a comprehensive assessment of the nation’s energy future by the National Academies, Electricity from Renewable Sources: Status, Prospects and Impediments (National Academy Press, 2010), p. 56. Other studies reach similar conclusions, for example Rand Science and Technology, ‘Generating electric power in the Pacific Northwest: implications for alternative technologies’ (2002), 8, available at www.rand.org/content/dam/rand/pubs/monograph_reports/2002/MR1604.pdf (‘Current projections show that in the future, the majority of all new electricity generation in the Northwest – in fact the entire West – will come from naturalgas-fired plants.’) Early-twentieth-century ecology was premised on the theory that natural systems progressed to a relatively steady climax state. F. Bosselman and A. D. Tarlock, ‘The influence of ecological science on American law: an introduction’, Chicago-Kent Law Review 69(4) (1994), 847–73, explains the origins of climax theory and its replacement by non-equilibrium theories. International Energy Agency, ‘Renewable energy essentials: hydropower’ (2010), available at www.iea.org/papers/2010/Hydropower_Essentials.pdf United States Department of Energy, ‘Effects of climate change on federal hydropower’, Report to Congress (August 2013), available at http://energy.gov/sites/prod/files/2013/12/f5/hydro_climate_change_report.pdf T. J. Wilbanks, V. Bhatt, D. E. Bilello, S. R. Bull, J. Eckmann, W. C. Horak, Y. J. Huang, M. D. Levine, M. J. Sale, D. K. Schmalzer and M. J. Scott ,‘Effects of global climate change on energy production and use in the United States’, Report by the US Climate Change Science Program and the Subcommittee on Global Change Research, Department of Energy, Office of Biological & Environmental Research (2009), available at http://science.energy.gov/~/media/ber/pdf/ia_workshop _low_res_06_25_09.pdf

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generation capacity.10 Third, since 1968 the United States has addressed the adverse environmental impacts of hydroelectric production by a serious of laws that substantially constrain the construction of new dams and the operation of existing ones. Thus, there is no need to subsidise additional capacity compared to the subsidies offered to other renewable sources of energy.11 THE LEGAL CONSTRAINTS TO PROTECT THE ENVIRONMENT The imposition of environmental constraints on hydropower production began in the 1930s with the construction of fish ladders on projects to protect fish runs.12 The major constraints, however, date from 1968. In that year, Congress passed the Wild and Scenic Rivers Act which designated three categories of free-flowing rivers. Some 208 rivers are now included in the system. The Act expressly precludes both private and public development on these rivers,13 which include many of the best undeveloped river canyons. The next major constraint came in 1973. To implement the Convention in Trade in Endangered Species (CITES), Congress enacted the Endangered Species Act (ESA) which applies to public and federally licensed dams that jeopardise the survival of a listed fish.14 The ESA has become a basis for the imposition of mandatory flow releases to protect at-risk species. In addition, by the end of the 1970s, the federal government had stopped constructing large multiple-purpose dams. Public utilities and small ‘merchant’ power providers are the major source of new hydro production. The Federal Energy Regulatory Commission (FERC) retained the power to license and re-license private projects. FERC administers the 1935 Federal Power Act.15 Thus, the agency has the primary responsibility to apply the full range of federal environmental laws to the projects that it licenses. Public utilities and others who wish to construct a facility on a navigable river must obtain a FERC licence. The licences last fifty years; if the licensee wishes to continue to operate the project, it must apply for a new licence. The original licenses were issued before the concern for the environmental impacts of dam operation. Relicensing proceedings generally allow interveners who raise these considerations. These proceedings have become very contentious. 10

Underinvestment is a problem in most developed countries. See International Energy Agency, Tackling Investment Challenges in Power Generation in IEA Countries (2007), available at www.iea.org/publications/freepublications/publication/tackling_investment.pdf 11 For example, the 2011 Amendments to Illinois’s utility renewable portfolio standards define only ‘hydropower that does not involve new construction or significant expansion of hydropower dams’ as a renewable source of energy, 20 ILCS 3855/1-10 (2011). The purpose is to ensure that most existing hydropower does not count towards the portfolio standard. The failed 2009 Waxman-Markey energy bill, H.R. 2454 (2009), classified hydro as a renewable energy source for the purpose of carbon credits but credit was limited to ‘qualified hydro power’, which was defined as either energy efficiency or capacity additions to pre-1992 hydroelectric facilities which were placed in service after 1 January 1992. Sec. 101(a)(18)(G). 12 D. Tarlock, ‘Hydro law and the future of electric power generation in the United States’, Vanderbilt Law Review 65(6) (2012), 1723–67. 13 16 USC, Sec. 1278. 14 16 USC, Sec. 1531–9. 15 16 USC, Sec. 201 et seq.

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In 1986, Congress responded to the need to mandate the environmental considerations in new and re-licensed projects and enacted the Electric Consumers Protection Act (ECPA).16 EPCA mandates that FERC give equal weight to the benefits of relicensing the project and to ‘the protection, mitigation of damage to, and enhancement of, fish and wildlife (including related spawning grounds and habitat)’. The ESA still applies to all FERC projects too, but ECPA decides whether or not the project will jeopardise a listed species. FERC retains the discretion to make the final balance between fish and hydro, but must justify any decisions to subordinate fish protection to electric power generation. The federal Clean Water Act has become a powerful tool to require minimum flow releases. Section 40117 requires that federal licences obtain a state certification that the operation of the project will not violate state water-quality standards. In a rare pro-environmental decision, PUD No. 1 of Jefferson County v. Washington Department of Ecology18, the United States Supreme Court held that Section 401 allowed the state to impose minimum flows for fish protection and aesthetic enhancement. The utility argued that the conditions were water quantity not quality conditions but with a majority Connor J dismissed the distinction as artificial. FERC must now accept the all legitimate 401 conditions imposed by the state. Environmentalists are moving beyond minimum flow release conditions and are now pressing for the removal of many hydro dams. Major public dam removal decisions must be made by Congress, but FERC has the power to order the removal of at least some licensed dams, and Congressional approval is not required for the removal of FERC-licensed dams. Dam removal is a relevant consideration in many re-licensing applications because the Federal Power Act has been construed to give the agency the authority to deny a licence renewal application and order that a dam be decommissioned if the facility has become uneconomic.19 A SMALL-SCALE FUTURE The future of hydro lies in small-scale projects. State and federal alternative energy legislation generally only extends various benefits such as credit under state alternative energy portfolio standards and tax incentives to new, small-scale projects. The current boom is primarily in ‘little’ hydro, often run-of-the-river and kinetic projects. To further induce small-scale projects in 2013, Congress passed the Hydropower Regulatory Efficiency Act20 which expands FERC exemptions for small hydropower projects and conduits from 5 to 10 MW. It also exempts small hydropower projects that use only the hydroelectric potential of a non-federally owned conduit, have a maximum installed capacity of 5 MW and are not currently licensed or exempted from FERC licence requirements. 16

16 USC, Sec. 797(e). 16 USC, Sec. 797(e). 18 511 US 700 (1994). 19 City of Tacoma v. Federal Energy Regulatory Commission, 460 F.3d 55 (D.C.Cir. 2006). 20 PL 113-23 (9 August 2013), 127 Stat 493 codified in 16 USC, Sec. 2705(d). 17

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The Act expedites the licensing of low-impact hydropower projects, the new law, by directing FERC to investigate the feasibility of issuing a licence for hydropower projects at non-powered dams and closed loop-pumped storage projects in a two-year period. Significantly, the new law states that this twoyear period shall include any FERC pre-licensing process. This reflects the fact that FERC relicensing proceedings have become prolonged multi-stakeholder negotiations.

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HYDROPOWER: FROM PAST TO FUTURE UNCERTAINTIES Ludovic Gaudard1 and Franco Romerio2, 3

INTRODUCTION In the past, hydropower (HP) underwent impressive development in many countries around the world, despite technical, environmental, economic and institutional uncertainties. Today, HP faces even more challenging uncertainties due to the opening of power markets to competition. This article highlights the entire spectrum of uncertainties and provides some indications for the future. Uncertainty applies to future unknown events and trends, in the sense that it is not possible to quantify their probability of occurrence. This is what distinguishes uncertainty from risk.4 In 2011, HP represented 19.5 per cent of installed electrical capacity worldwide, 9 per cent in the USA, 19.5 per cent in OECD-Europe and 15.6 per cent in the European Union – respectively 1060, 101, 198 and 147 GW. HP generation 1

2

3 4

Ludovic Gaudard is Research Associate at the University of Geneva and Visiting Fellow at the London School of Economics. He holds a PhD in Interdisciplinary Studies (Economics and Environmental Sciences), a Masters degree in Environmental Sciences and a Bachelor’s degree in Physics. His research focuses on the impact of climate change, new technologies (such as smart grid) and market liberalisation on hydropower, with regard to the physical, technical and economics aspects. He is used to integrating simulations, optimisation and econometrics with risk and uncertainty analysis. Franco Romerio leads the Energy, Policy and Economics group at the Institute for Environmental Sciences (ISE), University of Geneva. He holds a PhD in Economics and a Masters in History, both from the University of Geneva, as well as a postgraduate degree in Energy from the Federal Institute of Technology in Lausanne (EPFL). His research focuses on the organisation of energy policy and electricity markets, hydropower, nuclear energy and risk management in the field of energy. He teaches Energy Economics and Policy at the University of Geneva and at the EPFL. The authors thank the Swiss National Research Program 70 (Energy Turnaround) for its support. F. H. Knight, Risk, Uncertainty and Profit (University of Chicago Press, 1921).

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was respectively 3490, 322, 504 and 311 TWh.5 This data shows that HP provides a significant contribution to electricity supply. TECHNO-ECONOMIC AND ENVIRONMENTAL CHARACTERISTICS HP produces electricity by using kinetic energy from water. This energy activates the turbine, which in turn powers a rotor that generates electricity. Thanks to water reservoirs, it is possible to store electricity in the form of potential energy.6 Besides the distinction between small, medium and large installations, one should consider the main three types of hydropower plants (HPP), i.e. runof-river, storage and pumped-storage.7 The production of run-of-river plants depends on the water inflows. Their storage capacity is low or zero and they provide base or intermediate load. Conversely, storage power plants are able to follow the daily load curve. Furthermore, water reservoirs can be managed seasonally and even annually. Their energy efficiency is very high: around 90–95 per cent.8 Pumped-storage transfers energy from off-peak to peak hours. The efficiency of the whole cycle is lower, between 65 and 80 per cent, due to both turbine and pump losses combined.9 HP with reservoirs provides a significant contribution to ensuring the power system’s reliability in many regions. Flexibility is of the utmost importance. Thanks to their short starting time, these installations provide peak energy as well as reserves. In fact, most of the ancillary services can be supplied by hydropower.10 HP is a capital-intensive technology with long payback periods.11 To a large extent, costs depend on the sites where installations are built. The external costs and benefits of internalisation can make the difference. HP may actually have an important environmental impact despite the fact that it is a renewable resource.12 Flushing large reservoirs may affect rivers downstream. Hydropeaking, which is provoked by intermittent use of the reservoirs and causes rapid, strong discharge fluctuations, may distress aquatic organisms. The volume of water diverted from its natural watercourse may cause significant changes to the abiotic and biotic conditions in and around the river. Blocked

5

International Energy Agency, World Energy Outlook (IEA, 2013). J. Twidell and T. Weir, Renewable Energy Resources, 2nd edn (Taylor and Francis, 2006). 7 International Energy Agency, Technology Roadmap: Hydropower (IEA, 2012). 8 Eurelectric and VGB PowerTech, ‘Efficiency in electricity generation’ (2003), Union of the Electricity Industry – EURELECTRIC, VGB – Ref. 2003–030–0548. 9 H. Ibrahim, A. Ilinca and J. Perron, ‘Energy storage systems – characteristics and comparisons’, Renewable and Sustainable Energy Reviews 12 (2008), 1221–50. 10 L. Gaudard and F. Romerio, ‘The future of hydropower in Europe: interconnecting climate, markets and policies’, Environmental Science and Policy (37) (2014), 172–81. 11 International Energy Agency, Nuclear Energy Agency and Organization for Economic Cooperation and Development, ‘Projected costs of generating electricity’ (2010), available at www.iea. org/publications/freepublications/publication/projected_costs.pdf 12 World Commission on Dams, ‘Dams, ecosystem functions and environmental restoration’ (2000), available at www.unep.org/dams/WCD/report/WCD_DAMS%20report.pdf 6

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rivers disrupt the migration and breeding of fish. However, HP plants can be designed and managed to minimise their environmental impact. Fish ladders represent quite a remarkable achievement in this respect. MARKET LIBERALISATION AND NEW ENERGY POLICY In the 1990s, electricity markets were liberalised in the European Union, in some US states and in some other countries around the world. Generation, transmission and supply were unbundled to a certain extent. Wholesale and retail markets were opened to competition. The only exception to this move was represented by networks, as they are natural monopolies, but open access is granted by the regulator. New forms of regulation were implemented.13 This reorganisation has had an important impact on the hydropower companies, because now they have to deal with different types of risks and uncertainties that either did not exist or were far easier to manage at the time of the monopolies. Price fluctuations and volatility are the most quoted risks. Political and regulatory, as well as technological and environmental uncertainties, can, however, also jeopardise hydropower companies and projects directly or indirectly (through market prices). Another radical change is represented by new energy and climate policies, in particular in Europe, where the goal is to reduce dependence on fossil fuels and, in certain countries, to phase out nuclear energy. An interesting example is given by the feed-in tariff, created by some European countries (in particular Germany), to boost the take-off of new renewable energy.14 They in fact provoked a significant decrease in spot prices, and consequently impacted the profitability of HP. The decrease of the spread between peak and off-peak prices further affects HP plants with reservoirs. Several projects in the Alps have already been cancelled or postponed.15 The development of balancing and ancillary services’ markets may allow HP plants with reservoirs to rediscover lost profitability. These markets are used by the system operator to balance supply and demand in real time. HP plants with reservoirs should thus provide valuable reserves to the electricity system.16 The creation of capacity markets (capacity payments or requirements) is also considered, but they are quite controversial as they present various drawbacks (for instance, they can further depress the energy market).17 13

I. J. Pérez-Arriaga, Regulation of the Power Sector (Springer, 2013). F. Sensfuss, M. Ragwitz and M. Genoese, ‘The merit-order effect: A detailed analysis of the price effect of renewable electricity generation on spot market prices in Germany’, Energy Policy 36 (2008), 3086–94. 15 Swiss Federal Office of Energy, ‘Perspektiven für die Grosswasserkraft in der Schweiz. Wirtschaftlichkeit von Projekten für grosse Laufwasser- und Speicherkraftwerke und mögliche Instrumente zur Förderung der Grosswasserkraft’ (2013), available at www.energie-aktuell.ch/uploads/news/ Studie_Perspektiven_Grosswasserkraftwerke_20131212.pdf 16 D. S. Kirschen and G. Strbac, Fundamentals of Power System Economics (John Wiley & Sons, 2004). 17 C. Batlle and I. J. Pérez-Arriaga, ‘Design criteria for implementing a capacity mechanism in deregulated electricity markets’, Utilities Policy 16(3) (2008), 184–93. 14

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Besides market design, HP profitability depends on the future configuration of the electric system, which also represents a big source of uncertainty. PV and wind power are among the most promising technologies. PV generation is characterised by a day-night rhythm that is correlated with the daily load curve. Wind power can stay constant over several days or fluctuate over hours. PV and wind generation also vary seasonally. Thanks to its flexibility, HP with reservoirs can compensate for these fluctuations and provide back-up capacity. However, the integration of wind and solar parks situated in different areas will decrease PV and wind’s intermittency. Furthermore, the levelling-out of daily loads through demand-side management, namely peak shaving and valley filling, will reduce the need for flexibility. Last but not least, new electricity storage technologies may provide alternative solutions. One should recognise that taken together these elements represent a challenge for HP. CLIMATE CHANGE AND WATER RIGHTS Climate change (CC) will affect natural runoffs and sedimentation, and in turn HP’s potential and generation. The literature shows that world hydropower potential will slightly increase by 2050.18 In Europe and the United States, the potential will decrease by 6 per cent and 2 per cent respectively.19 However, during a transitional period, glacier retreats could cause an increase in HP output. In certain regions, for instance Scandinavia, output may increase by 15 to 30 per cent by 2070.20 In addition to annual runoff, its monthly distribution will also affect the output. One should stress that it is difficult to generalise as every region and power plant possesses its own characteristics.21 For instance, a glacier retreat may create new lakes that may be used as reservoirs. Furthermore, installations with reservoirs are less vulnerable than run-of-river power plants. Last but not least, a smart reservoir’s management can mitigate the negative effects of CC.22 Sedimentation affects HP installations by filling up reservoirs, obstructing intakes and deteriorating turbines. It’s generally accepted that 1 to 2 per cent of the reservoir capacity is lost every year worldwide.23 In Europe and the United States, the fill rate is at the lower end of the range, at about 0.7 per cent per year.24 18

B. Hamududu and A. Killingtveit, ‘Assessing climate change impacts on global hydropower’, Energies 5 (2012), 305–22. 19 B. Lehner, G. Czisch and S. Vassolo, ‘The impact of global change on the hydropower potential of Europe: a model-based analysis’ Energy Policy 33 (2005), 839–55; US Department of Energy, Effects of Climate Change on Federal Hydropower, Report to Congress (2013). 20 Lehner et al., ‘The impact of global change on the hydropower potential of Europe’. 21 L. Gaudard, F. Romerio, F. Dalla Valle, R. Gorret, S. Maran, G. Ravazzani, M. Stoffel and M. Volonterio, ‘Climate change impacts on hydropower in the Swiss and Italian Alps’, Science of the Total Environment (493) (2014), 1211–21. 22 L. Gaudard, M. Gilli and F. Romerio, ‘Climate change impacts on hydropower management’, Water Resources Management 27 (2013), 5143–56. 23 T. Jacobsen, ‘New sediment removal techniques and their applications’ Hydropower & Dams (1998), 135–46. 24 A. Schleiss, ‘Reservoir sedimentation endangers the sustainable use of hydropower’, in P. Brobrosky, Encyclopaedia of Natural Hazards (Springer, 2013).

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The right to use water resource to generate hydroelectricity is granted by the state or by regional or local authorities. It can take the form of a concession (entailing vested rights), licence, permit or authorisation. The duration spans from 1-2 decades to an unlimited period of time. Obligations concerning residual waters, royalties, local communities’ compensation and so on may be defined within this framework.25 Water right renewal represents a hot topic in some countries due to national and local, public and private interests.26 From the European Commission’s perspective, water rights should be awarded through a competitive and transparent process, instead of on the basis of a ‘preferential right’, granted to the ‘national champion’ or other public companies. In fact, some countries have been subject to infringement procedures on these issues. ‘Preferential right’ to public bodies was also a controversial issue in the United States in the 1970s, when HP licences, granted in the 1920s, began to expire.27 Some states and municipalities applied for renewal on this basis. Private companies were opposed. A large number of Acts, court decisions and administrative rulings were issued in this respect. The preferential clause is still applied by the Federal Energy Regulatory Commission (FERC), which has the responsibility of licensing and relicensing.28 CONCLUSION HP has significant potential worldwide. Energy policy and market design should not hinder this valuable resource. However, stringent rules should be implemented in order to avoid economic, social and environmental disruptions. One should not seek to address long-term risks and uncertainties with short-term visions and attitudes. HP represents a test bench to prove if public and private decision-makers are still able to build in the long term. Flexible solutions with respect to plant design, concessions, licences, permits and regulations may offer the most appropriate approach.

25

F. Romerio, ‘Regional policy and hydroelectric resources: the case of a Swiss Mountain Canton’ (2008) Journal of Alpine Research 1 (2008), 79–89. 26 J.-M. Glachant, M. Saguan, V. Rious, S. Douguet and E. Gentzoglanis, ‘Regimes for granting rights to use hydropower in Europe’, European University Institute (2014), available at http:// cadmus.eui.eu/bitstream/handle/1814/33653/2014_RR_Hydropower.pdf?sequence=1 27 D. H. Cole, ‘The federal power act’s controversial municipal preference: The Merwin dam dispute and legislative proposals to amend federal hydro-licensing procedures’, Energy Law Journal 7 (1987), 373–87. 28 United States General Accounting Office, ‘The evolution of preference in marketing federal power’, (GAO/RCED-00-127) (2000).

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RENEWABLE ENERGY PRODUCTION IN MARINE AREAS AND COASTAL ZONE: THE NORWEGIAN MODEL Sigrid Eskeland Schütz1

INTRODUCTION Sea and coastal zones are attractive for renewable energy production, but are under increased pressure from human activity. With its more than 100,000 km of coastline, Norway has good prospects for renewable energy production in marine areas and the coastal zone. Renewable energy sources could be onshore and there is potential for offshore windmill farms and also osmosis (or waveenergy) power plants, the latter of which are still at a more experimental stage. These installations and associated infrastructures require the use of land or marine space,2 with potential conflicts with outdoor recreation, transport, fishery and wildlife. Stakeholders differ according to whether the activity takes place on land, close to the shore or out in the open sea: so too does the Norwegian regulatory framework for renewable energy production. The increased pressure on the marine environment has led to changes in policy and law, at international, regional (EU) and national level. More precise management principles have been developed from overarching principles such as integrated coastal zone management and ecosystem-based management. Knowledge-based management, impact assessment, cumulative impact and 1

2

Professor dr juris Sigrid Eskeland Schütz is a licensed solicitor (2001) and dr. juris (2008) whose thesis is on the Norwegian planning and building act and implementing EU directives on environmental impact assessment. In 2009–10 she was member of a government-appointed committee on toxic substances that looked at measures needed to fulfil the obligations of the Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR). Her interests are (EEA) environmental law, land use planning, coastal zone management and marine spatial planning. She is head of the research group for natural resource law, environmental law and development law. This includes areas under and on the seabed, in the water column or above sea level.

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holistic approaches, access to information and public participation in decisionmaking are core principles managing ecosystems, areas and conflicts related to change in the spatial distribution of human activities.3 We will focus on two characteristics of the Norwegian management model for renewable energy production in marine areas. A SYSTEM FOR LAND AND A SYSTEM FOR THE SEA An important characteristic of the Norwegian model is the shift in regulation of resource exploitation and use of land and sea areas as one moves from land out to the open sea. On land and in internal waters, the elected municipality councils and county councils are, under the 2008 Planning and Building Act (PBA),4 delegated key tasks in land use management which are an essential part of local self-government in Norway. Assignment of power to these institutions safeguard the values of local and regional self-government. Decentralised power also fulfils the ecosystem approach, as the approach often ‘will imply decentralisation to the level of local communities’ with the ‘opportunity to assume responsibility and the capacity to carry out the appropriate action’.5 The stakeholders are typically municipalities and private owners of land, seabed or water column subject to private property rights. The open sea, on the other hand, has no decentralised institutions for decision-making, no private owners, no municipal or regional authorities, but it does have marine stakeholders. In principle, it is within the municipality councils’ autonomy to decide on land use, that is, whether an area should be designated for outdoor recreation, industry, energy production and so on. Councils have this competence not just out to the landward of the baselines,6 but, since 2008, to one nautical mile out to sea.7 The municipal master plan can give an overview of land-use purposes, but the applicant needs to develop a zoning plan for major building and construction projects outlining how the land will be used in the specific project.8 The zoning 3

4 5

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These are first and foremost procedural requirements. Substantive environmental requirements like environmental quality norms are prerequisites for management, but will not be analysed further. Quality norms are particularly developed for ecological and chemical status/environmental status under the EU Water Framework Directive, Directive 2000/60/EC establishing a framework for Community action in the field of water policy, and the Marine Strategy Framework Directive, Directive 2008/56/EC establishing a framework for community action in the field of marine environmental policy. Norway is in a special position because it is not an EU member, but rather a member of the EEA agreement, leaving some parts of the EU regulation outside the agreement, such as the Marine Strategy Framework Directive. The Norwegian Planning and Building Act, Act no. 71 of 27 June 2008. Fifth Ordinary Meeting of the Conference of the Parties to the Convention on Biological Diversity, May 2000, Decision V/6, Sec. C, Operational guidance for application of the ecosystem approach. Baselines are the normal lines for measuring the breadth of the territorial sea, following the low-water line of the state, but, as for a country like Norway, with a deeply indented coastline, straight baselines joining appropriate points may be used. See 1982 United Nations Convention on the Law of the Sea Sec. 5 and 7. See PBA Sec. 1-2. This is due to the implementation of the Water Framework Directive under the EEA-agreement. See PBA Sec. 12-1.

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plan is often adapted in parallel processes with the granting of licences for other aspects of the activity, such as pollution, and all processes are open for public and stakeholder participation. Local self-government is nevertheless conditional. The state can have a strong interest in the development, and in municipal landuse planning, and despite law, regulation, governmental guidelines and provisions or regional plans, it can give the county, a neighbouring municipality or affected national expert authorities competence to ‘object’ to the local plan.9 Unless the municipality takes the objections into account, the contested part of the plan shall be sent to the Ministry of Local Government and Modernisation for approval.10 Energy projects have been a challenge, and important exceptions from following these procedures are made for effective planning of the energy supply, which is a national interest. Exceptions in PBA Sec. 1-3 leaves the 1990 Energy Act as the fulcrum for national or regional energy-power lines.11 For energy production plants, both PBA and the Energy Act apply. An important exception from the PBA is that a zoning plan does not need to be developed for the plant.12 And to further safeguard national interest, the Ministry of Petroleum and Energy can step in as planning authority.13 The Energy Act places the competence to accept energy projects like windmill farms with central government, although it is now delegated to the state agency, the Norwegian Water Resources and Energy Directorate (NVE). Still, the affected municipality councils have a strong position in the process, reflecting the importance of local self-government. The municipalities have the competence to object to a development consent.14 Unless the NVE, after negotiations, takes the objection or appeal into account, the concession is sent to the central government ministry for approval. With regard to the open sea, the state’s competence to manage is absolute. As the potential for renewable offshore energy production developed, the 2010 Offshore Energy Act was adopted,15 reflecting the fact that the sea is regulated differently from the land, both in EU and in national law.16 The Act regulates renewable energy production seaward of the baselines, and a concession from NVE is required for renewable energy projects.17 9

See PBA Sec. 5-4. See PBA Sec. 5-6. 11 The Norwegian Energy Act, Act no. 50 of 29 June 1990. 12 See PBA Sec. 12-1. 13 See PBA Sec. 6-4 and the Energy Act Sec. 3-1. 14 See the Energy Act Sec. 2-1, para. 7. Here the provisions concerning objections in PBA Sec. 5-4 to 5-6 apply to the extent appropriate to the processing of applications for licences under Sec. 3-1 of the Energy Act. 15 The Norwegian Offshore Energy Act, Act. no. 6 of 21 April 2010. 16 The EU member states have, for instance, accepted that EU has competence to regulate marine spatial planning, but not spatial planning on land, nor in the coastal zone. See the proposal for a Directive establishing a framework for maritime spatial planning and integrated coastal zone management in COM (2013) 133 final, and the final adopted directive leaving out the coastal zone, Directive 2014/89/EU establishing a framework for maritime spatial planning. 17 See the Offshore Energy Act Sec. 1-2 (scope) and 3-1 (concession). 10

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TIERING STRATEGIC PLANNING WITH PROJECT CONCESSIONS The ecosystem approach might require new arrangements or ways of organisation for institutions involved in decision-making.18 An important development in Norwegian management of renewable energy during the last twenty years has been the adaptation of more strategic and holistic instruments for management of areas and resources, compared to the traditional (sectorial) licensing system. It is thus characteristic for the Norwegian management regime to have a vertical management hierarchy, which tiers strategic planning with downstream project concessions. Experience has shown that traditional licensing procedures are inadequate in evaluating realistic alternatives for future development and in addressing cumulative impacts, and that ‘[t]he issue of alternatives can only be properly assessed at the plan and programme level’.19 Norway has no national strategy for spatial distribution of windmill farms onshore and in the coastal zone. Regional plans can be adapted in accordance with the PBA. On a voluntary basis, the elected county councils in each of Norway’s nineteen councils can develop thematic plans based on perceived regional planning needs.20 Some regions have taken the opportunity to develop such plans, but the Ministry has not used the opportunity to make such plans mandatory.21 The specific need for a regional plan is justified by the fact that windmill parks require large areas, often crosscutting municipal borders or being visible across them. The strategic plans are knowledge-based. They build on relevant knowledge of infrastructure, cultural heritage, biological diversity (such as birdlife) and, of course, the wind itself. Regional plans are not decisive for the following municipal land use planning,22 nor for consent given by the NVE in accordance with the Energy Act. The vertical management hierarchy is not strict. Even so, municipal land use planning, unlike a regional plan, can give the county, a neighbouring municipality or affected national expert authorities competence to object to the local plan: the contested part of the plan must then be approved by the Ministry. Neither regional windmill plans nor municipal master plans are decisive in relation to concessions given by the NVE in accordance with the Energy Act, but they could be grounds for filing objections against the consent. In the open sea, the holistic and strategic perspective is implemented in the Offshore Energy Act in a formal process for the ‘opening of areas’ with a view to the granting of licences.23 This has for many years also been the system for 18

Fifth Ordinary Meeting of the Conference of the Parties to the Convention on Biological Diversity, May 2000, Decision V/6, Sec. B 6. 19 Recognised in the preparatory works of the SEA-directive, Directive 2001/42/EC of 27 June 2001 on the assessment of the effects of certain plans and programmes on the environment, see COM 96(511), p. 5. Under the directive, impact assessments should be prepared for plans and programmes for areas like fisheries, energy, transport, water management, and town and country planning, and which set the framework for future development consent for projects. 20 Cf. PBA Sec. 3-4, 3-6 and 8-1 and Sec. 8-3, third paragraph for impact assessment. 21 See Sec. 8-1 second paragraph. 22 See Sec. 8-2 23 The Offshore Energy Act, Sec. 2-2.

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oil exploitation.24 The licence can only be granted for projects like windmill farms, if they are situated in areas formally ‘opened’ for this activity. Here the vertical management hierarchy is strict, tiering strategic planning with downstream project concessions. In 2009, the Ministry of Petroleum and Energy appointed a group of representatives from state agencies, led by the NVE, to delineate Norwegian maritime areas that should be a part of the opening process, and suggested fifteen areas for strategic impact assessment.25 The impact assessment sets out information relevant to the decision as to whether to open the area for activity. The areas are divided into sub-areas: those that are recommended for opening now; those that should not be opened due to an existing technological situation; and those that could be opened at a later stage. The decision whether to open areas in accordance with Sec. 2-2 has not yet not been taken by the government. THE CROSS-CUTTING ECOSYSTEM APPROACH Legal lines drawn to define territorial borders or a shift from a land-based system to a sea-based system should not hinder an ecosystem-based approach to a specific problem. In Norway’s deeply indented coastline, wind, birdlife and marine traffic nullify the relevance of baselines in the context of strategic management of marine windmill parks. The Offshore Energy Act opens the possibility to include waters on the landward side of the baselines.26 In the process of opening areas for renewable energy production offshore, several of the areas are wholly or partly placed inside the baselines, which may lead to an extension of the geographical scope of the legislation itself to areas both outside and inside the baselines in question.

24

The Norwegian Act relating to petroleum activities, Act. no. 72 of 29 November 1996, Sec. 3-1. Documents or summaries are available in English at www.nve.no/en/Planning-for-offshore-windpower-in-Norway 26 Regional plans for windmill farms established by the county councils do not include projects in marine areas. 25

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THE GEOPOLITICS OF CLEAN ENERGY: RE-ENGAGING WITH RUSSIA THROUGH RENEWABLE ENERGY COOPERATION Anatole Boute1

EU-Russian relations have reached a low point in the context of the Ukrainian crisis, with consequences for the European Union’s external energy security.2 The sanctions imposed on Russia in reaction to ‘Russia’s actions destabilizing the situation in Ukraine’3 have affected cooperation in the energy sector. The deteriorating EU-Russian relations have generated calls to strengthen the ‘further diversification of energy supply and supply routes’ to the EU.4 However, given high energy import levels from Russia,5 ‘further diversification’ is unlikely to result in the EU’s energy independence from Russia. Furthermore, energy independence would not be economically justifiable, taking into account the cost of this policy choice in 1

2

3

4

5

Anatole Boute, PhD in Law (2011, University of Groningen), is an Associate Professor at the Chinese University of Hong Kong and Legal Advisor to the International Finance Corporation (World Bank Group). He has been admitted to the Brussels Bar where he practised in the field of energy and environmental law. He is the author of Russian Electricity and Energy Investment Law (Brill Nijhoff, forthcoming). On the implications of the Ukrainian crisis for EU-Russian energy relations, see S. Pirani, J. Henderson, A. Honoré, H. Rogers and K. Yafimava, ‘What the Ukraine crisis means for gas markets’, Oxford Institute for Energy Studies (2014), available at www.oxfordenergy.org/2014/03/whatthe-ukrainian-crisis-means-for-gas-markets Council Regulation (EU) No 833/2014 of 31 July 2014 concerning restrictive measures in view of Russia’s actions destabilising the situation in Ukraine, OJ (2014) L 229/1. Transport, Telecommunications and Energy Council Meeting, ‘Council conclusions on energy prices and costs, protection of vulnerable consumers and competitiveness’, Council Meeting, 13 June 2014, available at www.consilium.europa.eu/uedocs/cms_Data/docs/pressdata/en/trans/143198.pdf See EU Commission Staff Working Document, ‘In-depth study of European energy security accompanying the communication on European energy security strategy’ (SWD(2014) 330 final/3), 2 July 2014.

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connection to the mutual benefits characterising the close geographic proximity to the EU of Russia’s huge energy reserves. Given their intrinsic energy interdependence, the EU and Russian partners need to develop new cooperation approaches to re-engage with each other and re-establish mutual trust. This chapter argues that renewable energy provides a unique basis to re-initiate the EU-Russian energy dialogue. ‘Clean energy geopolitics’ – a largely ignored component of external energy relations – could be a way for the EU to rebuild ties with Russia, to the benefit of EU’s long-term energy and environmental security. EU law lays the basis for cooperation between the EU and third countries in the field of clean energy. The EU Renewable Energy Directive6 establishes binding national renewable energy targets, and at the same time introduces cooperation mechanisms to allow these mandatory targets to be reached in the most cost-efficient way. With ‘joint projects with third countries’,7 EU member states can support the construction of renewable energy installations in non-EU countries. Electricity generated by these installations and ‘consumed’ in the EU will count towards the national targets of the member state concerned. Joint projects with third countries require the physical export to the EU of an amount of electricity which ‘equates’ to the power produced from renewable energy sources abroad. This mechanism thus only applies to countries with a large renewable energy resource base that can easily be interconnected to the EU. Russia shows a large renewable energy resource base in geographic proximity to the EU. The Unified Energy System of Russia is interconnected to the electricity network of Finland and the Baltic countries. Russia thus represents unique opportunities for cooperation with the EU in the field of clean energy.8 These opportunities have been recognised at the highest political level.9 However, no concrete initiatives have been undertaken to implement this scheme – with the Ukrainian crisis affecting any short-term prospect of positive development in this field. Joint development of Russia’s renewable energy potential represents important mutual benefits should the EU and Russia decide to reinitiate cooperation with each other. Taking into account the increasing ‘Europeanisation’ of renewable energy policy in the EU,10 the EU – instead of its member states – would have to be the driving force behind this initiative at the 2030 horizon.

6

Directive 2009/28/EC (23 April 2009) on the Promotion of the Use of Energy from Renewable Sources and Amending and Subsequently Repealing Directives, 2001/77/EC and 2003/30/EC, OJ (2009), L 140/16. 7 Articles 9-10 EU Renewable Energy Directive. 8 See A. Boute and P. Willems, ‘RUSTEC: greening Europe’s energy supplying by developing Russia’s renewable energy potential’, Energy Policy 51 (2012), 618–29. 9 See G. Oettinger and A. Novak, ‘Roadmap EU-Russia energy cooperation until 2050’ (March 2013), available at http://ec.europa.eu/energy/sites/ener/files/documents/2013_03_eu_russia_roadmap_2050_ signed.pdf 10 See EU Commission, ‘A policy framework for climate and energy in the period from 2020 to 2030’, 22 January 2014 (COM(2014) 15 final).

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Cooperation in the field of clean energy provides an opportunity for the EU to work with Russia on issues which are less strategically sensitive than traditional upstream energy projects. This could contribute to the creation of a certain degree of mutual trust and understanding between the EU and Russian partners.11 This idea is not new. According to Handke and de Jong’s 2007 study on EU-Russian energy relations, ‘[i]n the long term, helping to enhance Russia’s energy efficiency may be an effective way to improve relations’.12 In the context of the deteriorating relations between the EU and Russia, it is necessary to focus on the operationalisation of this external energy policy mechanism to achieve the mutual benefits that characterise the EU-Russian energy relation. From a EU decarbonisation perspective, Russia’s large renewable energy resource base holds the potential to contribute in a cost-efficient way towards the EU target of 27 per cent renewable energy by 2030. Given excellent wind conditions in direct geographic proximity to the EU (in particular in the north-west of Russia), onshore wind projects in Russia present cost benefits in comparison to locations in the EU. Moreover, the large size of the Russian electricity sector presents interesting market opportunities for EU electricity and renewable energy equipment companies. By helping to harness this commercial potential, the EU could open new markets for its clean energy industry – a key component of the EU’s broader external energy efficiency policy.13 Besides these strategic, geopolitical and commercial aspects, there are compelling ethical reasons for the EU to be involved in the development of Russia’s renewable energy resource basis.14 The EU, to an important extent, has a moral responsibility regarding greenhouse gas emissions in the Russian energy sector. First, EU member states (mainly Finland) import electricity produced from inefficient thermal plants in Russia. According to the IPCC Guidelines for National Greenhouse Gas Inventories,15 greenhouse gas emissions remain with the producing country – that is, Russia – despite the fact that these carbonintensive goods are exported to and consumed in the EU. Second, to increase the amount of natural gas available for export, Russia announced that it will 11

A. Boute, ‘The European foreign energy efficiency policy: securing external energy supply in a carbon-constrained world’, in C. Kuzemko, A. V. Belyi, A. Goldthau and M. F. Keating (eds), Dynamics of Energy Governance in Europe and Russia (Palgrave Macmillan, 2012), pp. 66–85. 12 S. Handke and J. de Jong, ‘Energy as a bond: relations with Russia in the European and Dutch context’, Clingendael International Energy Programme (2007), available at www.clingendael.nl/ publications/2007/20070900_ciep_energy_handke.pdf, 40. 13 See EU Commission, ‘Energy efficiency or doing more with less’, Green Paper, 22 June 2005, COM (2005) 265 final, 28 and 38. 14 See A. Boute, ‘The EU’s shaping of an international law on energy efficiency’, in D. Kochenov and F. Amtenbrink, The EU’s Shaping of International Law (Cambridge University Press, 2013), pp. 238–60. 15 D. Gómez and J. Watterson, ‘Stationary Combustion’, 2006 IPCC Guidelines for National Greenhouse Gas Inventories, available at www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/2_Volume2/V2_2_ Ch2_Stationary_Combustion.pdf

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stimulate the use of coal for electricity production.16 The emissions associated with the increased use of coal represent in a certain sense the carbon cost of EU’s external energy supply.17 Third, Russian oil exported to and consumed in the EU is characterised by the carbon intensity of its production process, taking into account the practice of gas flaring in Russia.18 Influencing the development of renewable energy in Russia can be seen as a way for the EU to mitigate the carbon impact of its energy import and consumption patterns. The promotion of clean energy exchanges with Russia could face opposition for reasons of security of supply related to the EU’s dependence on Russian energy. In Finland, comparable arguments have, for instance, been invoked to block electricity interconnection plans with Russia.19 These arguments are increasingly sensitive in the context of the Ukrainian crisis. However, this possible opposition to EU-Russian cooperation in the field of clean energy would ignore the fact that renewable energy imports from Russia can contribute to the EU’s energy security strategy by diversifying the type of energy imported from Russia.20 Moreover, electricity cannot easily be stored and therefore does not face the same interruption risks as gas or oil supply.21 Even if an interruption occurred, the damage on the EU economy would be limited, taking into account that the EU would already have the necessary back-up capacity in place to compensate for the variability of wind. Internalising the carbon cost associated to the current import levels of Russian electricity by the EU does not require additional EU-Russian interconnection capacity. ‘Greening’ Russia’s electricity exports to the EU is possible provided an amount of electricity that is equivalent to the amount of clean energy produced from new investments in Russia is nominated at the EU-Russian border. This nomination-based ‘greening’ approach meets the ‘consumption’ requirements of the EU Renewable Energy Directive.22 However, it is limited to the existing volumes of Russian-EU electricity exchanges. 16

See Government of the Russian Federation, Resolution No. 1715-r of 13 November 2009 on Russia’s Energy Strategy until 2030 (Rasporiazhenie Pravitel’stva RF ‘Ob Energeticheskoi strategii Rossii na period do 2030 goda’, Sobranie Zakonodatel’stva Rossiiskoi Federatsii (30 November 2009), No. 48, item 5836). 17 See K. Rosner, ‘Dirty hands: Russian coal, GHG emissions and European gas demand’, Journal of Energy Security (August 2009), available at www.ensec.rog; Jefferson Institute, ‘Improving energy relations with Russia: the roles of energy efficiency and alternative energy’, Jefferson Institute (2009), available at www.jeffersoninst.org/publications/improving-energy-relationsrussia-roles-energy-efficiency-and-alternative-energy, 3–5. 18 J. Loe and O. Ladehaug, ‘Reducing gas flaring in Russia: gloomy outlook in times of economic insecurity’, RussCasp Working Paper, FNI/Pöyry, Oslo (2012). 19 V. Lappalainen, Proposed Finland–Russia Interconnector Rejected, OGEL 1 2007, available at www.ogel.org/article.asp?key=2380 20 According to the EU Commission, Commission Staff Working Document Accompanying Communication on Renewable Energy: a Major Player in the European Energy Market, 6 June 2012, SWD 164 Final (2012), even if the energy is still imported, the diversification in the types of energy imported would contribute to improving EU energy security. 21 J. Lilliestam and S. Ellenbeck, ‘Energy security and renewable electricity trade – will Desertec make Europe vulnerable to the energy weapon?’, Energy Policy 39 (2011), 3380–91. 22 Boute and Willems, ‘RUSTEC: greening Europe’s energy’, 627.

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Developing new interconnection capacity would be needed to enable the large-scale deployment of Russia’s huge renewable energy resource basis located in geographic proximity to the EU. Cooperating towards the realisation of such an ‘EU-Russian clean energy bridge’ would send a strong signal of renewed partnership and joint commitment towards the achievement of the mutual benefits characterising the EU-Russian energy relation.

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TALKING ABOUT SHALE IN ANY LANGUAGE Alison Peck1

In 2012 and 2013, farmers in the Polish town of Żurawlów occupied a Chevron shale gas concession for 400 days, demanding that the company demonstrate its legal bona fides before beginning work. The farmers succeeded in stopping the work temporarily based on both an EU law protecting migratory birds and procedural violations in Polish environmental impact review.2 Although Chevron has expressed a desire to work cooperatively with local communities, Żurawlów residents were disappointed by the tenor of communications between the parties. According to one local news source, Chevron representatives left the room when television cameras appeared during a meeting between Żurawlów residents and Chevron representatives prior to seismic testing in January 2012.3 After Chevron had been stopped from conducting work on the concession in June 2013, Żurawlów residents questioned Chevron’s attempt to construct a fence around the area. Residents told reporters that a Chevron employee responded, ‘It’s none of your business. What if we want to plant carrots?’ Chevron issued a statement saying, ‘Chevron holds all necessary agreements and permits to start work in this area. We have every right to use the leased land. We want to put up a fence around it.’4 1

2

3 4

Alison Peck is Professor of Law at West Virginia University, in the heart of the Marcellus Shale basin. She teaches and writes about natural resources, administrative process and environmental democracy, both US and international, with special focus on agriculture and energy. Previous articles include ‘Does regulation chill democratic deliberation? The case of GMOs’, Creighton Law Review 46(4) (2013), 653–705, and ‘Sustainable development and the reconciliation of opposites’, St Louis University Law Journal 57 (2012), 151–84. K. Domagalska, ‘Local residents challenge US company’s shale gas exploration plans in Poland,’ BBC International Reports (Europe) (from Gazeta Wyborcza website) (26 June 2013). Ibid. Ibid.

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Nearly 4,500 miles from Żurawlów, in February 2014, a Pennsylvania state trooper visited the home of anti-fracking activist Wendy Lee, according to a news report.5 Lee told a reporter that the state trooper, identified as Michael Hutson, came to her home after Lee and other activists visited a compressor station, took photos and left when security guards asked them to. According to Lee, Hutson ‘asked her if she knew anything about pipe bombs’.6 Hutson declined to comment on the story, but the news source reported that it had obtained documents identifying Hutson as part of the Marcellus Shale Operators’ Crime Committee, a group organised to share intelligence between law enforcement and the gas industry.7 Previously, in 2010, a Pennsylvania state agency had contracted with a security firm, the Institute of Terrorism Research and Response, to produce and distribute reports suggesting that a citizen coalition monitoring gas drilling was engaged in terrorist activity.8 After a lawsuit was filed by the group, Gas Drilling Awareness Coalition, the director of the agency resigned in connection with the activity and the agency was dissolved.9 In both the European Union and the United States, jurisdictions with significant unconventional oil and gas resources have experienced public controversy about whether to develop those resources despite the potential for negative environmental and social impacts. The governments of Poland and Pennsylvania, among others, have endorsed it, citing economic development and energy independence. Governments of other jurisdictions, such as France and New York, have prohibited development, at least for the present. Whatever the stance of the central government, citizens in these jurisdictions and others have been vocal and mobilised, either in support or in opposition. Unconventional oil and gas, with all its potential risks and benefits, raises strong emotions, and public discourse about the technology tends to be heated at best, vitriolic at worst. This public discourse over shale development proceeds on two fronts. First, most legal systems offer a variety of mechanisms to solicit views of citizens in the process of setting energy law and policy. These ‘top down’ mechanisms include consultation procedures prior to granting concessions for exploration or development; formal hearings on potential new laws; notice and comment procedures on regulations governing industry practices or environmental protection; public input on environmental impact assessments; and civil society-designated seats on public advisory committees. 5

6 7 8

9

M. Cusick, ‘In fracking hot spots, police and gas industry share intelligence on activists’, StateImpact Pennsylvania (a collaboration of National Public Radio affiliate stations in WITF and WHYY of Pennsylvania) (2 February 2015), available at http://stateimpact.npr.org/pennsylvania/2015/02/02/ in-fracking-hot-spots-police-and-gas-industry-share-intelligence-on-activists Ibid. Ibid. Letter from Glenn M. Cannon, Director, Pennsylvania Emergency Management Agency, to Gas Drilling Awareness Coalition (18 December 2014), available at www.documentcloud.org/ documents/1507784-pema-letter-to-gdac.html Ibid.

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Second, outside these mechanisms that invite citizen input on central government decision-making, civil society or local interests may organise to protest the outcome of government decisions; to seek reversal of those decisions through legal and political mechanisms; to set policy at the local level that runs contrary to central policy; and to voice views where public input was not sought or was insufficiently considered. Examples of these ‘bottom up’ actions include public demonstrations; media campaigns; local bans, zoning restrictions or moratoria; and court actions to enforce substantive and procedural protection for the public. The way this discourse will proceed matters. As the Żurawlów and the Pennsylvania incidents reflect, discourse that begins from adversarial positions tends to divide the participants in the debate into ‘tribes’. Once tribal identifications are engrained, participants tend to defend these identity positions based on affiliation and to become deaf to the positions of others. Real communication becomes difficult as each side goes to war. Entities like the Marcellus Shale Operators’ Crime Committee, which start from a presumption of criminality, create infertile soil for true listening, understanding and arrival at meaningful compromise. Moreover, the greatest potential for abuse is not by activists but by the government, and parties backed by government support. Because the sovereign makes the first-order decisions over natural resource use and has a monopoly on legalised coercion and violence, the government and those it supports wield greater power in conflicts over resource use than do private citizens. The issue is ripe as jurisdictions on both sides of the Atlantic and elsewhere in the world with unconventional oil and gas resources debate whether and how to develop them. These jurisdictions have begun, after some missteps, to feel their way towards better engagement of civil society. In France, the government granted concessions for exploration without seeking comment from local elected officials,10 but after protests erupted, admitted that the award without consultations ‘was an error’.11 In April 2011, a French ministry report recommended, among other things, that the mining code be reformed to require public consultation before permits are granted for shale development,12 although the issue was mooted when the legislature banned the practice altogether in July of that year.13 In Poland, following the Żurawlów incidents, Chevron partnered with state-controlled PGNiG to improve its operations in the country,14 but has recently abandoned its exploration in the country in favour of ‘other 10

Conseil général de l’industrie de l’énergie et des technologies et conseil général de l’environnement et du développement durable (hereafter Conseil général), ‘Les hydrocarbures de roche-mère en France (rapport initial)’ (February 2011), 55, available at www.developpement-durable.gouv.fr/ IMG/pdf/007612-01_et_007612-03_rapports.pdf 11 D. Jolly, ‘Shale exploration hits bump in France’, International Herald Tribune (11 May 2011). 12 Conseil général, ‘Les hydrocarbures de roche-mère en France (rapport provisoire)’ (April 2011), available at www.developpement-durable.gouv.fr/IMG/pdf/Rapport_provisoire_sans_annexe.pdf 13 Loi no. 2011-835 du 13 juillet 2011, Journal Officiel de la République Française, p. 658. 14 S. Raszewski and J. Górski, ‘Energy security or energy governance? Exploration of shale gas in Poland’, Oil, Gas & Energy Law Intelligence 12(3) (2014), 10.

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opportunities in Chevron’s global portfolio’.15 In New York, the governor in late 2014 extended a moratorium based on regulators’ recommendations,16 an action that was to some extent redundant in light of the state’s highest court’s decision upholding local bans that were prevalent in parts of the state within the Marcellus basin.17 In Pennsylvania, the state supreme court in late 2013 struck down provisions of a state law that prohibited local jurisdictions from passing zoning restrictions affecting fracking.18 In late 2014, the state settled the lawsuit by the Gas Drilling Awareness Coalition and issued a public statement clarifying that the agency ‘has no reason to believe that GDAC . . . could fairly be characterised as a “terrorist organisation” and that the organisation ‘has done nothing more than engage in the exercise of its rights guaranteed by the United States and Pennsylvania constitutions’.19 The debate over shale will continue in the coming years in Pennsylvania, Poland, New York, France, West Virginia, Germany, South Dakota and the UK, as well as in Argentina, South Africa, Brazil, China and elsewhere. Ample time remains in most jurisdictions to learn from early mistakes; to listen and respond to civil society’s calls for inclusion in the process; and to identify legal mechanisms that governments may use to transfer a meaningful degree of power to civil society to afford a fair and honest debate.

15

S. Reed, ‘Chevron abandoning shale project in Poland’, International New York Times (31 January 2015). 16 T. Kaplan, ‘Citing health risks Cuomo bans fracking in New York State’, The New York Times (17 December 2014); New York State Department of Health, ‘A public health review of high volume hydraulic fracturing for shale gas development’, available at www.health.ny.gov/press/ reports/docs/high_volume_hydraulic_fracturing.pdf 17 Wallach v. Town of Dryden, 22 N.Y. 3d 1050 (2014). 18 Robinson Twp, Washington County v. Commonwealth of Pennsylvania, 623 Pa. 564 (2013). 19 Letter from Glenn M. Cannon, Director, Pennsylvania Emergency Management Agency, to Gas Drilling Awareness Coalition (18 December 2014), available at www.documentcloud.org/ documents/1507784-pema-letter-to-gdac.html

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THE SHALE REVOLUTION, FRACKING AND REGULATORY ACTIVITY IN THE US: A POLICY DIVIDED James W. Skelton, Jr1

On 16 June 2014, the author made a presentation at the University of Houston Law Center to a group of touring Iraqi journalists, whose trip was sponsored by the International Center for Journalists. The purpose of the speech was to provide the journalists with an overview of the US oil and gas industry with an emphasis on two issues: (1) the remarkable increase in production that had occurred due to the usage of horizontal drilling and hydraulic fracturing as methods of enhancing the production from shale formations; and (2) the status of efforts to regulate and even prohibit the use of one of those widely used production methods, namely hydraulic fracturing, or fracking. Fracking is the process of injecting sand, water and chemicals into shale rock formations to crack them open and release the hydrocarbons inside. One of the predictions the author made, of course, was that the price of oil would eventually decrease due to such a marked increase in supply. By 20 June 2014, the price of a barrel of West Texas Intermediate (WTI) crude oil reached its peak at $107.26,2 while Brent Blend crude oil was priced at $114.81 per barrel.3 1

2

3

James W. Skelton, Jr has practised law for nearly forty years, primarily specialising in international and domestic petroleum transactions. He worked for Conoco/ConocoPhillips for twentyeight years, most of which were spent handling upstream international oil and gas transactions. After retiring in 2008, he re-entered private practice and also began teaching at the University of Houston Law Center, where he is Adjunct Professor of Law. He has published thirteen articles and two book reviews in legal periodicals, made presentations at fourteen legal conferences in Houston, Dallas, London and Moscow, and co-authored the textbook Doing Business in Emerging Markets: a Transactional Course (Foundation Press, 2014). R. Holywell, ‘Falling oil prices lower the boom,’ San Antonio Express News (2 February 2015), 4, available at www.expressnews.com/business/eagle-ford-energy/article/Falling-oil-prices-lowerthe -boom.html M. Rachon, ‘Crude oil futures finish higher amid Iraq supply disruption fears’, International Business Times (21 June 2014), 1, available at www.ibtimes.com.uk/crude-oil-futures-finishhigher-amid-iraqi-supply-disruption-fears.html

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No one could have predicted that the price of WTI would decrease to $43.46 per barrel on 17 March 2015, the lowest level since 11 March 2009.4 This represents an incredible plunge of 59.5 per cent. The decline in the price of Brent was nearly as dramatic, dropping to $51.48 per barrel on the same date, for a 55.1 per cent change.5 Who would have believed that in November 2014, despite the fact that oil prices were virtually in freefall, the members of the Organization of Petroleum Exporting Countries (OPEC) would decide, ‘in the interest of restoring market equilibrium’, to maintain its production level of 30 million barrels per day, even while recognising there ‘are indications of an extremely well-supplied market?’6 Only a cartel with such enormous market power would have the audacity to ignore the law of supply and demand in an attempt to force US oil companies to reduce shale oil production levels and postpone exploration activities in order to avoid potentially catastrophic economic losses. Reports of significant budget cuts by US oil companies became rampant by the end of 2014, and early in 2015 there seemed to be a new story every day about service companies that were laying off thousands of employees and idling hundreds of drilling rigs.7 For example, a total of 310,700 oil and gas jobs have already been lost, and the number of drilling rigs in use has fallen from 1,609 in October 2014 to 866 in mid-March 2015, a reduction of 46 per cent.8 While these figures are staggering enough, another problem has arisen in connection with storage capacity for excess crude oil production. A recent Energy Department report stated that production has risen to 9.4 million barrels per day, the highest level in decades, and that the amount of crude oil being held in storage tanks has risen to a record level of 448.9 million barrels.9 Throughout this period, of course, the movement by activists, state and local governments and federal agencies to limit or prohibit the use of fracking continued to gather momentum. Local and state governments are the primary regulators of oil and gas companies operating on private and state-owned land, which is where the vast majority of drilling activity and fracking occurs. At the local level, there has been a great deal of activity in terms of bans against fracking, such as the ordinance passed by the city of Dallas, Texas that prohibits drilling operations less than 1,500 feet from a house.10 In nearby 4

R. Meyers, ‘Surge of shale begins to slacken, government reports’, Houston Chronicle (18 March 2015), D1. 5 Ibid., D5. 6 See OPEC, ‘OPEC 166th meeting concludes’, Press Release (27 November 2014), available at www.opec.org/opec_web/en/press_room/2938.html, and T. Hirst, ‘OPEC votes not to cut production, oil prices plummet’, Business Insider (7 November 2014), available at http:// uk.businessinsider.com/opec-votes-not-to-cut-production-oil-prices-plummet-2014-11 7 See, for example, C. Eaton, ‘Drillers idle nearly 100 more drilling rigs’, Houston Chronicle (14 February 2015), D1. 8 R. Grattan, ‘Oil price drop dashes the industry’s optimism’, Houston Chronicle (14 March 2014), A13. 9 Ibid., A13. 10 R. Loftis, ‘Dallas OKs gas drilling rules that are among the nation’s tightest’ Dallas News (12 December 2013).

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Denton, the city enacted a moratorium on drilling permits that was designed to give the citizens time to ‘vote on an ordinance that would ban all hydraulic fracturing in the city’,11 which they did.12 Not surprisingly, there is a draft bill being circulated in the Texas House of Representatives that would ban cities and local jurisdictions from regulating oil and gas operations, ‘with the exception of surface spills’.13 On the state level, New York led the way by instituting a statewide moratorium on fracking in 2010 in order to block the development of the Marcellus Shale formation.14 Colorado took a different approach in 2014 when, despite industry opposition, it adopted rules ‘that directly regulate methane emissions’, and which has been described as ‘a major breakthrough and a bellwether for other states seeking to minimize air pollution’.15 The US government channels its federal regulatory efforts through the Environmental Protection Agency (EPA) and the Bureau of Land Management (BLM) of the Department of the Interior. An example of EPA regulatory action occurred in 2012 when it promulgated the New Source Performance Standards,16 which changed the way in which ‘flowback from hydraulically fractured natural gas is processed’.17 In order to control flowback, operators must use a technique called Reduced Emission Completions, also known as ‘green completions’.18 On 20 March 2015, the BLM promulgated the first major set of federal regulations on fracking, which only apply to public and tribal lands. According to the BLM’s news release, the final rule is designed to update the BLM’s thirty-year-old drilling regulations by: (1) requiring strong cement barriers between the wellbore and water zones; (2) requiring disclosure of the kinds of chemicals used in fracking within thirty days of completing fracking operations; (3) raising standards for interim storage of recovered waste fluids; and (4) requiring submission of more detailed information about pre-existing wells to enhance the BLM’s ability to evaluate and manage drill site characteristics.19 The BLM’s fracking rule was scheduled to become effective ninety days after its publication, which would have been 18 June 2015, barring any delay 11

B. Kroger and J. Newman, ‘Ten issues that lawyers can help the energy industry solve’, Houston Lawyer 12 (2014), 52. 12 N. Sakelaris, ‘Denton voters say no to fracking, becoming first Texas city to ban it’ Dallas Business Journal (4 November 2014), 2, available at www.bizjournals.com/dallas/news/2014/11/04/ denton-voters-say-no-to-fracking-becoming-first.html 13 K. Reeves, ‘The “Denton Ban:” Oil industry, anti-frackers take arguments to Texas Capitol’, Dallas Business Journal (23 March 2015), 2, available at www.bizjournals.com/dallas/news/2015/03/23/ the-denton-banoil-industry-anti-frackers-take-arguments-to texas-capitol.html 14 F. Krupp, ‘How to make fracking safer for the environment’, Foreign Affairs 15 (2014), 93. 15 Ibid., 19–20. 16 ‘Oil and natural gas sector: new source performance standards and national emission standards for hazardous air pollutants reviews’, Federal Register 77 (16 August 2012), 49,490. 17 J. Gray and C. Moreno, ‘The federal government seeks to exert control’, Houston Lawyer 20 (2014), 52. 18 Ibid., 21. 19 Bureau of Land Management News Release, 20 March 2015, available at www.blm.gov/wo/st/ en/info/newsroom/2015/march/nr_03_20_2015.html

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in the process.20 Such a delay occurred, however, when a lawsuit against the regulations was filed in the state of Wyoming’s federal court by two oil and gas industry groups, the Independent Petroleum Association of America and the Western Energy Alliance.21 According to the lawsuit, the federal rule is based on ‘unsubstantiated concerns’ and the groups claim that the ‘Interior Department “lacks the factual, scientific or engineering evidence necessary” to support the policy’.22 On 30 September 2015, the US District Court judge in that case issued a preliminary injunction blocking the imposition of the new rule until the case is resolved.23 On the other hand, some of the US private environmental groups are split on their evaluation of the fracking rule. For example, some have praised the final rule, claiming ‘it includes pressure testing each well before production begins, and would require millions of gallons of waste water be stored in tanks, rather than open pits’.24 Other groups claim ‘the rule falls short, pointing to fracking mishaps they said have led to contamination of local water supplies in communities from Wyoming to Pennsylvania’.25 The BLM has taken the position that the estimated cost of the implementation of the new rule would be ‘less than one-fourth of 1 percent of the cost of drilling a well’ based on an average well cost of $5.4 million.26 A representative of the Western Energy Alliance stated that the BLM’s ‘$5,500 a well cost estimate is laughable’; its own study, which was based on a prior proposal, found ‘projected added costs of $97,000 a well’.27 The industry clearly has a significantly different point of view from the BLM, which will undoubtedly lead to another series of competing studies and more delays. The year 2016 may prove to be decisive in terms of a more coherent and updated policy with respect to the regulation of fracking operations. It all depends on whether (1) the new federal rule becomes effective and (2) the individual states follow the new rule and pass similar regulations. As for the condition of the oil and gas industry itself, it appears that the low price scenario will continue and oil producers will be forced to muddle through and adapt to the new commercial and regulatory realities for the medium term.

20

Ibid. M. Drajem, ‘Oil industry meets first federal fracking rules with a lawsuit’, Bloomberg Business (21 March 2015), 4, available at www.bloomberg.com/news/articles/2015-03-/u-s-sets-firstfracking -rules -since-process-fueled-energy-boom.html 22 Ibid., 5. 23 B. Finley, ‘Federal judge blocks BLM rules for fracking on public lands,’ The Denver Post (30 September 2015), available at www.denverpost.com/news/ci_28901828/federal-judge-blocks -blm-rules-fracking-public-lands.html 24 Ibid., 5. 25 Ibid., 5. 26 Ibid., 5, note 19. 27 Ibid., 6, note 21. 21

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63

FRACTURED SYSTEMS: A MULTIPLE POLICY PROPOSAL FOR PROMOTING SAFE SHALE GAS DELIVERY IN THE UNITED STATES Caroline Cecot1

Deep shale formations in the United States have long been known to hold large quantities of gas and oil, but their low permeability made energy extraction challenging and previously unprofitable. In recent years, operators have combined two techniques to increase well productivity: horizontal drilling, which exposes more shale rock to the wellbore; and hydraulic fracturing (fracking), which injects large quantities of water mixed with chemicals and sand at high pressure to create and prop open tiny fractures that allow trapped gas and oil to flow into the wellbore.2 The newfound profitability of extracting energy from shale has generated a boom in the oil-and-gas industry and in many local areas with extensive drilling. But widespread shale development has highlighted outstanding uncertainty about its environmental, health and safety impacts – most prominently, its water-contamination risks – and the ability of current 1

2

Caroline Cecot earned her JD and her PhD in law and economics at Vanderbilt University in May 2014. Her research focuses on risk, administrative law, and energy and environmental regulation. Before going to Vanderbilt, Caroline worked as a research associate at the AEI-Brookings Joint Center for Regulatory Studies in Washington, DC for two years after graduating from Harvard University in June 2006 with an AB in economics magna cum laude. She was Vanderbilt’s 2014–15 Postdoctoral Research Scholar in Law and Economics and taught Risk and Environmental Regulation II. She is currently a law clerk to the Honorable Raymond J. Lohier, Jr, on the US Court of Appeals for the Second Circuit in New York, and plans to pursue a position in legal academia. US Department of Energy, ‘Modern shale gas development in the United States: an update’, National Energy Technology Laboratory Report, DE-FE0004002, Washington, DC (2013).

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institutions to deal with these impacts.3 States, the primary regulators of oil and gas extraction, face pressure from the industry, local communities and, in some cases, the federal government to strike the right balance between energy production and the health and safety of individuals and the environment – an elusive balance given the ongoing risk uncertainty. In this chapter, I outline some of the benefits and costs of shale development, focusing on natural gas extraction. I then argue that state regulators could better manage the risks to water from fracking activities by strengthening regulatory safeguards, incentivising research, clarifying tort responsibility and using insurance mandates to ensure compensation and remediation. THE PROMISES AND PITFALLS OF SHALE GAS Natural gas provides low-cost energy for individuals, households and firms. Advocates of shale development claim that development boosts local and state economies, promotes energy security (if homegrown shale gas replaces imported conventional oil) and reduces global greenhouse gas emissions (if shale gas replaces coal). In particular, some studies estimate local and state economic benefits of shale gas production in the form of increases in employment, income, property values and tax revenues.4 In addition, shale gas is abundant domestically and would significantly contribute to an energy-independent United States.5 Finally, some environmental groups support responsible shale development in the hope that natural gas (the cleanest-burning fossil fuel) replaces coal, putting the United States on a ‘cost-effective bridge to . . . a low-carbon future’.6 The unprecedented scale of development, however, exposes more areas to ordinary perils associated with drilling activities, including air pollution, drilling and road accidents, fluid spills and well blowouts, the cumulative effects of which could be significant. Fracking also presents its own set of possible risks, such as groundwater and surface water contamination from fracking fluid or wastewater, water-supply shortages due to fracking’s sizeable water requirements, and earthquakes induced through the injection of fracking wastewaters into disposal wells. Current research has not convincingly isolated a causal connection between fracking and some of these adverse events. And, in any 3

4

5

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US Government Accountability Office, ‘Oil and gas: information on shale resources, development, and environmental and public health risks’, Report to Congressional Requesters, GAO-12-732, Washington, DC (2012). These consequences of shale development might not correspond to true net benefits if relevant effects are double counted. US Energy Information Administration, Annual Energy Outlook 2014 with Projections to 2040, EIA-0383(2014), Washington, DC (2014). Massachusetts Institute of Technology, ‘The future of natural gas’, Report 2011. While burning natural gas undeniably emits less greenhouse gases than does burning coal, scientists disagree on whether the entire carbon footprint of natural gas is lower than that of coal. Even assuming its production and use generates significant greenhouse gas reductions in the short term, some environmentalists worry that shale development will divert investments from long-term renewable-energy solutions and that extensive fracturing could limit shale’s usefulness in carbonsequestration projects going forward.

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case, the total expected damages would depend on the number of wells drilled, on the location of the wells and on the practices employed by operators – as well as on regulatory enforcement within each state. As a result, there is significant uncertainty surrounding the expected overall costs of shale development. The most publicised risk is drinking-water contamination by fracking fluid or wastewater, most likely to occur through surface spills from drilling activities. For example, fracking wastewater is often stored in on-site pits, at least temporarily, and then transported for treatment or injection into a disposal well. Spills could occur when wastewater is transported or when it is improperly enclosed in a storage container. If spills or leaks are not cleaned up, then contaminants can migrate into groundwater sources. Under US federal law, operators must report qualifying spills of hazardous substances,7 but states are responsible for ensuring that proper regulations are in place to prevent such spills, and these state regulations vary widely.8 In 2012, the International Energy Agency (IEA) advised firms to support regulations that deal convincingly with environmental risks of fracking, which would raise production costs by about 7 per cent, or else face widespread bans and other limits that would ultimately prove more expensive.9 Already, numerous US towns, cities, counties and even a few states have banned shale development. Of course, the IEA’s statement assumes that such banning behaviour is at least partly motivated by the perceived environmental costs of shale development.10 And, in my research, I do find evidence that concerns about environmental externalities, especially water-risk concerns, lead to bans on shale development in some contexts.11 Specifically, I find that shale-rich New York towns with a higher reliance on private water wells and those with higher livestock water use were associated with a higher probability of adopting a ban during 2010–13.12 Unlike for the public water system, states do not regulate private water wells, making it up to the homeowner to ensure that his or her water supply is safe for consumption. Properties that rely on private water 7

Comprehensive Environmental Response, Compensation, and Liability Act, 42 USC, Sec. 9603 (2013). 8 N. Richardson, M. Gottlieb, A. J. Krupnick and H. J. Wiseman, ‘The state of state shale gas regulation’, Resources for the Future Report, Washington, DC (2013). 9 International Energy Agency, World Energy Outlook: Golden Rules for a Golden Age of Gas (2012), available at www.worldenergyoutlook.org/goldenrules 10 Banning behaviour could also be driven by other local externalities, such as the sizeable wear and tear on roads and other infrastructure from extensive fracking activities. 11 C. Cecot, ‘Shale development: risks, responses, and regulation’, PhD dissertation, Vanderbilt University (2014), Chapter II. 12 Ibid., Chapter II. In addition, industry presence and previous experience with drilling tend to decrease the probability that a town adopts a ban. And, unsurprisingly, demographic characteristics, environmental preferences and political interests also predict whether a town will adopt a ban. In 2014, New York’s Governor Andrew M. Cuomo announced plans to ban shale development across the state. T. Kaplan, ‘Citing health risks, Cuomo bans fracking in New York State’, New York Times (17 December 2014), available at www.nytimes.com/2014/12/18/nyregion/ cuomo-to-ban-fracking-in-new-york-state-citing-health-risks.html?_r=1

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wells, therefore, have a higher probability of realising poor water quality if a nearby well damages water sources. In other research, I also find that a nearby horizontal well is associated with property-value losses for some properties that rely on private water wells.13 It may be that concerns about property-value losses from water-contamination risk perceptions underlie the banning behaviours. Such findings suggest a role for comprehensive regulation of the risks to water from shale development to reduce property-value losses and banning behaviour going forward. A PROPOSAL USING MULTIPLE POLICY INSTRUMENTS Typically, when a socially beneficial activity generates externalities, governments can deploy three tools to manage these externalities: regulations, tort liability standards and liability insurance mandates. Governments can promulgate all kinds of regulations, but under an economic framework, only net beneficial regulations are justified. Private parties, in contrast, initiate tort litigation, seeking compensation for harms allegedly caused by other parties. Governments, however, can define the scope of tort liability, which can regulate private behaviours. Finally, liability insurance is a market tool available to companies to manage risks from their activities. Governments can mandate liability insurance coverage, ensuring that only companies that are able to pay for expected damages engage in an activity. Although other regulatory proposals have focused on one or more of these tools to regulate the risks of shale development,14 in my research I argue that effective regulation of shale development requires using the appropriate combination of these tools for different risk categories.15 Essentially, whether a tool, or combination of tools, is appropriate depends on the nature of the risk that the government seeks to control or mitigate. I categorise the potential harms from shale development into four groups (I, II, III, and IV) broadly based on the timing of pollution discharges and the manifestation of harms. Table 63.1 summarises these risks. Category I and II risks manifest in immediate harms to water sources. These risks are not very different from the water risks presented by all onshore drilling activities, not just shale development. Regulators should require operators to adopt all risk-mitigating operating practices that generate net benefits.

13

Cecot, ‘Shale development’, Chapter I. See also S. Gopalakrishnan and H. A. Klaiber, ‘Is the shale energy boom a bust for nearby residents? Evidence from housing values in Pennsylvania’, American Journal of Agricultural Economics 96 (2014), 43–66; L. Muehlenbachs, E. Spiller and C. Timmins, ‘Shale gas development and property values: differences across drinking water sources’, NBER Working Paper No. 18390 (2012). 14 D. A. Dana and H. J. Wiseman, ‘A market approach to regulating the energy revolution: assurance bonds, insurance, and the certain and uncertain risks of hydraulic fracturing’, Iowa Law Review 99 (2014), 1523–93; T. W. Merrill and D. M. Schizer, ‘The shale oil and gas revolution, hydraulic fracturing, and water contamination: a regulatory strategy’, Minnesota Law Review 98 (2013), 145–264. 15 For a more detailed discussion of this proposal, see my previous research: Cecot, ‘Shale development’, Chapter I.

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Table 63.1 Categorising water contamination harms from shale development Incident type Discovery/Manifestation

Sudden

Gradual

Immediate

Category I: Spills, discharges or blowouts

Category II: Slowly leaking on-site waste storage pits

Delayed

Category III: Spills, discharges or blowouts found to generate latent harms

Category IV: Leaking pits, disposal wells or unplugged abandoned wells that generate later harms

Strict liability for drilling harms in tort litigation will also motivate operators to adopt these practices, especially if legislative and regulatory interventions facilitate recovery for actual drilling-related harms. Mandatory environmental impairment liability insurance coverage for Category I and II risks (covering immediate injury, property and clean-up costs from both accidental sudden and gradual releases of pollution) will then guarantee that only operators that are able to pay for expected immediate harms, reasonable care notwithstanding, engage in drilling activities. Net beneficial regulations, an adequate enforcement system and robust tort litigation will ensure that operators continue to adopt all net-beneficial risk mitigation operating practices. States should recognise that this regulatory strategy, however, is unlikely to address Category III and IV risks that are characterised by uncertain pathways and latent harms. Regulators should implement research-based strategies now to learn more about these risks. By being proactive, regulators can amass scientific data in a timely manner and update regulations in an appropriate way given the information. Tort litigation can still function as a backstop motivating force. If governments are concerned about having money available to address these latent harms in the future, then governments could apply a portion of regulatory fines toward a fund that could be used in the future to remediate the environment when those responsible for latent-manifesting contamination are unable to pay. Financing the fund with a percentage of fines collected each year would also add a fault element; those responsible for the worst violations would contribute a larger amount of money to the fund. Overall, governments could use these three tools – regulation, liability standards and insurance mandates – to provide protection against all categories of harms to water from shale development. When deployed effectively, these tools can facilitate responsible shale development by creating incentives for optimal activity levels, acceptable risk-taking and comprehensive environmental protection.

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PREPARING PENNSYLVANIA FOR A POST-SHALE FUTURE Ross H. Pifer1

Pennsylvania is now in the midst of a massive resource boom – spurred by natural gas production from the Marcellus Shale Formation. As one of the key players in the so-called ‘Shale Revolution,’2 Pennsylvania’s natural gas production has increased by a magnitude of sixteen in a five-year period – from 197 billion cubic feet of production in 2008 to 323 trillion cubic feet in 2013.3 As a result of this surge in production, Pennsylvania has become the second leading natural gas producer in the United States, trailing only Texas.4 1

2

3

4

Working in the heart of the Marcellus Shale formation, Professor Ross Pifer has given numerous presentations throughout Pennsylvania, across the USA and internationally on shale gas topics to audiences consisting of landowners, attorneys, judges, government officials, academics and the general public. He also has written a number of publications on shale law issues and, as Clinical Professor of Law at Penn State Dickinson School of Law, he teaches courses on Oil and Gas Law, Law and Policy of Shale Development, and Agricultural Law. He recently authored ‘Historical background of Pennsylvania oil and gas law’ for a treatise entitled ‘The law of oil & gas in Pennsylvania’. His current research includes effective governance of shale development globally; compulsory pooling of oil and gas interests in Pennsylvania; and a comprehensive review of the issues, questions, problems and opportunities that have arisen by and through shale development. At Penn State Law, he serves as the Director of the Center for Agricultural and Shale Law and the Director of the Rural Economic Development Clinic. See D. Brooks, ‘Shale gas revolution’, New York Times (4 November 2011), A31 (highlighting the job growth in Pennsylvania from shale gas development). See also United States Energy Information Administration, ‘Drilling Productivity Report (April 2015), available at www.eia.gov/petroleum/ drilling/pdf/dpr-full.pdf (detailing the Marcellus Shale Formation as the most productive gas formation among the seven ‘key tight oil and shale gas regions’ in the United States). United States Energy Information Administration, ‘Natural gas gross withdrawals and production’, available at www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_FGW_mmcf_a.htm Ibid. In 2013, Pennsylvania accounted for 27 per cent of the shale gas production in the United States. United States Energy Information Administration, ‘Shale gas production’, available at www.eia.gov/dnav/ng/ng_prod_shalegas_s1_a.htm. From 2008 to 2013, its share of national shale gas production rose significantly each year. It is likely that this trend will continue as Pennsylvania shale production in 2014 increased by 29 per cent over 2013 production. A. Litvak, ‘DEP: shale producers hit 4 trillion cubic feet of gas in 2014’, Pittsburgh Post-Gazette (17 February 2015).

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Based upon production data and other trends, it appears that Pennsylvania remains in the very early days of shale gas production.5 At some point, however, today’s shale boom will end, and when that occurs – whether it is after ten, twenty-five, fifty or one hundred years of development – what will the legacy of shale gas development be for Pennsylvania? The answer to this question has not yet been written. As such, now is the time for state elected officials, industry executives, local community leaders and other policy-makers to implement measures to ensure that shale development leaves a positive legacy for Pennsylvania and its communities. Throughout its short history of barely a decade, shale development in Pennsylvania has been extremely controversial.6 To some, shale development is viewed as a solution to our nation’s energy issues and a much-needed economic driver for local communities.7 Alternatively, others fear that it will cause environmental degradation on a grand scale.8 Sitting at centre stage for this polarising debate in Pennsylvania are the rural communities where much of this development is taking place. Shale development unquestionably has generated positive economic activity in these communities.9 Landowners have been enriched through lease bonuses and royalty payments.10 The labour force has welcomed a large number of jobs, and business owners have capitalised on new opportunities to sell goods and services to this industry.11 Shale development, however, has also imposed strains upon the local infrastructure in many communities.12 In considering the positive and negative impacts, it is clear that shale gas development has presented Pennsylvania and its communities with a tremendous opportunity – an opportunity to manage the development of this resource for the ultimate benefit of current and future generations. This is not a new opportunity, however, as Pennsylvania has a long history of resource extraction.13 5

See Standard & Poor’s Rating Services, ‘How the Marcellus Shale is changing the dynamics of the U.S. Energy Industry’ (15 October 2012) (noting the large potential reserves, proximity to regional markets and low break-even costs among the factors driving industry activity in the Marcellus Shale Formation). 6 Following the release of the New York State Department of Health’s Public Health Review of High Volume Hydraulic Fracturing for Shale Gas Development, New York Governor Andrew Cuomo stated that the debate over hydraulic fracturing was ‘probably the most emotionally charged issue I have ever experienced’. G. Lean, ‘Fracking banned on health grounds from New York State’, The Guardian (23 December 2014). 7 See R. Bryce, ‘America needs the shale revolution’, Wall Street Journal (13 June 2011). 8 See Gasland (New Video Group 2010) (highlighting the perceived environmental risks posed by hydraulic fracturing). 9 T. W. Kelsey, K. Hardy, L. Glenna and C. Biddle, ‘Local economic impacts related to Marcellus Shale Development’, Center for Rural Pennsylvania (September 2014). 10 Ibid. 11 Ibid. 12 K. R. Davis, T. W. Kelsey, L. L. Glenna and K. Babbie, ‘Local governments and Marcellus Shale Development’, Center for Rural Pennsylvania (September 2014). 13 See W. E. Edmunds, ‘Coal in Pennsylvania’ (Pennsylvania Department of Conservation and Natural Resources, 2002) (describing the history of coal production in Pennsylvania, beginning as early as 1761), available at www.dcnr.state.pa.us/cs/groups/public/documents/document/ dcnr_014594.pdf

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In 2014, Pennsylvania ranked twentieth in crude oil production among the thirty-one oil-producing states in the United States.14 With this low production figure, Pennsylvania’s prominent role in the early years of the oil industry can be easily forgotten. The drilling of the Drake well in 1859 commenced a regional oil boom that continued for several decades with Pennsylvania producing more than one-half of all oil produced in the United States until 1892.15 As with subsequent oil booms in other locations, Pennsylvania oil production peaked – in 1891 – and the boom eventually faded.16 Pennsylvania’s historical natural gas production largely mirrored that of its oil production. Following extensive early natural gas development spurred by the Drake oil boom, Pennsylvania was a national leader in natural gas production in the late nineteenth century and into the early years of the twentieth century.17 This natural gas boom faded and throughout most of the twentieth century, Pennsylvania was a relatively minor natural gas producing state. At the onset of shale production, Pennsylvania ranked fourteenth among the United States in natural gas production.18 Early resource extraction – from oil and natural gas as well as from timber and coal – was instrumental to the rise of Pennsylvania’s industrial development. Extraction activities and the resulting industries, including steel and glass, served as tremendous economic engines for Pennsylvania.19 Unfortunately, in many instances, this economic activity came at a high cost to the environment and public health.20 As one such example, historic coal mining 14

United States Energy Information Administration, ‘Crude oil production’, available at www. eia.gov/dnav/pet/pet_crd_crpdn_adc_mbbl_a.htm. Although Pennsylvania’s oil production had more than doubled in the prior five years, its 6.4 million barrels produced in 2014 accounted for only 0.2 per cent of United States oil production during that year. See ibid. 15 G. R. Hopkins and A. B. Coons, Statistical Appendix to the Minerals Yearbook, 1932–33 (US Bureau of Mines, 1934), pp. 210–11. 16 Pennsylvania lost its position as the leading oil-producing state in the United States in 1895 when its production was surpassed by that of Ohio. By 1918, oil production in Pennsylvania had declined to less than 25 per cent of its peak production. Hopkins and A. B. Coons, Statistical Appendix, p. 210. 17 R. H. Pifer, Historical Background of Pennsylvania Oil and Gas Law, The Law of Oil and Gas in Pennsylvania (Pennsylvania Bar Institute, 2014). 18 In 2008, Pennsylvania’s annual production of natural gas was below that of Texas, Wyoming, Oklahoma, New Mexico, Colorado, Louisiana, Arkansas, Utah, Alaska, Kansas, California, Alabama and West Virginia. United States Energy Information Administration, Natural Gas Gross Withdrawals and Production, available at www.eia.gov/dnav/ng/ng_prod_sum_a_EPG0_ FPD_mmcf_a.htm 19 See Edmunds, ‘Coal in Pennsylvania’, 2 (‘Pennsylvania’s great reserves of high-quality coal . . . were directly responsible for the presence of our iron and steel, chemical, glass, and metal-fabricating industries’.) See also ‘Value of natural gas, its use clarifies the atmosphere at Pittsburg’, New York Times (17 October 1885), 6 (noting that, in Pittsburgh, ‘[e]very steel and iron mill, glass factory, and manufactories generally of any consequence, besides many private dwellings, [depended] upon gas for fuel’.) 20 See Edmunds, ‘Coal in Pennsylvania’, 3 (‘economic benefits derived from the widespread use of coal have not come without serious cost to the environment’).

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practices have created acid mine drainage, substantially degrading many Pennsylvania streams to the point that the United States Geological Survey has estimated the restoration costs to be in the range of $5 billion to $15 billion.21 Significant long-term burdens such as these can raise questions as to whether the economic benefits realised from past resource extraction in Pennsylvania were worth the cost. This is particularly so where economic benefits were generated for a relatively short time period during, and immediately after, the resource boom.22 With these historical lessons in mind, how can Pennsylvania develop policies and enact laws today to ensure that the legacy left by shale development is a positive one? How can it take full advantage of the available economic opportunities while also ensuring that its communities will remain strong when the shale era has concluded? As a baseline, two considerations must be paramount in the development and implementation of a sound policy: (1) environmental protection and (2) infrastructure preservation. Resource extraction necessarily will have an impact upon the environment just as do nearly all human activities. Reasonable regulation must be imposed upon developmental activities to ensure that environmental impacts are minimised to the greatest extent practicable. It simply is not acceptable to impose long-term environmental burdens upon future generations. Additionally, extraction necessarily will also have an impact, to some degree, upon the infrastructure of affected communities. Communities must be provided with financial resources to manage these impacts so that they are able to maintain all forms of their infrastructure, including transportation systems and social services, throughout the course of development. By appropriately addressing these two baseline considerations, Pennsylvania will ensure that its communities will be strong and its environment healthy after the shale era has concluded. But with what has been termed by the president of a major environmental organisation as a ‘once-in-a-generation energy and economic opportunity’,23 Pennsylvania needs to develop a policy that looks beyond these two baseline considerations. Pennsylvanians should not be satisfied merely 21

USGS Pennsylvania Water Science Center, ‘Coal-mine-drainage projects in Pennsylvania’, available at http://pa.water.usgs.gov/projects/energy/amd. USGS also estimates that Pennsylvania loses $67 million each year due to the loss of recreational fishing in affected streams and rivers. Ibid., p. 3. 22 Pithole, which rose from forestland to a town with ‘more than fifty hotels’ almost overnight, provides the classic story of a boomtown. The entire lifecycle of this town was just a few years. D. Yergin, The Prize: The Epic Quest for Oil, Money & Power (Simon & Schuster, 1991), pp. 14–15. Other longer-established towns have often struggled economically when resourcerelated industries have vacated the community. See ‘Inside Oil City, hope runs dry’, New York Times (26 July 1995) (describing the relocation of the Quaker State Corporation headquarters from Oil City, Pennsylvania to Dallas, Texas). 23 Pennsylvania Environmental Council, ‘Pennsylvania Environmental Council releases major report on Marcellus Shale drilling’, Press Release (13 July 2010), available at http://celdf.org/ downloads/PA%20-%20PEC%20Marcellus%20Shale%20Policy%20Report.pdf

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with the receipt of economic benefits during the shale boom. Rather, they should use shale development as a springboard for economic and community development in the post-shale era. There are a number of potential strategies that can assist in the achievement of post-shale economic vitality. Certainly, shale extraction already has created, and will continue to create, private wealth that can be used for longlasting community development, through philanthropy and the establishment of new businesses.24 State and local governments can also take an active role by encouraging the establishment of supplementary industries that will extend beyond the life of shale development.25 These measures will provide some benefits in the post-shale era, but they may not do so on a consistent basis throughout all impacted communities. To maximise the provision of economic and social benefits in the postshale era, Pennsylvania should establish a sovereign wealth fund to utilise as an investment for, and in, Pennsylvania communities. Sovereign wealth funds have been used by many jurisdictions, throughout the United States and across the globe, to invest revenue generated from the extraction of oil and natural gas for the economic benefit of future generations.26 The largest of these funds, Norway’s Government Pension Fund Global, has a reported value of $882 billion.27 Within the United States, at least eight states have established sovereign wealth funds to invest revenue from oil, natural gas or other minerals.28 In recent years, revenues from shale oil and gas development

24

See G. E. McGinnis, ‘Philanthropy and Pennsylvania’s natural gas boom: an examination of philanthropic opportunities in rural communities’, Penn State Department of Agricultural Economics and Rural Sociology (Fall 2010), available at http://mcginnisfundraising.weebly.com/ uploads/1/0/5/3/10533020/philanthropy_and_the_natural_gas_boom_fall_2010_mcginnis.pdf (‘[p]hilanthropic gifts made by those who benefited greatly are some of the only remnants of [past resource booms in Pennsylvania] still providing value to the community’). 25 See ‘Meetings on proposed shell “cracker” plant in Beaver County lure 1,000’, Pittsburgh Tribune Review (16 April 2014), available at http://triblive.com/news/beaver/5952982-74/ shell-plant-beaver#axzz3YpPemyG7 (discussing Pennsylvania’s offer of potential tax credits in excess of $1 billion to attract an ethane cracker plant). 26 See Sovereign Wealth Fund Institute, ‘Largest sovereign wealth funds by assets under management’, available at http://www.swfinstitute.org/fund-rankings (listing the seventy-eight largest sovereign wealth funds globally). Among these, 60.3 per cent of the aggregated assets are derived from oil and natural gas. Ibid. 27 In describing the impact of its sovereign wealth fund, former Norway Prime Minister Jens Stoltenberg stated, ‘There are many, many other countries in the world that are in similar positions, that are facing the same kinds of challenges that we are facing: huge temporary income from natural resources . . . So, if there is a danger of an oil curse, Norway is really exposed to that danger. But we have managed to avoid it. The oil industry has been a blessing for Norway.’ ‘Norway’s sovereign wealth fund “is example for oil-rich nations”’, The Guardian (30 September 2013), available at www.theguardian.com/business/2013/sep/30/norway-oilsovereign-wealth-fund. 28 See Sovereign Wealth Fund Institute, ‘Largest sovereign wealth funds’ (listing funds established by Alaska, Texas, New Mexico, Wyoming, Alabama, North Dakota, Louisiana and West Virginia).

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have spurred the creation of the North Dakota Legacy Fund29 and the West Virginia Future Fund.30 Through the establishment of a sovereign wealth fund, Pennsylvania could use revenue from the development of public land31 and from the assessment of an impact fee32 or severance tax33 to fund educational and other programmes long after its shale resources have been depleted. Using shale revenue for the future, rather than solely to pay for current expenses, avoids a dilemma where the funding stream for basic governmental functions declines together with the overall economic decline resulting from lessened shale development. Establishing a sovereign wealth fund does require fiscal discipline to forego a potential revenue source today, but it will provide long-lasting benefits for future generations. Doing so will ensure that shale development in Pennsylvania leaves a positive legacy; that Pennsylvania and its communities will be more prosperous in the post-shale era due to the effective management and stewardship of its natural resources. 29

On 2 November 2010, North Dakota voters approved the addition of the North Dakota Legacy Fund to the state constitution. North Dakota Secretary of State, ‘Official Results General Election – November 2, 2010’, available at http://results.sos.nd.gov/resultsSW.aspx?eid=22&text=BQ&type =SW&map=CTY. Pursuant to this constitutional amendment, ‘[t]hirty percent of the total revenue derived from taxes on oil and gas production or extraction’ must be placed in the fund, and such funds ‘may not be expended until after June 30, 2017’ North Dakota Cons., Art. X, Sec. 26. 30 Effective 1 July 2014, ‘twenty-five percent of the annual revenue in excess of $175 million that is collected and received’ from the severance tax must be deposited into the West Virginia Future Fund. Neither principal nor interest may be expended from this fund until 2020. West Virginia Code, Sec. 11–13A-5b. 31 See Pennsylvania Environmental Defense Foundation v. Commonwealth, 108 A.3d 140 (Pennsylvania Commonwealth, 2015) (describing the general process of leasing public land for oil and natural gas development in Pennsylvania as well as the general manner of handling proceeds from development through the operation of the Oil and Gas Lease Fund). 32 Pennsylvania currently collects an impact fee from shale gas operators. 58 Pa.Cons. Stat,. Secs 2301–18. The impact fee is assessed upon each unconventional well for fifteen years on a declining fee schedule based upon annual market prices for natural gas. See Sec. 2302. The proceeds from the impact fee are distributed primarily to local government units to be expended for purposes related to the impacts of natural gas development. See Sec. 2314. 33 Pennsylvania currently does not impose a severance tax upon producers. The Pennsylvania Independent Fiscal Office has determined that the impact fee is generally comparable to a severance tax in the range of 0.6 per cent to 1.6 per cent. Independent Fiscal Office, ‘Natural gas extraction: an interstate tax comparison’, Special Report 2014-2 (March 2014). Pennsylvania Governor Tom Wolf has proposed a ‘5% severance tax plus 4.7 cents per thousand feet of volume’ as part of the Pennsylvania Education Reinvestment Act. Office of the Governor, ‘Governor Wolf proposes education reinvestment plan featuring natural gas severance tax’, Press Release (11 February 2015), available at www.pa.gov/Pages/NewsDetails.aspx?agency=PAGovNews&item=16502#.VULppGd 0wdU. Legislative leaders have voiced strong opposition to this severance tax proposal. See ‘Wolf says Pennsylvania severance tax “not a partisan idea”’, Pittsburgh Post-Gazette (3 March 2015) (quoting Senate President Pro Tempore Joe Scarnati as stating, ‘I believe strongly, strongly, that this industry will pull out of this commonwealth’ [if Governor Wolf’s proposal is enacted]). Certainly, the implementation of a severance tax will be a cost for shale gas operators that will have an adverse effect on the business climate in Pennsylvania. At some level, it will discourage investment in Pennsylvania, but the fact that other states impose a severance tax seems to indicate that a reasonable severance tax, in and of itself, will not drive operators out of Pennsylvania.

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THE DECLINE OF COAL AND THE ECONOMIC TOLL ON THE APPALACHIAN REGION Patrick R. Baker1

Over the past twenty-five years, the Appalachian region has seen a steady decline in coal production.2 The decrease is due in part to regulations such as the Clean Power Plan as well as an increase in natural gas production. Because of the decrease in production, the region, once the heart of the nation’s coal industry, has succumbed to massive job losses because of mine closures and layoffs. Wyoming, West Virginia, Kentucky, Pennsylvania and Illinois are currently the top five largest coal-producing states in the nation.3 Three of these states, West Virginia, Kentucky and Pennsylvania, lie in the Appalachian region.4 Kentucky and West Virginia have been the hardest hit.5 1

2

3

4

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Patrick R. Baker is an Associate Professor of Law and Director of the Natural Resources Law Center at the Appalachian School of Law. Professor Baker teaches Administrative Law, Water Law, Oil & Gas Law, and Coal & Hard Mineral Law. He also serves as Chair of the Institutional Development and Strategic Planning Committee. Special thanks to my Research Assistant Erin Taylor: you have exceeded my expectations and will be a wonderful lawyer and counselor. T. Foster and L. Glustrom, ‘Trends in U.S. coal production: 1990–2012’, Clean Energy Action (October 2013), available at https://cleanenergyaction.files.wordpress.com/2013/10/ coal_production_top_16_states.pdf US Energy Information Administration, ‘Which states produce the most coal?’ (2 February 2015), available at www.eia.gov/tools/faqs/faq.cfm?id=69&t=2 Appalachian Regional Commission, ‘The Appalachian Region’, available at www.arc.gov/ appalachian_region/TheAppalachianRegion.asp B. Plumer, ‘Here’s why Central Appalachia’s coal industry is dying’, The Washington Post (4 November 2013), available at www.washingtonpost.com/blogs/wonkblog/wp/2013/11/04/hereswhy-central-appalachias-coal-industry-is-dying

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Nationally, coal production in the United States fell below one billion short tons (hereafter referred to as ‘tons’) to 984.8 million tons in 2013 from 1,012 million tons in 2012, approximately 3.1 per cent.6 US coal mine productive capacity dropped approximately 2.5 per cent to 1,252 million tons in 2013, which was a decrease of 32.4 million tons compared to 2012.7 The average number of employees at US mines decreased from 89,838 in 2012 to 80,396 in 2013, a decrease of 10.5 per cent.8 Furthermore, total US coal stocks decreased 16.1 per cent to 200.4 million tons, a decrease of 38.4 million short tons.9 Electric power sector coal stocks decreased from 185.1 million tons at the end of 2012 to 148 million tons at the end of 2013, roughly 20.1 per cent lower than 2012.10 Specifically, Kentucky has seen harsh declines in coal production accompanied with rising unemployment.11 For over two centuries, Kentucky has been mining coal.12 The earliest recorded statistic regarding commercial coal production in Kentucky is 20 tons in 1790.13 This number steadily rose to over 100,000 tons by 1855.14 Throughout the twentieth century, industrialisation gave rise to the expansion of Kentucky’s coal industry, as bituminous coal became the primary energy source for growing cities throughout the Midwest.15 The expansion of railroads led to increased demand for Kentucky coal and this increase would continue until the 1930s when railroads transitioned to diesel.16 However, World War II sparked increased coal production in order to fuel the Allies’ war efforts and then subsequently the economic boom of the 1950s.17 Ultimately, coal production peaked in 1990 at over 173 million tons.18 In 2013, Kentucky ranked as the third-largest coal producer, with 8.2 per cent of US production; however, it simultaneously witnessed a 12 per cent decrease in production to 80.6 million tons.19 This is the lowest level of recorded annual production since 1963.20 Further, coal mining productivity is down nearly 45 per cent from the year 2000.21 Kentucky has the second-highest number of coalminers,

6

US Energy Information Administration, ‘Annual Coal Report’ (20 January 2015), available at www.eia.gov/coal/annual 7 Ibid. Productive Capacity is the maximum possible outcome of an economy. 8 Ibid. 9 Ibid. 10 Ibid. 11 Kentucky Coal Facts, 14th edn (8 July 2014), available at http://energy.ky.gov/Coal%20 Facts%20Library/Kentucky%20Coal%20Facts%20%2014th%20Edition%20(2014).pdf 12 Ibid. 13 Ibid. 14 Ibid. 15 Ibid. 16 Ibid. 17 Ibid. 18 Ibid. 19 Ibid. 20 Ibid. 21 Ibid.

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with 15.2 per cent of the national employment in 2013.22 Coal-related employment in Kentucky has decreased by 15.9 per cent in 2013 to 11,885 workers.23 Coal production is essential to the economic health of Appalachia. However, this narrow and singularly focused approach has prevented the region from identifying other potential sources of economic growth. For instance, Kentucky depends heavily on its coal severance tax revenue.24 Severance taxes on coal production in 2013 totalled $212,443,519.59.25 In fiscal year 2014, $61.3 million in coal severance tax receipts were returned to coal-producing counties for infrastructure improvements, economic development projects and, most importantly, education.26 According to the latest census data, the poverty level in Kentucky is now 18.6 per cent compared to 14.9 per cent nationally.27 The revenue collected from coal severance taxes offsets a poor economy and allows for initiatives that, for example, provide high-speed broadband for the entire state and increase funding for scholarships.28 New Environmental Protection Agency (EPA) regulations are a major reason for the decrease in coal production. For example, under the Clean Power Plan, the EPA has mandated a 30 per cent reduction in carbon emissions at fossil fuel burning power plants by 2030 compared to 2005 carbon levels.29 Each state will determine how to meet customised targets set by the EPA.30 This formula will examine each state’s most recent emissions along with other factors such as their ability to shift to natural gas or idle coal plants by 2030.31 States will have until 2017 to finalise a plan to reduce emissions, and possibly 2018 if they plan to join with another state in reduction efforts.32 Some states will be allowed to emit more carbon, while others will be forced to emit less.33 If a state refuses to implement a plan, the EPA will design and mandate a state-specific goal.34 If a state wishes to build a new coal-fired power plant, as opposed to retrofitting an already existing plant, EPA regulations mandate that CO2 emissions not surpass 1,100 pounds per MWh.35 This regulation will make it difficult, if not impossible, to build new coal-fired power plants with 22

Ibid. Ibid. 24 Ibid. 25 Ibid. 26 Ibid. 27 US Census Bureau, available at www.census.gov 28 ‘Competitiveness: Creating a Brighter Future for Eastern Kentucky’, available at http://governor. ky.gov/Press%20Release%20Attachments/20140121_BudgetFactSheet-SOAR.pdf 29 C. Kardish and K. Tidmarsh, ‘How much each state has to cut carbon emissions under new EPA regulations’, Governing (4 June 2014), available at www.governing.com/topics/transportationinfrastructure/gov-how-much-each-state-has-to-cut-carbon-dioxide-under-epa.html 30 Ibid. 31 Ibid. 32 Ibid. 33 Ibid. 34 Ibid. 35 Ibid. 23

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the current technology.36 Due to the cost and technological limitations, it is unlikely that any new coal fired power plants will be built in the United States. Because of EPA regulations imposing greater costs on coal production and consumption, natural gas has become more cost-effective for electricity generation. Total US natural gas gross withdrawals reached a new high at 82 billion cubic feet per day (Bcf/d) in 2013, with shale gas wells becoming the largest source of total natural gas production.37 Gross withdrawals from shale gas wells increased from 5 Bcf/d in 2007 to 33 Bcf/d in 2013, representing 40 per cent of total natural gas production, and surpassing production from non-shale natural gas wells.38 New technology has enabled producers to shift production to resources that are now easier to reach with reduced drilling costs.39 These trends have been reflected in the lower market price for natural gas.40 West Virginia’s marketed natural gas production has increased alongside the development of Marcellus Shale.41 By 2011, shale gas reserves exceeded 6 trillion cubic feet of natural gas.42 Because of the rapid growth of natural gas production, many natural gas processing plants are being constructed or expanded throughout the state to separate dry natural gas from natural gas liquids being produced from the Marcellus Shale.43 West Virginia has thirty natural gas storage fields located in depleted natural gas reservoirs.44 Those fields have a total storage capacity in excess of 500 billion cubic feet.45 Natural gas storage fields in West Virginia account for approximately 6 per cent of the nation’s total natural gas storage capacity.46 The proximity of this storage capacity to north-eastern US markets makes the state an important supplier to New England during the winter when natural gas demand peaks.47 Clearly, the Appalachian region has seen a negative impact on coal production caused by new EPA regulations as well as an increase in natural gas production; therefore, the only way to offset this precipitous decline in jobs and the economic downturn is a government bailout for Appalachia. In 2008, the US government created the Troubled Asset Relief Program (TARP) to help 36

J. Eilperin and S. Mufson, ‘Everything you need to know about the EPA’s proposed rule on coal plants’, The Washington Post (2 June 2014), available at www.washingtonpost.com/national/ health-science/epa-will-propose-a-rule-to-cut-emissions-from-existing-coal-plants-by-up-to30-percent/2014/06/02/f37f0a10-e81d-11e3-afc6-a1dd9407abcf_story.html 37 US Energy Information Administration, ‘Today in energy’ (25 November 2014), www.eia.gov/ todayinenergy/detail.cfm?id=18951 38 Ibid. 39 Ibid. 40 Ibid. 41 US Energy Information Administration, ‘West Virginia’ (18 December 2013), available at www. eia.gov/state/analysis.cfm?sid=WV 42 Ibid. 43 Ibid. 44 Ibid. 45 Ibid. 46 Ibid. 47 Ibid.

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stabilise the financial crisis.48 Appalachia today confronts a similar crisis as the coal industry experiences a radical decline. According to the US Treasury Department, the auto industry bailout totalled $80 billion.49 More applicable to the Appalachian region is the tobacco buyout in the 2000s.50 The value of tobacco in 2005, the first year after the buyout, was less than $294 million.51 This is down from a high of almost $948 million in 1997.52 Now that farmers are selling their crop directly to manufacturers through contracts, the overall value increased to more than $404 million in 2013.53 Instead of abruptly ending tobacco quotas, the government conducted an orderly buyout and wind-down that prevented the economic crash of many agriculture communities. A government bailout of Appalachia would help offset those who are facing poverty in the Appalachian region. If families were offered financial incentives for relocation, retraining and education, sustainable economic development programme, and more federal dollars to offset steep declines in coal severance taxes, it would prevent an impoverished region from becoming more impoverished and what is likely to be one of the greatest financial disasters of the century.

48

US Department of the Treasury, ‘Auto industry’ (8 January 2015), available at www.treasury. gov/initiatives/financial-stability/TARP-Programs/automotive-programs/Pages/default.aspx 49 Ibid. 50 J. Patton, ‘With the end of tobacco buyout checks looming, Kentucky farmers have had to make changes’ (28 September 2014), available at www.kentucky.com/2014/09/28/3452483_with-theend-of-tobacco-buyout.html?rh=1 51 Ibid. 52 Ibid. 53 Ibid.

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THE EU NETWORK CODES AND PROSPECTS OF CROSS-BORDER NATURAL GAS PIPELINE PROJECTS Gokce Mete1

INTRODUCTION The geopolitical events since 2014 between Russia and Ukraine have brought energy security and efforts to increase the diversification of sources and routes to the top of the European agenda. With the need to increase new entry capacity from third countries to compensate for the decline of indigenous production in Europe, investment in incremental capacity is likely to be significant in the future. Project investors wishing to build infrastructure to deliver gas from third countries into EU territory must fully comply with the EU’s Third Energy Package (TEP)2 or request an exemption from some provisions of the internal gas market 1

2

Gokce Mete is concurrently undertaking doctoral-level research at the Centre for Energy Petroleum and Mineral Law and Policy at the University of Dundee as an AIPN Scholar. Her research examines EU internal gas market legislation, assessing its potential to attract investment into the energy infrastructure. Gokce is also a Research Fellow at the Energy Charter Secretariat, analysing the implementation of the Energy Charter, and is responsible for planning and managing the regular International Meeting of Experts on Reliable and Stable Transit jointly hosted by the ECS and Turkmenistan. She previously studied for her LLM at Queen Mary University of London, focusing on international investment arbitration in the energy sector. She has published on legal issues related to energy transit and cross-border pipelines. This consists of Council Regulation (EC) No 713/2009 of the European Parliament and of the Council of 13 July 2009 establishing an Agency for the Cooperation of Energy Regulators, (2009) OJ L211/1; Council Directive 2009/73/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in natural gas and repealing Directive 2003/55/EC, (2009) OJ L211/94 (Gas Directive); Regulation (EC) No 715/2009 of the European Parliament and of the Council of 13 July 2009 on conditions for access to the natural gas transmission networks and repealing Regulation (EC) No 1775/2005 (Regulation 715);

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regulations.3 Exemption decisions are taken on a case-by-case basis by the National Regulatory Authorities (NRA) of the member state where the infrastructure will be built, with the Commission having a right to veto the decision. Projects can be proposed to qualify as a ‘Project of Community Interest’ (PCI), identified as key infrastructure projects by the member states and the European Commission. In this case, the provisions of the TEP are fully applicable. Existing capacity in non-exempted natural gas pipeline projects is, by default, allocated by auction under the Capacity Allocation Mechanisms Network Code (CAM NC).4 Notably the TEP, in its current form, does not provide specific procedures for the construction and utilisation of new pipeline capacity. However, an ‘incremental capacity’ chapter, in the form of a CAM NC amendment, is in the process of public consultation at the time of writing. The issue of incremental capacity is closely related to the different Network Codes discussed below. INCREMENTAL CAPACITY PROPOSAL The incremental capacity proposal aims to attract efficient and financially viable investments in new cross-border pipeline infrastructures. The draft proposal offers an ‘open-season’ procedure, as an alternative to the default integrated auction method for allocating incremental capacity described in the CAM NC. The open-season procedure is a two-step process. First, it enables identification of actual market demand, and second, it allocates capacity on a transparent and non-discriminatory basis. In other words, the decision to invest in incremental capacity is contingent upon commitments from shippers to book enough capacity upfront to fulfil a ‘market test’. This is known as market-based investment. The other option, integrated auctions at all entry points along the provisions of the CAM NC, also provides a market test, as the bids submitted in the auctions determine the need for additional capacity. The bids should provide sufficient information to trigger the investment. However, allocating capacity based on auctions may not be financially feasible for large-scale projects.5 This might be the case where, for example, two or more entry-exit systems and Transmission System Operators (TSOs) are involved, or where a fifteen-year period for auctions – actually ten years after construction – is not considered to be sufficient to pass the economic test at the reserve price. Therefore, until a market-based, investment-friendly open-season procedure is developed and agreed, and has entered into force for new cross-border projects, the only economically viable way to construct major cross-border pipelines in the EU will remain the exemption option. 3 4

5

Art. 36 Gas Directive. Commission Regulation (EU) No 984/2013 of 14 October 2013 establishing a Network Code on Capacity Allocation Mechanisms in Gas Transmission Systems and supplementing Regulation (EC) No 715/2009, (2013) OJ, L 273/5 (CAM NC). A. Konoplyanik, ‘Economic background of gas problems within Russia-EU-Ukraine triangle and possibilities for mutually acceptable compromise’ (30 October 2014) Invited Speakers Thursday Lectures: Occasional Papers Issue 1, CEPMLP (forthcoming).

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Furthermore, the capacity at interconnection points under the CAM NC can be offered as ‘bundled capacity’ or ‘unbundled capacity’. Bundled capacity means the same level of entry and exit capacity on a firm basis at both sides of an interconnection point.6 Although the TSOs have a duty to maximise the quantity of bundled capacity offered,7 capacity at each entry and exit point may not match in all cases.8 Only in such cases may unbundled capacity be offered. CAPACITY ALLOCATION MECHANISMS The CAM NC regulates the allocation of unsold capacity at interconnection points, stipulating that, irrespective of the duration of the supply contract, capacity can only be booked for the next fifteen years in the EU.9 The rationale is that otherwise shippers could book the capacity for so long that they would foreclose short-term markets for small competitors. There is another issue with the CAM NC for incremental capacity: the obligation to reserve 10 per cent for short-term bookings.10 This obliges investors to build a pipe with 111 per cent of the requested capacity. The risk for the investor is therefore about 10 per cent higher. Under the default auction procedure of the CAM NC, a network user can book yearly, quarterly, monthly, daily and within-day standard capacity products. The TSOs are called to provide details on the available interconnection capacity11 and shippers to submit bids and offers for cross-border capacity. Capacity is explicitly allocated to shippers via one or a limited number of joint web-based booking platforms operated by TSOs or third parties. NETWORK CODE ON TARIFFS In an effort to harmonise transmission tariff structures and to allocate costs for incremental capacity within the applicability zone of the TEP,12 a Network Code on Tariffs has been developed by the ENTSO for Gas. The NC on Tariffs foresees that the price payable for capacity products is calculated as the sum of its reserve price and, if any, the auction premium. The Network Code on Tariffs is not yet final. The main issue with new and incremental capacity is whether shippers should pay for capacity through fixed or floating tariffs. Fixed tariffs would be preferable for some shippers as it would provide greater predictability in long-term commitments. However, the Framework Guidelines for Tariffs drafted by the 6

CAM NC, Art. 3(4). CAM NC, Art. 6. 8 The European Federation Of Energy Traders (EFET), An EFET Position Paper: Advancing the EU internal energy market: sector priorities for the Juncker Commission (12 November 2014), available at www.efet.org 9 CAM NC, Art 11(3). 10 CAM NC, Art 8(8). 11 Regulation 1775, Art. 18(3). 12 The Energy Community is also committed to apply the TEP, but each NC has to be approved separately and to be transposed in national law. 7

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European Agency for the Cooperation of Energy Regulators (ACER) suggest that the reserve price is identified as a floating price.13 Floating tariffs imply that if the revenues of the TSO at a particular time are less than expected, the missing revenues should be compensated for, via a tariff increase for the following year. This creates a situation where the actual prices for already-booked capacity could increase, as the final tariff is not set until after the auctions have taken place. CONGESTION MANAGEMENT PROCEDURES Contractual congestion occurs where capacity at an interconnection point is requested while it is fully booked by existing contracts. In this case, unused capacity should be reallocated to fulfil the pending requests to ensure that capacity is efficiently used. This is the purpose of the Congestion Management Procedures (CMPs). In order to handle contractual congestion, CMPs were amended to the Gas Regulation in 2012,14 providing many CMP measures: long-term use-it-or-lose-it (UIOLI), firm day-ahead UIOLI, oversubscription/ buy-back, capacity surrender and finally secondary markets for unused capacity15– although a formal secondary market for transport capacity did not hitherto exist in all member states. However, in its Implementation Monitoring Report on CMP, ACER reported incomplete implementation and limited application of CMP provisions by TSOs across the EU.16 NETWORK CODE ON BALANCING The TSO has to undertake an effective balancing mechanism to offset the gap between the commercial and physical gas networks. In this regard, a Network Code on Gas Balancing of Transmission Networks was published in 2014 to be applicable as of October 2015.17 It sets out a vision of market-based balancing at a single virtual trading point inside an entry-exit system. CONCLUSION Regulatory predictability is key for long-term investments in future crossborder natural gas infrastructure projects. The long-term market uncertainties – regulatory and political – caused by a range of complex interactions in a changing energy market in the EU, carry the risk of making shippers reluctant to commit to long-term capacity bookings.18 13

Framework Guidelines on rules regarding harmonised transmission tariff structures for gas (29 November 2013), prepared by ACER. 14 Commission Decision of 24 August 2012 on amending Annex I to Regulation (EC) No 715/2009 of the European Parliament and of the Council on conditions for access to the natural gas transmission networks (2012/490/EU). 15 Regulation 715, Annex I, guidelines on congestion-management procedures in the event of contractual congestion, Para. 2.2. 16 ACER, ‘Implementation monitoring report on congestion management procedures in 2014’ (13 January 2015), available at www.acer.europa.eu 17 Commission Regulation (EU) No 312/2014 of 26 March 2014 establishing a Network Code on Gas Balancing of Transmission Networks. 18 ESB Generation and Wholesale Markets, Response to Consultation Paper ‘Access Tariffs and Financing the Gas Transmission System’ Reference: CER/13/122.

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The international investment community may dislike the PCI/CEF process and the exemption regimes for new capacity. Until it is established in law or easily accessible, the exemption procedure is political, which is detrimental to financing prospective cross-border pipeline projects. The implications of the TEP for investments in the transport infrastructure and upstream investments beyond Europe is of paramount importance: they are, however, unexplored. The Network Codes aim to bring different market zones in the framework of the TEP under harmonised, transparent, operational and commercial rules. At the time of writing, four out of twelve potential Network Codes have been finalised and will become operational between 2015–17 and thereafter. Many problems will probably be identified and fixed through amendments, with the objective of looking for a balance between the predictability provided by the rules and the flexibility needed to address the process of change.

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BUILDING THE ENERGY UNION: THE PROBLEM OF CROSS-BORDER GAS PIPELINE INTERCONNECTIONS IN BALTIC, CENTRAL AND SOUTHEASTERN EUROPE Jack D. Sharples1

INTRODUCTION: THE EUROPEAN UNION IN 2015 – A FRAGMENTED GAS MARKET The European Union imports two-thirds of its natural gas consumption.2 However, these gas imports do not form a common EU supply of natural gas that is subsequently shared out between EU member states. The EU today is not one gas market, but several, each consisting of a dominant supplier and a group of importing states dependent on that supplier. In the Baltic, central and south-eastern regions of Europe, Russia is the dominant supplier.3 Greece and Lithuania are the only countries in the region with access to liquefied natural gas (LNG) imports,4 although that situation is changing: Poland’s new LNG 1

2

3

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Jack Sharples is a Lecturer in Energy Politics at the European University at St Petersburg. His research interests are in the political economy of energy, energy geopolitics and EU-Russia energy relations, in particular state-business relations in Russia’s gas sector, the political economy of Russia’s gas exports to Europe, the role of Ukrainian gas transit in EU-Russia gas relations, EU energy security, and the development of the EU gas market and the prospects for Gazprom on that market. Dr Sharples received his PhD from the University of Glasgow, UK. European Commission, ‘EU energy in figures: statistical pocketbook 2015’ (2015), available at https://ec.europa.eu/energy/sites/ener/files/documents/PocketBook_ENERGY_2015%20PDF% 20final.pdf; see p. 24. Eurogas, ‘Statistical report 2014’ (2014), available at www.eurogas.org/uploads/media/Eurogas_ Statistical_Report_2014.pdf Of the twenty-one LNG terminals currently operating on EU territory, nineteen are located in Sweden, the Netherlands, Belgium, the UK, France, Spain, Portugal and Italy. See Gas Infrastructure Europe, ‘GIE LNG map: May 2015’ (2015), available at www.gie.eu/index.php/maps-data/lng-map

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import terminal at Swinoujscie officially opened in October 2015, with the first delivery arriving in mid-December 2015,5 while Croatia plans to bring a new LNG terminal online by 2019.6 On 25 February 2015, the European Commission unveiled its ‘Energy Union’ project. To make the single European gas market a reality, the states of the Baltic, central and south-eastern regions of Europe need better cross-border interconnections between themselves, and with the wider European gas market, to alleviate their energy security concerns and develop a more competitive regional gas market. MECHANISMS ALREADY IN PLACE: PROJECTS OF COMMON INTEREST AND THE ‘CONNECTING EUROPE FACILITY’ The European Commission already has mechanisms in place to encourage the construction of new gas pipeline interconnections in the EU. The ‘Connecting Europe Facility’ (CEF) was established to encourage investment in Europe’s transport, energy and digital networks. The Commission states that ‘funding for energy networks will further integrate the internal energy market, reduce the EU’s energy dependency, and bolster the security of supply’, thus helping ‘to complete the European single market’.7 The CEF programme provides financial assistance for the planning and construction of natural gas pipelines in the EU. In doing so, the programme recognises that ‘Under current market and regulatory conditions some energy projects are not commercially viable, and would normally not make it into investment programmes of infrastructure developers’.8 To address ‘investment gaps’, the CEF seeks to mitigate risks that discourage investment and to provide grants that enhance the commercial viability of projects.9 In essence, the CEF programme promotes private investment and provides financial assistance to projects which, though they may not be commercially attractive, contribute to European energy security and the creation of the single, integrated EU gas market. To be eligible for CEF assistance, a project must be granted the status of ‘Project of Common Interest’ (PCI). To qualify as a PCI, the project must ‘have a significant impact on the energy markets of at least two EU countries, such as by contributing to the integration of their networks’ and ‘enhance the EU’s security of supply by allowing countries to receive energy from a greater number of sources’.10 5

LNG World News, ‘Deputy PM: Polish LNG terminal to be completed by July’, LNG World News (2 March 2015), available at www.lngworldnews.com/deputy-pm-polish-lng-terminal-tobe-completed-by-july 6 LNG Croatia, ‘Open season’ (2015), available at www.lng.hr/en/open-season 7 European Commission (2015), ‘Connecting Europe Facility’, available at http://inea.ec.europa. eu/en/cef/cef.htm 8 European Commission (2015), ‘Connecting Europe Facility – energy’, available at http://inea. ec.europa.eu/en/cef/cef_energy 9 Ibid. 10 European Commission (2015), ‘Energy: projects of common interest’, available at https://ec.europa. eu/energy/en/topics/infrastructure/projects-common-interest

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As of 18 November 2014, seventy-eight gas infrastructure projects have been granted PCI status. Of these seventy-eight projects, sixty-three are being developed in Baltic, central and south-eastern Europe under the framework of three regional groupings: the Baltic Energy Market Interconnection Plan in Gas (BEMIP Gas), the Southern Gas Corridor (SGC) and the North-South Gas Interconnections in Central Eastern and South Eastern Europe (NSI East Gas).11 The BEMIP projects aim at improving connections between Poland and Finland, to integrate the Baltic ‘energy island’ into the European gas market. The SGC projects aim to bring gas to the EU from the Caspian region, and to connect Bulgaria with both Turkey and Austria (via Romania and Hungary). Finally, the NSI East projects aim at improving connections between Poland, Slovakia, the Czech Republic, Austria, Slovenia and Hungary, as well as promoting new LNG import terminals in Croatia and Greece. The ‘North-South’ corridor refers to the series of interconnections between existing and proposed LNG terminals in Poland, Croatia and Greece. A PROPOSED ADDITION TO THE CEF Despite the assistance provided by the European Commission through the CEF programme, several interconnector projects have experienced delays. The launch of the Hungary-Slovakia interconnector (due in January 2015) was delayed for six months, reportedly because ‘Hungary’s pipeline operator, Magyar Gaz Tranzit [MGT], experienced delays in receiving certification from the European Commission to be a licensed transmission system operator [TSO]’.12 The Bulgaria-Romania interconnector was due for completion in 2013, yet is still not complete.13 The Bulgaria-Greece interconnector had an expected completion date of December 2014,14 but is now expected to be completed only in 2018.15 The latter two projects have been beset by technical difficulties, domestic political upheavals in Bulgaria and Greece, lack of effective communication and coordination between project participants (both 11

European Commission (2015), ‘Union list of projects of common interest as of 18 November 2015’, available at https://ec.europa.eu/energy/sites/ener/files/documents/5_2%20PCI%20annex.pdf 12 ICIS, ‘Hungary-Slovakia gas pipeline battling continued delays’, ICIS (12 February 2015), available at www.icis.com/resources/news/2015/02/12/9860703/hungary-slovakia-gas-pipeline-battlingcontinued-delays 13 European Commission, ‘Gas interconnection: Romania – Bulgaria’ (2013), available at http:// ec.europa.eu/energy/eepr/projects/files/gas-interconnections-and-reverse-flow/romania-bulgariaro-bg_en.pdf; Novinite, ‘Bulgaria expects to choose builder of gas link to Romania in December’, Novinite News (2 October 2015), available at www.novinite.com/articles/171125/Bulgaria+Exp ects+to+Choose+Builder+of+Gas+Link+to+Romania+in+December 14 European Commission, ‘Gas interconnection: Greece – Bulgaria’ (2013), available at http://ec.europa .eu/energy/eepr/projects/files/gas-interconnections-and-reverse-flow/greece-bulgaria-igb_en.pdf 15 Novinite, ‘Agreement on Bulgaria-Greece gas interconnector to be signed on December’, Novinite News (21 November 2015), available at www.novinite.com/articles/171906/Agreement+on+BulgariaGreece+Gas+Interconnector+to+be+Signed+on+December+10

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commercial entities and national governments) and a lack of public funds being provided by the states involved. The Bulgarian government has also faced accusations from the European Commission that it lacks the ‘political will’ to build the interconnectors.16 Such delays are the result of financial uncertainty and a lack of strong and effective project leadership. This chapter proposes that, to counter such delays, a mechanism could be established whereby an EU-funded and managed TSO could be established to buy into severely delayed strategic projects, provide additional investment and offer the required project leadership. Financial uncertainty can discourage private investors, while economic difficulties (such as those experienced by Bulgaria and Greece) can hinder state investment. Under circumstances where grants from the CEF are insufficient to induce participants to move forward with a project deemed to be of strategic importance by the European Commission, an EU-backed TSO buying into the project as a minority shareholder could provide additional investment. Shareholder dividends would provide a return on such investment. Furthermore, the shareholding could later be sold back to the private sector, thus recouping more of the EU investment. If the European Commission were to simply hand each participating government 100 per cent of the costs of their pipeline sections, then those governments could ‘free ride’ in the project, and private investment would be discouraged. By acting as an ‘impartial arbiter’ between the other project participants, and between the participants and the European Commission, the EU-backed TSO could also provide the consistent and effective project leadership necessary for the realisation of the project, and facilitate the successful negotiation of problems such as those detailed above. For example, an EU-backed TSO would be relatively immune to economic difficulties and political upheavals, and could provide a source of economic and political stability for the project in which it participated. Crucially, the EU-backed TSO would also be able to coordinate multiple projects in parallel. For example, this could ensure that interconnections from Greece to Hungary via Bulgaria and Romania (currently multiple separate projects) are coordinated with the development of new LNG import capacity in Greece. CONCLUSIONS The existing mechanisms of the CEF programme have succeeded in promoting the development of new pipeline interconnector projects in the Baltic, central and south-eastern regions of the EU. This chapter proposes an addition to the existing mechanisms, rather than a radical replacement. In cases of severe delays 16

G. Gotev, ‘Bulgaria lacks political will to build interconnectors, says Commission’, Euractiv (6 March 2015), available at www.euractiv.com/sections/energy/bulgaria-lacks-political-willbuild-interconnectors-says-commission-312709

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to projects deemed by the European Commission to be strategically important to European energy security, an EU-backed TSO could actively participate in those projects, and provide sufficient financial support and leadership to ensure their completion. In this way, the European Commission could play a more active role in the construction of the ‘Energy Union’.

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EMINENT DOMAIN AUTHORITY FOR UPSTREAM GAS INFRASTRUCTURE: AN ALTERNATIVE APPROACH Tara Righetti1

Gathering lines are pipelines that transport gas from a current production facility to a central collection point such as a natural gas processing plant, transmission line or larger mainline pipeline.2 They are a critical component of gas production and transportation infrastructure: without gathering lines, gas could not be transported from wellhead to market. Before commencing construction of gathering lines, operators must obtain authorisation and right of way from landowners on whose land the gathering lines will cross.3 While some states grant pipeline companies general authority of eminent domain, others limit condemnation authority to common carriers and public utilities.4 1

2 3

4

Tara Righetti joined the University of Wyoming College of Law faculty in the autumn of 2014. Prior to that, she served as CEO and general counsel of a privately owned upstream oil and gas company with operations in six states and on the outer continental shelf. Professor Righetti teaches classes on Oil and Gas Law and Energy Transactions and Finance. Her other areas of interest include state-owned oil enterprises, pipeline law and the environmental design of energy man camps. Professor Righetti’s research focuses on legal issues related to development of oil and gas on split estates, local regulation of oil and gas development, royalty payment statutes and energy development on tribal land. She is currently working on several projects that cumulatively look at the impact of unitisation pursuant to the Mineral Leasing Act on surface access and use by the unit operator. Professor Righetti wishes to acknowledge the contributions of her research assistant, Bailey Schreiber (JD 2014) to the research and writing of this chapter. 49 Code of Federal Regulations (hereafter CFR) 192.3 (2015). See A. B. Niles, ‘Eminent domain and pipelines in Texas: it’s as easy as 1, 2, 3 – common carriers, gas utilities, and gas corporations’, Texas Wesleyan Law Review 16 (2010), 271–93. E. J. Blieszner, ‘Condemnation Litigation – the Sword and the Shield’, in Rocky Mountain Mineral Law Foundation, Surface Use for Mineral Development in the New West: Finding Good Ground, Paper No. 15 (2008).

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Gas gathering and transportation may not fit neatly in the common carrier or public utility framework, thus presenting challenges to the planning and development of gathering systems. Unlike interstate pipelines, the siting of gas-gathering lines is generally outside federal regulatory jurisdiction.5 The US Natural Gas Act (NGA), which provided the Federal Energy Regulatory Commission (FERC) with jurisdiction over interstate lines, expressly excludes the ‘physical activities, facilities, and properties used in the production and gathering of natural gas’.6 Whether a specific midstream operation is classified as non-jurisdictional gathering or a jurisdictional transmission facility subject to FERC regulation is based on the primary function test.7 This test looks at a number of detailed physical criteria including, without limitation, the diameter and length of the facility and operating pressure of the line,8 and non-physical criteria such as the general business activities of the owner of the facility.9 Consistent with this test, most pipelines developed for natural gas gathering are exempt from FERC jurisdiction. Certain onshore gathering lines in populated areas or operated at high pressures may also be subject to regulation by the Pipeline and Hazardous Material Safety Administration (PHMSA) of the US Department of Transportation (DOT).10 PHMSA regulates construction, maintenance and operation of gathering facilities determined to be ‘regulated’ onshore gathering lines according to DOT regulations.11 The majority of gathering lines are found to qualify for the gathering exemption under NGA Section 1 and do not qualify as regulated onshore gathering lines.12 Accordingly, siting and construction of gathering facilities is primarily regulated by the individual states in which the gathering facility is constructed.13 States take disparate approaches when determining whether operators of gathering facilities have authority to exercise the power of eminent domain. Eminent domain authority must be conferred by the legislature, expressly or by necessary implication, and will not be inferred.14 Certain states, including Texas, Pennsylvania and Ohio, limit condemnation authority to public utilities 5

Panhandle Eastern Pipeline Co. v. The Public Service Comm’n of Ind., 332 U.S. 507, 516 (1949). Phillips Petroleum Co. v. State of Wis., 347 U.S. 672, 678 (1954); Colo. Interstate Gas Co. v. Fed. Power Comm’n, 324 U.S. 581 (1945). 7 Conoco Inc. v. Fed. Energy Reg. Comm’n, 90 F.3d 536, 542 (D.C. Cir. 1996). 8 Farmland Indus. Inc., 23 Fed. Energy Reg. Comm’n 61,063, 61,143 (1983). 9 Jupiter Energy Corp. v. Fed. Energy Reg. Comm’n, 407 F.3d 346, 349 (5th Cir. 2005). 10 49 CFR 192.1 (2015). 11 49 CFR 192.8 (2015); American Petroleum Institute (2000), ‘API recommended practice 80: guidelines for the definition of onshore gas gathering lines’. 12 W. J. Airey, ‘Natural gas gathering line safety regulation: potential impact on oil and gas development’, in Rocky Mountain Mineral Law Foundation, Development Issues and Conflicts in Modern Gas and Oil Plays, Paper No. 14 (2004). 13 J. Jost and G. L. Matero, ‘Regulatory and permit requirements for gathering systems, central facilities, and processing plans’, in Rocky Mountain Mineral Law Foundation, Oil & Gas Agreements: Midstream and Marketing, Paper No. 6 (2011). 14 Coastal States Gas Producing Co. v. Pate, 309 S.W.2d 828 (Tex. 1958) 6

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or common carriers.15 In order to qualify for eminent domain authority under these standards, a company must be offering a service to the public for hire.16 A recent Texas case, Texas Rice Land Partners, Ltd. v. Denbury Green PipelineTexas, LLC, found that the mere availability to transfer products for third parties, without a reasonable probability that the pipeline would actually transport products to or for the public for hire, was insufficient to classify a company as a common carrier.17 While the holding in that case was limited to hydrogen and carbon dioxide carriers under Chapter 111.002 of the Natural Resources Code,18 the court’s approach presents similar challenges if applied to companies seeking to qualify as a gas utility. In order to qualify as a gas utility with eminent domain authority, a company must be in the business of transporting or distributing gas for public consumption and offer service indiscriminately to the public.19 In response to the Denbury decision, the Texas Railroad Commission modified its rules to heighten scrutiny relating to pipeline permits effective 1 March 2015.20 While these rules stop short of establishing standards of proof for common carrier status, they impose new requirements including an attestation to knowledge of the eminent domain provisions of the Texas Property Code and a Landowners Bill of Rights.21 Likewise, in Pennsylvania, a company must have public utility status in order to exercise condemnation authority using the procedures of the Pennsylvania eminent domain code.22 While it may be possible in limited cases for a gathering line to qualify for public utility status,23 most gathering operations will not qualify as public utilities for purposes of exercising authority of eminent domain. As one administrative law judge in Pennsylvania noted, ‘the very nature of gathering prevents indiscriminate service to the public’.24 As these cases in both Texas and Pennsylvania make clear, there is an uncomfortable fit between gas gathering and the public utility or common carrier framework. Accordingly, it is unclear as to whether, or in what limited situations, eminent domain authority is unavailable to natural gas producers seeking to construct gathering facilities to exclusively gather and transport the gas they and their 15

Tex. Util. Code Ann. Sec. 181.004 (West 2013); Tex. Nat. Res. Code Ann. Sec. 111.019 (West 2013); Ohio Rev. Code Ann. Sec. 4906 (West 2014). 16 Tex. Nat. Res. Code Ann. Sec. 111.002(6) (West 2013). 17 Texas Rice Land Partners, Ltd. v. Denbury Green Pipeline-Texas, LLC, 363 S.W.3d 192, 201 (Tex. 2012).. 18 Tex. Nat. Res. Code Ann. Sec. 111.002 (West 2013). 19 Tex. Utilities Code Ann. Sec. 181.004 (Vernon 2011). 20 16 Tex. Admin. Code. Sec. 3.70 (2015), available at www.sos.state.tx.us/texreg/archive/December 192014/Adopted%20Rules/16.ECONOMIC%20REGULATION.html#132; 39 Tex. Reg. 9969 (19 December 2014), available at www.sos.state.tx.us/texreg/pdf/backview/1219/1219is.pdf 21 16 Tex. Admin. Code 3.70 (2015). 22 66 Pa. Cons. Stat. Ann. Sec. 1104 (West 2014). 23 ‘Application of Laser Ne. Gathering Co., LLC for approval to begin to offer, render, furnish, or supply natural gas gathering & transporting or conveying serv. by pipeline to the pub. in certain townships of Susquehanna Cnty., PA’, 2011 WL 2433056 (19 May 2011). 24 Re Peregrine Keystone Gas Pipeline, LLC, A-2010-2200201, Pa. P.U.C.. (2012).

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affiliates produce.25 In the absence of this authority, companies must negotiate rights of way with each landowner on whose land a gathering line will cross – an arduous process which may prove insurmountable.26 Several states in the Rocky Mountain region have granted pipeline operators the authority to exercise the power of eminent domain without requiring that they qualify as a common carrier or public utility. Wyoming constitutionally grants the use of eminent domain for ‘private ways of necessity, and for reservoirs, drains, flumes, or ditches on or across the lands of others for agricultural, mining, milling, domestic or sanitary purposes’,27 including development and production of oil and gas.28 In many other states, including Wyoming, pipeline companies are granted the power of eminent domain by statute. In Colorado, Wyoming, North Dakota and Utah, state statutes allow condemnation by pipeline operators for the construction and operation of gathering lines.29 These statutory grants, however, generally require that the condemnation is in the public interest and is of reasonable necessity.30 Although a statutory grant includes a declaration of public interest, the condemnor may still be required to demonstrate the public purpose and necessity of the taking.31 In Colorado, public purpose is determined by balancing a number of factors, including a project’s necessity for development of the state’s natural resources.32 State law may also limit the implication of public purpose in a statutory grant. For example, in 2007, in response to a citizen ballot reacting to Kelo v. City of New London, North Dakota passed Senate Bill 2214, which revised North Dakota’s eminent domain statute to specify that ‘private property shall not be taken for use of, or ownership by, any private individual or entity unless that property is necessary for conducting a common carrier or utility business’.33 As a result, eminent domain authority may not be available to a private company 25

Texas Rice Land Partners, Ltd. v. Denbury Green Pipeline-Texas, LLC, 363 S.W.3d 192, 201 (Tex. 2012) (holding that a party must not only hold it self out for public hire, but there must also be a reasonable probability that it will do so). 26 A month after the administrative law judge recommended the commission deny Peregrine’s application for public utility status, Peregrine withdrew its application. S. Ferris, ‘Peregrine withdraws public utility application’, Herald-Standard (14 June 2012). 27 Wyo. Const. Art 1, Sec. 32. 28 Coronado Oil Co. v. Grieves, 603 P.2d 406 (Wyo. 1979). 29 Colo. Rev. Stat. Ann. Sec. 38-5-105 (West 2014); Jost and Matero, ‘Regulatory and Permit Requirements’. 30 Larson v. Chase Pipe Line Co., 514 P.2d 1316 (Colo. 1973) (finding that the public use requirement was satisfied where the company would be operated as a common carrier under federal law); see Wyo. Stat. Ann. Sec. 1-26-815. (West 2014). 31 Berman v. Parker, 348 U.S. 26 (1954); Coronado Oil Co. v. Grieves, 603 P.2d 406 (Wyo. 1979) (citing Baycol, Inc. v. Downtown Dev. Auth., 315 So.2d 451, 455 (Fla. 1975)). 32 Ibid.; although the Colorado Constitution includes provisions for private ways of necessity, the Colorado Court of Appeals, in Akin v. Four Corners Encampment, held that natural gas pipelines were not private ways of necessity within the meaning of the Colorado constitution. 179 P.3d 139 (Colo. App. 2007). 33 N.D. Cent. Code Ann. Sec. 32-15-01 (West 2013); S.B. 2214, 60th Gen. Assemb., Reg. Sess. (N.D. 2007).

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looking to construct a pipeline to gather hydrocarbons from a group of wells or to transport gas solely for its affiliates.34 New Mexico has taken an unique approach that bridges the gap between granting companies general eminent domain authority and limiting such authority only to public utilities. In 1986, the Supreme Court of New Mexico ruled that a ‘pipeline whose sole direct beneficiaries [were] private individuals’ satisfied the public use requirement for condemnation purposes pursuant to the Pipeline Eminent Domain Statute.35 The Court specifically noted the ‘legislature could have chosen to exclude gathering lines from exercising the right of eminent domain, but it did not, as revealed by the clear and unambiguous language of the [Pipeline Eminent Domain Statute]’.36 Presumably in response, seven months later, in April 1987, the New Mexico legislature amended the Pipeline Eminent Domain Statute to expressly exclude gathering lines not operated by public utilities or their affiliates or by operators licensed by the state corporation commission.37 While this could have put an end to the exercise of eminent domain authority for gathering lines altogether, shortly thereafter the New Mexico legislature in 1988 enacted the Gathering Line Land Acquisition Act (the GLLAA).38 The GLLAA provides mineral developers with a straightforward and comprehensive administrative procedure for exercising condemnation authority to obtain an easement for the purpose of constructing a natural gas or petroleum gathering line. The GLLAA defines a mineral developer as the mineral owner, operator, lessee or a natural gas or petroleum pipeline company engaged in production of conveyance by pipeline of natural gas or petroleum.39 This definition closes the gap between those companies conducting gathering for purposes related to mineral development and production and those engaged solely in the midstream market.40 If initial efforts with the property owner are unsuccessful, the GLLAA allows the mineral developer to commence a statutory acquisition process in which a hearing officer is appointed to determine all terms of the acquisition including the route of the easement and compensation paid to the landowner.41 When compared to condemnations by public utilities pursuant to the New Mexico Eminent Domain Code, the GLLAA provides landowners with additional compensation for loss of income, inconvenience, ongoing burdens, and surface reclamation costs.42

34

Akin v. Four Corners Encampment, 179 P.3d 139 (Colo. App. 2007). Kennedy v. Yates, 725 P.2d 572, 573 (N.M. 1986); N.M. Stat. Ann. Sec. 70-3-5 (West 2014). 36 Kennedy, 725 P.2d at 574. 37 1987 N.M. Laws 2167. There are no sources available that specifically indicate legislative intent. 38 N.M. Stat. Ann Sec.. 70-3A-4. 39 N.M. Stat. Ann. Sec. 70-3A-2. 40 Niles, ‘Eminent Domain and Pipelines in Texas’, 281–3, citing Thedford v. Jackson County, 502 S.W.2d 899 (Tex. Civ. App. 1973): ‘The court obviously found that simply transporting gas from a private well to an oil and gas company, if one is not in the business of transporting gas for hire or purchasing gas from other producers, is not enough to obtain common carrier status.’ Ibid., 282. 41 N.M. Stat Ann. Sec. 70-3A-5. 42 Ibid. 35

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State regulations requiring companies to demonstrate common carrier or public utility status as a precondition to the exercise of eminent domain with respect to gathering activities can create inconsistencies in the ability of companies to gather and transport gas from the wellhead to market. These requirements are unduly burdensome and ignore the economic and operational realities of gas gathering and transportation, particularly as it relates to the development of unconventional resources. Likewise, even in states with statutory grants of condemnation authority, some pipeline operators, such as natural gas producers, may be unable to satisfy the public purpose requirement, creating an arbitrary distinction between companies gathering and transporting gas for affiliates as part of regular production operations and those gathering as a separate midstream business. Legislation similar to the New Mexico Gathering Line Land Acquisition Act may provide a path forward for states struggling to balance the necessity of protecting private property ownership rights while preventing waste and ensuring that valuable state resources are efficiently developed. The GLLAA provides an example of tidy solution: landowners are provided with additional measures of protection, strategic behaviour can be overcome and essential midstream infrastructure can be efficiently constructed.

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PETROLEUM LICENSING ON THE UKCS FIFTY YEARS ON: PROBLEMS, SOLUTIONS AND MORE PROBLEMS? John Paterson1

INTRODUCTION The discovery by a state that it may have hydrocarbons under its territory or within its continental shelf brings obvious opportunities and less obvious challenges. The opportunities include potential income, balance of trade and energy security advantages, employment and the like. The challenges take a little longer to appear and in some cases reveal themselves only over the course of decades. The current position of the United Kingdom in relation to the legal and regulatory framework for the exploitation of its offshore oil and gas reserves offers a fascinating case study of emergent challenges and the difficulties attendant on efforts to overcome them. This chapter sketches the outline of this case study. It is of necessity incomplete, given that efforts to reset the legal and regulatory framework are ongoing, but the intention is to highlight the issues that are sometimes overlooked, with a view to informing the current debate in the UK as well as pointing out problems to be avoided in other jurisdictions at an earlier stage of hydrocarbon development. PROBLEMS AND ATTEMPTED SOLUTIONS In common with many states new to the hydrocarbons business, the UK moved quickly but not always wisely in the mid-1960s to establish a licensing approach 1

Educated at the universities of Aberdeen and Edinburgh and at the European University Institute, John Paterson trained as a solicitor in the UK civil service before pursuing an academic career. He worked in Belgium and in England before moving to Aberdeen in 2004. He has long experience of international projects in research, teaching, training and consultancy in the energy field. He is co-editor of Oil and Gas Law: Current Practice and Emerging Trends (now in its second edition) and co-directs the University of Aberdeen’s successful LLM programmes in Oil and Gas Law.

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to the exploration for and exploitation of oil and gas on its continental shelf.2 Early licences reveal the extent to which the country had not understood the obligations that it should impose on licensees and the controls that it should retain over them. Thus, licensees were only required to ensure that exploration obligations were fulfilled within the term of the licence (forty-six years in the early days) rather than within a relatively short initial term, and there were no surrender obligations to ensure that work was carried out efficiently and that relinquished acreage could be recycled.3 The dawning realisation that the state’s interests were not as well protected as they might have been led to the controversial decision to change licence terms retrospectively by way of primary legislation in the mid-1970s. Additional powers in the hands of the Secretary of State were introduced by the Petroleum and Submarine Pipelines Act 1975. That these powers were still not sufficient, however, became clear in the early years of the new century when joint industry and government surveys revealed, first, that a significant number of licensed blocks had not seen any significant exploration activity whilst a significant number of discoveries had not seen any significant development towards production;4 and, second, that in relation to producing assets there was considerable variation in the degree of efficiency with which they were being managed.5 These findings raised the question of the sort of intervention that would be required to improve the position. Whilst retrospective changes to licences were again considered, this was not regarded as a desirable option, sending as it would a problematical signal about the stability of the investment regime in the UK.6 The solution ultimately chosen was what might be described as a hybrid, insofar as it relied upon voluntary compliance by the industry, but with the threat that if such compliance was not forthcoming, then the Secretary of State would make use of his powers under the licence.7 Thus, in the case of greenfield assets the Fallow Initiative was established by way of ministerial guidance,8 whilst in the case of brownfield assets a similar approach was used to introduce the Stewardship Initiative.9 2

3

4 5

6 7 8 9

Continental Shelf 1964 Act and the Petroleum (Production) (Continental Shelf and Territorial Sea) Regulations 1964 (SI 1964/708). All licences issued by the UK government are available on the DECC website. For an example of the problems besetting early licences, see, for example, Licence No. P.001, Minister of Power and BP Petroleum Development Limited, 17 September 1964. Among the issues of note are the very broadly drawn working obligations in Schedule 3. PILOT, The Work of the Progressing Partnership Work Group (2002). PILOT, Maximising Economic Recovery of the UK’s Oil and Gas Reserves: Context for the Brownfields Challenge, Report of the PILOT 2004 Brownfields Studies (March 2005). PILOT, The Work of the Progressing Partnership Work Group, Para 3.2.3.2. PILOT, The Work of the Progressing Partnership Work Group, Para 3.2.3.3. For the current approach, see www.og.decc.gov.uk/UKpromote/regulatory/FallowAcreageInitiative.pdf For the current approach, see Guidance on the Content of Offshore Oil and Gas Field Development Plans, Sec. 6.1 and Appendix 11, available at www.gov.uk/government/uploads/system/uploads/ attachment_data/file/265842/FDP_guidance_notes_November_2013_web.pdf

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The Fallow Initiative essentially requires licensees to report on an annual basis regarding exploration activity and the development of discoveries. Where there is a good reason for a lack of activity or development respectively, then the position is noted and the issue is returned to in the following year. Where no such good reason can be shown to exist, then the licensee has three choices: get on with the required work; transfer the assets to someone who will; or surrender the acreage or discovery to the state.10 The Stewardship Initiative requires all operators to provide a report on their activity on an annual basis. Following a fairly quick review, the Secretary of State is able to report to the vast majority that their operations are satisfactory and that there will be no further review until the following year. For the poorest performing projects, however, the Secretary of State institutes a more thorough review after which if he or she is persuaded that the interests of the state and of the operator are now in alignment (which may have required the operator to institute changes) then the process is complete for another year. Where, however, even after such a review the Secretary of State is not satisfied then he or she can make use of licence powers, for example to require investment or force a change of operator.11 All indications are that these initiatives have been successful, perhaps not least because they both have their origins in joint industry and government discussions. Quite why a voluntary approach is required, however, if the background licence powers really allow the Secretary of State to intervene is a question that will probably not be answered unless and until there is a challenge to their use.12 In the meantime, however, it would appear that the industry as a whole is content to see assets in the hands of those who can make most productive use of them and thus is not minded to quibble over the legal niceties. Indeed, the shadow of the Secretary of State’s possible intervention may be just the incentive that is required in the case of a dysfunctional joint venture where one party is blocking investment that would allow exploration, development or enhanced recovery to go ahead. The challenges of the mature province are such, however, that solving problems at the level of individual joint operating agreements is not likely to be sufficient. As the UK continental shelf (UKCS) sees continued year-on-year reductions in production, as the likelihood of making large as opposed to smaller and more marginal discoveries decreases, and as the infrastructure that would allow marginal discoveries to be developed ages and nears decommissioning, it becomes clear that a more holistic approach to deficiencies in the licensing regime is required. This is the background to the review requested by Ed Davey, the Secretary of State for Energy and Climate Change, from Sir Ian Wood, the then

10

See www.og.decc.gov.uk/UKpromote/regulatory/FallowAcreageInitiative.pdf See Guidance on the Content of Offshore Oil and Gas Field Development Plans. 12 See the discussion in G. Gordon and J. Paterson, ‘Mature province initiatives’, in G. Gordon, J. Paterson and E. Usenmez (eds), Oil and Gas Law: Current Practice and Emerging Trends, 2nd edn (Dundee University Press, 2011), paras 5.33 and 5.47. 11

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recently retired chairman of the Wood Group, in 2013.13 If the nature of the challenges of the mature province appears to call for radical solutions, then Sir Ian’s review does not disappoint.14 Given the radical nature of proposals, the warmth with which it was greeted by industry appears somewhat surprising.15 In essence, what Sir Ian proposes is that, given the problems with current arrangements, a new regulator with new powers is required.16 These powers are described in different ways in different places in the report, and while the idea of a new regulator ‘facilitating’ and ‘encouraging’17 behaviours designed to maximise the recovery of hydrocarbons may not frighten operators, the idea that he or she will be able to ‘require’18 or ‘enforce’19 such behaviours might have been expected to give some pause for thought – all the more so given that Sir Ian is clear that many of the obstacles standing in the way of improved performance on the UKCS can be traced back to the ability of individual operators to make decisions which are in their commercial best interests without having to consider the impact on other operators or the state’s interests as a whole.20 In other words, having become accustomed to a regime characterised over five decades by commercial freedom, there is every indication in Sir Ian’s review that what he sees as being required is a much more interventionist role for the state – and one, significantly, that he sees as being backed up by strong powers. In this last regard, his reference to the insertion of a maximising economic recovery clause in every licence might have been expected to set alarm bells ringing.21 But instead there appeared to be wholehearted support from industry for the review in the months following its publication.22 It might be suggested, however, that by the time the initial steps were taken by government to implement the proposals, a degree of unease was palpable. And while it appears that there is no appetite on the part of the government to alter licences retrospectively, the Department of Energy and Climate Change (DECC) remains clear that the new regulator (now identified as the Oil and Gas Authority, which will ultimately take the form of a government company23) 13

Written Ministerial Statement by Edward Davey: Review of UK offshore oil and gas recovery (10 June 2013), available at www.gov.uk/government/speeches/written-ministerial-statement-byedward-davey-review-of-uk-offshore-oil-and-gas-recovery 14 Sir I. Wood, UKCS Maximising Economic Recovery: Final Report (24 February 2014). 15 See, for example, the immediate response from Oil and Gas UK: ‘We . . . strongly welcome the proposal for a new arm’s length regulator with additional powers and resources’, ‘Wood Review final recommendations can be game changers for UK Continental Shelf’, Press Release (24 February 2015). 16 Wood, UKCS Maximising Economic Recovery, Recommendation 2. 17 Ibid., para 3.3. 18 Ibid., para 3.3. 19 Ibid., Action 11. 20 Ibid., para 2.3. 21 Ibid., Recommendation 3 and Action 11. 22 Oil and Gas UK, ‘Wood Review final recommendations can be game changers’. 23 DECC, ‘Government response to Sir Ian Wood’s UKCS: Maximising Economic Recovery Review’ (July 2014), esp. chapter 2. For the appointment of the Chief Executive, see Statement by Edward Davey on the appointment of Andy Samuel as Chief Executive Officer of the OGA (6 November 2014), available at www.gov.uk/government/speeches/appointment-of-chief-executive-of-the-oiland-gas-authority

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will have powers contained in primary legislation that will be of a quite different sort to those deployed at present in the context of the rather vaguely established Fallow and Stewardship Initiatives. In this regard, the regulator is envisaged as having powers to attend meetings, to have access to data and to impose sanctions, as well as playing a role in dispute resolution.24 All of these powers are to be deployed in relation to the achievement of the overarching objective of maximising economic recovery and both the regulator and operators will have obligations in that regard. This means that in due course the regulator will be able to intervene in relation to such issues as exploration, stewardship and decommissioning (among others) so as to ensure that decisions taken at the level of the joint venture (JV) are in consonance with the MER (Maximising Economic Recovery) UK strategy. In other words, the freedom of individual JVs to focus on their own interests to the exclusion of others would appear to be on the point of disappearing to be replaced by the likes of hub strategies, regional development strategies, delayed decommissioning decisions and other forms of collaboration which, if not entered into voluntarily by the relevant JVs, will be identified, led and ultimately compelled by the regulator.25 The shift from the broad statement of the idea of MER UK towards its detailed implementation has undoubtedly served to concentrate minds within the industry. What will it mean for existing ways of working, for example in relation to the allocation of risk, to have a regulator empowered in this way? The upcoming publication of the evidence submitted in response to the call from DECC in late 2014 will be an early opportunity to see exactly how the industry feels about the coming new order.

24 25

Ibid., esp. chapter 3. Ibid., esp. chapter 4.

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GREENLAND OFFSHORE PETROLEUM REGULATION TOWARDS ‘THE BLUE ARCTIC’ Irina Kim1

Despite declining international oil prices and numerous challenges associated with petroleum extraction, Greenland is committed to expanding and developing its mineral resources sector.2 While exploration of offshore hydrocarbons is viewed as important for Greenland’s economic growth, paying close attention to the environmental standards is critical. The importance of focusing on high safety standards for exploration in the Arctic offshore was emphasised by the Nordic Council of Ministers in the programme for 2015. Under the programme with the working title ‘The Blue Arctic’, the participating countries will join efforts to ensure the level of environmental protection appropriate to the oil and gas activity in the region.3 Despite global environmental concerns, the regulation of offshore petroleum activities in the Arctic remains subject to relatively few, scattered international agreements. While the need for a comprehensive Arctic treaty to address challenges of offshore hydrocarbon development is being argued by legal scholars, Arctic states agreed that the existing legal framework ‘provides a solid founda1

2

3

Irina Kim is a PhD researcher at the Centre for Enterprise Liability (CEVIA), University of Copenhagen. Prior to working in academia, Irina practised law in international law firms and in-house, specialising in natural resources law and business aspects of oil and gas operations. Irina’s primary research area concerns environmental law, and in particular issues of liability for offshore petroleum operations in the Arctic. K. Kielsen, ‘Annual New Year Reception Speech at the Greenland Representation in Copenhagen’ (2015), available at http://naalakkersuisut.gl/en/Naalakkersuisut/News/2015/01/080115-nytaarreception-GL-representation ‘Growth, welfare and values’, Programme for the Danish Presidency of the Nordic Council of Ministers (2015), 22, available at www.norden.org/en/nordic-council/cases/dokument-13-2014

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tion for responsible management through national implementation . . . and is capable of tackling challenges in this area’.4 Thus, there is ‘no need to develop a new comprehensive international legal regime to govern the Arctic Ocean’.5 It is probably safe to assume that no further steps will be made by the Arctic states towards developing a special international law for regulation of offshore petroleum operations. Among the existing legal instruments, the United Nations Convention on the Law of the Sea remains the central foundation for regulation in the Arctic. Various other international agreements and regulations apply to mineral and mining activities in Greenland. Some have been agreed or accepted by the Greenland government, others have been agreed or accepted by the Danish government, on behalf of the Kingdom of Denmark, in respect of all parts of the Kingdom, or in respect of Greenland. Among them are the Convention for the Protection of the Marine Environment of the North-East Atlantic (OSPAR Convention), the United Nations Framework Convention on Climate Change and the Arctic Offshore Oil and Gas Guidelines.6 Although no new comprehensive international regulation for offshore petroleum operations is expected in the future, Greenland remains committed to ‘advancing the existing international legal regulation of the Arctic’.7 Following adoption of the Self-Government Act, legislative powers in the mineral resources area have been transferred to the Self-Government authorities. They took on responsibility to negotiate and conclude international agreements with foreign states and international organisations on matters within the mineral resources area.8 Since established in 2009, these powers have mainly been exercised in the form of agreements with Nordic countries and so-called administrative agreements.9 Ratification work and international cooperation in the form of regional agreements is likely to continue in the future. Further adoption of relevant international conventions may contribute to strengthening the image of Greenland as a safe and reliable natural resource extraction partner.10 While provisions of international agreements are central for offshore petroleum activities in Greenland, exploration and production of oil and gas remains primarily regulated by national laws and applicable agreements between a host government and an international oil company. Fragmented international regulation and the prevalence of national law in the area of petroleum extraction makes it important to focus on advancing Greenland’s mineral resources law, in order to ensure overall safe exploration of petroleum in the Arctic. 4

The Ilulissat Declaration (2008), Arctic Ocean Conference, The Arctic Governance Project, available at www.oceanlaw.org/downloads/arctic/Ilulissat_Declaration.pdf 5 Ibid. 6 P. Vestergaard Petersen, Minerals and Mining: A Practical Global Guide (Globe Law and Business, 2012), p. 112. 7 ‘Kingdom of Denmark Strategy for the Arctic 2011–2020’, 15. 8 ‘Act on Greenland Self-Government’ (Act no. 473 of 12 June 2009), Sec. 12(1). 9 Petersen, Minerals and Mining, p. 113. 10 ‘To the benefit of Greenland’, Report of the Committee for Greenlandic Mineral Resources to the Benefit of Society (2014), 34.

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The regulation of the petroleum industry in Greenland has for many years been based on the Danish legislation, but recently acquired self-government led to the adoption of a new domestic law to govern the area of mineral resources. The Act on Mineral Resources and Mineral Resource Activities adopted by the Parliament of Greenland on 7 December 2009 (hereafter referred to as the ‘Mineral Resources Act’) is the main domestic law in this area. Among other things, the document sets out regulations relevant to exploration and production of hydrocarbons and the rules related to the protection of the environment. The essence of the law reflects the practical approach of self-government to incentivise mineral resources industry while ensuring environmental safety. To a large extent, the Mineral Resources Act is based on the Danish legislation on mineral resources, with few modifications. Some legal practitioners expect that interpretation and administration of the document will also ‘occur in accordance with Danish legal tradition’.11 Despite a well-reasoned and consistent structure, some provisions of the Mineral Resources Act raise questions. Among them are the areas of applicability and general distribution between Danish and Greenlandic law, the extent of the strict liability rule, the attribution of environmental liability, mandatory participation of the state national oil company Nunaoil, and consistency between the articles of the Mineral Resources Act and the provisions of the subordinate documents. Clarity and consistency of the mineral resources law is essential for the future economic growth of Greenland. One of the main goals of self-government is to incentivise private investments in oil exploration activities in Greenland.12 However, investors emphasise the need for effective and clear local mineral resources laws.13 Extraction of oil in Greenland is associated with harsh weather conditions, the technological complexity of petroleum extraction and commitment to the highest standards for safety of petroleum operations. The country may become more attractive for investors and achieve its goal for financial growth, if a coherent and effective mineral resources law offsets the challenges faced by the oil and gas companies. In order to be effective, the law should be consistent and clear on complex and controversial issues, such as liability rules, defences, enforcement, tolerable thresholds, regulatory compliance, joint and several liability, and the role of financial guarantees.14 Associated with the issue of the development of domestic laws is a question of competence of self-government’s authorities supervising mineral resources 11

J. S. Stenderup and P. Holm, The Pursuit of Oil: Environmental Challenges of Search and Extraction (International Law Office, 2011), available at www.internationallawoffice.com/Directory/ Biography.aspx?r=48436&o=1345 12 Greenland Oil and Mineral Strategy, 2014–2018, 9. 13 ‘Grønland’, Grønlands Erhvervsliv – investeringer og udvikling i den arktiske region (2014–2015) ‘Internationale aftalerammer og nationale love’, 39. 14 See Kit Armstrong, ‘Managing environmental legal risks in oil and gas exploration and production activities’, in Zhiguo Gao, Environmental Regulation of Oil and Gas (Kluwer Law International, 1998), p. 359.

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activities.15 Latest reports emphasise the importance of transparency in the distribution of competencies, as well as the focus on upgrading the central administration.16 In the next several years, the Mineral Resources Act is expected to be amended to provide a clearer and more transparent division of competences between local authorities in the areas of licensing and environmental protection, and to transfer powers from Danish environmental authorities to the Greenland Institute of Natural Resources.17 As petroleum projects in Greenland progress into the exploitation phase, the offshore drilling legislation, introduced in 2010, and relevant rules and regulations subordinate to the Mineral Resources Act are expected to receive further development. The goal for ‘The Blue Arctic’ requires a well-established legal framework of each Arctic country. Petroleum projects in Greenland are still in the exploration stage, and the legal basis for regulation of these projects is yet to be tested. For many years Greenland has been applying the Danish legislation for regulation of petroleum operations. Recent moves towards independence and plans to expand the mineral resources sector will affect the development of Greenlandic laws. On an international law level, the newly established self-government will adopt the existing regime and conclude new relevant international agreements. Due to the country’s desire to incentivise investment in the petroleum sector, and considering the needs of investors for enhanced legislation, the focus of the national laws will be on improving consistency, clarity and stability, as well as achieving efficient government organisation. During this challenging period of transformation, Greenland’s mineral resources legislation must strike a delicate balance between investors’ needs, the state’s desire to step up economic growth and ensuring the safety of the vulnerable Arctic environment.

15

Act on Self-Government, Act no. 473 of 12 June 2009, Schedule, List II item 26. ‘To the benefit of Greenland’. 17 Greenland Oil and Mineral Strategy, 2012-2014, 12. 16

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ENERGY JUSTICE: THE YIN AND YANG APPROACH Roman Sidortsov1

One would be hard-pressed to find an energy policy topic that is free of controversy. Whether it is offshore oil and gas development or a community solar farm, people engage in often contentious debates about the pros and cons of a proposed project or policy measure. However, although such debates are frequently centred around the impacts of energy systems on a person, family, community or entire socioeconomic or ethnic group, the ‘human dimension’ is all but removed from the decision-making process. Instead, politicians, government energy planners and corporate executives continue to rely almost exclusively on technical analysis and economic models to make decisions about energy development, production, generation, transportation and distribution.2 Meanwhile, communities displaced due to pipeline construction, children suffering from radiation-related leukaemia and families who have lost their 1

2

Roman V. Sidortsov serves as a Senior Global Energy Fellow at the Institute for Energy and the Environment and teaches Oil and Gas Development and Renewable Energy courses in the distance-learning programme. He is also a Doctoral Researcher at the Scott Polar Research Institute at the University of Cambridge, UK. Mr Sidortsov has taught at Irkutsk State Academy of Law and Economics in Russia and at Marlboro College Graduate School’s Managing for Sustainability programme in the USA. Prior to returning to academia, he practised law in Russia as in-house counsel for an American non-profit organisation, and in the USA as a transactional attorney. His research focuses on legal and policy issues related to the development of sustainable energy systems, energy justice, energy geopolitics, risk governance in the oil and gas sector, and Arctic offshore oil and gas exploration and extraction, with a special emphasis on the Russian Federation, Norway and the USA. He received his first law degrees (Bachelor’s and Masters) from Irkutsk State University in the Russian Federation and his JD and LLM degrees from Vermont Law School. See generally B. Jones, B. Sovacool and R. Sidortsov, ‘Making the ethical and philosophical case for “energy justice”’, Environmental Ethics 37(2) (2015), 145.

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ancestral homes due to climate change impacts are missing from the decisionmaking matrix premised on statistical averages. Such ‘by-products’ of the modern energy systems are not isolated incidents that are easily attributable to a rounding error. They are real and prevalent, and transcend time, space and socio-political formations. This does not mean that the existing energy decision-making analytical and management arsenal is obsolete. Economic and technical considerations are extremely important and, in some cases, are fundamental. Nevertheless, the energy decision-making toolbox needs to be diversified, reorganised and ultimately upgraded. Energy justice can and should be a permanent tool in it, treating energy as a means of serving the ends – real people – and not statistical averages. ‘What is energy justice?’ is a hard question to answer. Because the concept is still in its early stages of scholarly development, we are yet to reach a consensus on the definition. Benjamin Sovacool and Michael Dworkin attempted to answer this question in Global Energy Justice: Problems, Principles, and Practices by matching eight ideas of justice from philosophy with eight real-world energy challenges.3 Benjamin Sovacool, Benjamin Jones and I approached the same question from a slightly different angle. We proposed two fundamental principles of energy justice, prohibitive and affirmative, its yin and yang, by working through the most applicable theories of justice and applying them to the most egregious injustices related to energy development, production, transportation and use.4 One way to define energy justice is to pick a justice theory and apply it to a particular energy-centric problem. This approach has real practical implications because each theory elevates one principal ethical concern over another. Correspondingly, the cosmopolitan theory will examine an energy justice problem through the lenses of universal, worldwide needs without regard for differences in cultures and traditions.5 Procedural justice, on the other hand, will likely focus on how decisions regarding energy systems are made to ensure that the process is not hijacked by technocrats.6 Alternatively, one could define energy justice by using the most applicable justice theories upon which the actual definition can be built, thus building a proto-foundation. In Energy Security, Equality, and Justice my co-authors and I drew on the theories of distributive, procedural and cosmopolitan justice and came up with the following four assumptions: • Assumption 1: every human being is entitled to the minimum of basic goods of life that is still consistent with respect for human dignity . . .7 3

4

5 6 7

B. K. Sovacool and M. H. Dworkin, Global Energy Justice: Problems, Principles, and Practices (Cambridge University Press, 2014), p. xviii. See generally, B. Sovacool, R. Sidortsov and B. Jones, Energy Security, Equality, and Justice (Routledge, 2013). D. Moellendorf, Cosmopolitan Justice (Westview Press, 2002), p. 171. Jones et al., ‘Making the ethical and philosophical case’. Sovacool et al., Energy Security, Equality, and Justice, p. 30.

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• Assumption 2: the basic goods to which every person is entitled also include the opportunity to develop the characteristically human capacities needed for a flourishing human life . . .8 • Assumption 3: energy is only an instrumental good – it is not an end in itself . . .9 • Assumption 4: energy is a material prerequisite for many of the basic goods to which people are entitled . . .10 These assumptions enabled us to propose two fundamental principles of energy justice. The prohibitive principle states that ‘energy systems must be designed and constructed in such a way that they do not unduly interfere with the ability of any person to acquire those basic goods to which he or she is justly entitled.’11 This principle expands the reach of energy justice beyond the concepts of energy access, as well as energy and fuel poverty.12 It does so in two ways. First, it does not limit energy justice to entitlement to energy or energy services. Rather, it suggests that injustice can originate from something other than the lack of these. Second, it brings externalities into the justice discussion. Third, it creates a qualitative dimension for energy justice, affirming that divergent energy systems impact people in different ways.13 The affirmative principle states that ‘if any of the basic goods to which every person is justly entitled can only be secured by means of energy services, then in that case there is also a derivative right to the energy service’.14 The affirmative principle is closer to the three concepts noted above but it limits significantly the entitlement to energy and energy services. There is rarely a single theme in an instance of energy injustice. Plenty of examples exist when energy development has led to community displacement, human rights violations, environmental degradation and even an accident that has resulted in lost lives. This makes pinpointing the exact problems and designing appropriate solutions a hard task. Thus, breaking down such instances into

8

Ibid., p. 35. Ibid., p. 38. 10 Ibid., p. 41. 11 Ibid., p. 42. 12 Although overlapping in part, these three concepts are not the same. The concept of fuel poverty originates from developed countries and refers to households needing to spend over 10 per cent of their income on basic energy services. M. O’Brien, ‘Fuel poverty in England’, The Lancet (5 December 2011). The International Energy Agency (IEA) defines energy poverty as ‘a lack of access to modern energy services. These services are defined as household access to electricity and clean cooking facilities (e.g. fuels and stoves that do not cause air pollution in houses)’. IEA, ‘Energy poverty’, available at www.iea.org/topics/energypoverty. Finally, despite the lack of a common definition of energy access, many include household access to a ‘minimum level of electricity’, ‘safer and more sustainable . . . cooking and heating fuels and stoves’, ‘modern energy [that] enables productive economic activity’ and ‘modern energy for public services’. IEA, ‘Defining and modeling energy access’, available at www.worldenergyoutlook.org/resources/ energydevelopment/definingandmodellingenergyaccess 13 Sovacool et al., Energy Security, Equality, and Justice, pp. 42–6. 14 Ibid., pp. 46–8. 9

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different dimensions makes this task easier. For example, viewing environmental externalities through the temporal dimension makes it easier to recognise potential victims of environmental degradation. Applying the economic dimension of energy justice serves to reveal the true cost of fossil fuels, and doing so through the socio-political lens helps to expose the devastating effect of fossil fuel extraction on society. The geographic allocation of injustices helps to demonstrate how some critical problems attributable to the modern global energy system are not limited to developing countries. Finally, examining the technological dimension reveals energy justice implications that are inherent to certain technologies.15 Despite their philosophical grounding, the prohibitive and affirmative principles are intended for practical application. For this reason, my co-authors and I introduced a model for incorporating energy justice into decision-making processes – the energy justice checklist. The checklist spans across the five dimensions listed above and gives real-world examples of how the principles could apply.16 Bringing energy justice into a government office, legislative floor and corporate boardroom will not be easy. A plethora of cultural, administrative and political barriers stand guard over the vault of the status quo. Yet energy justice should not be viewed as a threat to the current methods employed in energy decision-making, only to their absolute hegemony. The concept can enrich the quantitative models and matrices by unveiling new qualitative categories, connecting ‘numbers’ to real human lives, and, perhaps most importantly, bringing the much needed ethical dimension into the energy sector. This is also an opportunity for academia to lead by example. Economists should not be afraid to have their models scrutinised by anthropological case studies, and engineers should be open to working with sociologists and human rights lawyers to examine the humanitarian implications of energy projects. After all, the vast majority of us agree that a just, fair and equitable world is the world in which we and our children would like to live.

15 16

See, generally, Ibid. Ibid., pp. 203–9.

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SUSTAINABLE DEVELOPMENT AND ENERGY JUSTICE: TWO AGENDAS COMBINED Kirsten E. H. Jenkins1

As acknowledgment that our current patterns of energy systems are frequently volatile and unsustainable, economies across the world are reworking the established patterns of energy supply, distribution and consumption.2 But who gets the energy? Who owns it? In what form? And at what costs? Not only are the physical infrastructures of energy supply beginning to change, but such questions are generating new awareness of the links between energy and social justice;3 it is in this context that the concept of energy justice has emerged, a concept that I believe directly complements and makes tangible many sustainable development goals. The concept of sustainable development has been well developed and accepted throughout the political system, appearing in European and nationallevel energy strategies, and wider afield. The European Commission’s ‘Energy 2020: a strategy for competitive, sustainable and secure energy’ places sustainability at its core,4 yet explicit references to the ideas of justice and equity 1

2

3

4

Kirsten Jenkins is a PhD candidate at the University of St Andrews. She previously undertook a Master of Research degree in Sustainable Development and a Bachelor of Science degree in Sustainable Development at the same institution. Her Economic and Social Research Council funded PhD studies focus on discourses of energy justice throughout the nuclear energy system. Kirsten hopes to progress to a career in academia following her PhD, and has a strong personal interest in Scottish energy provision and Arctic energy developments. G. Bridge, S. Bouzarovski, M. Bradshaw and N. Eyre, ‘Geographies of energy transitions: space, place and the low-carbon economy’, Energy Policy 53 (2013), 331–40. M. S. Hall, S. Hards and H. Bulkeley, ‘New approaches to energy: equity, justice and vulnerability’, Local Environment: The International Journal of Justice and Sustainability 18(4) (2013), 413–21. European Commission, Energy 2020 – A Strategy for Competitive, Sustainable and Secure Energy (Publications Office of the European Union, 2010).

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are notably absent. But sustainable development is embedded in the notion of equity and justice,5 and the desire for a sustainable energy system necessitates policy developments that have these concepts at their core. In this regard the newly emerging energy justice agenda is both fundamental and timely. Energy justice ‘aims to provide all individuals across all areas with safe, affordable and sustainable energy’,6 and classically carries three core tenets which emphasise distributional, procedural and recognition justice.7 The first tenet, distributional justice, recognises the inherently spatial nature of the concept and includes both the physically unequal allocation of environmental benefits and ills, and the uneven distribution of their associated responsibilities.8 It recognises that issues in specific localities become entwined with the desirability of technologies more generally,9 and represents a call for the even distribution of benefits and ills on all members of society regardless of income, race and so on. Some resources are naturally and unavoidably unevenly distributed – the location of wind resources, for example – and such claims for justice require that evidence of inequality is combined with an argument for fair treatment.10 Research has shown unequal placement of nuclear facilities in areas of low income, for example.11 Procedural justice, the second tenet, manifests as a call for equitable procedures that engage all stakeholders in a non-discriminatory way.12 It states that all groups should be able to participate in decision-making, and that their decisions should be taken seriously throughout. It also requires participation, impartiality and full information disclosure by government and industry,13 and appropriate and sympathetic engagement mechanisms.14 This includes, as an illustration, questions arising around how and for whom community renewables projects are developed.15 5

B. Hopwood, M. Mellor and G. O’Brien, ‘Sustainable development: mapping different approaches’, Sustainable Development 13 (1) (2005), 38–52. 6 D. McCauley, J. R. Heffron, H. Stephan and K. Jenkins, ‘Advancing energy justice: the triumvirate of tenets’, International Energy Law Review 32(3) (2013), 1–5, at 1. 7 K. Bickerstaff, H. Bulkeley and J. Painter, ‘Justice, nature and the city’, International Journal of Urban and Regional Research 33(3) (2009), 591–600. 8 G. Walker (2009), ‘Beyond distribution and proximity: exploring the multiple spatialities of environmental justice’, Antipode 41(4), 614–36. 9 S. Owens and L. Driffill, ‘How to change attitudes and behaviours in the context of energy’, Energy Policy 36(2008), 4412–18. 10 M. Eames and M. Hunt, ‘Energy justice in sustainability transitions research’, in K. Bickerstaff, G. Walker and H. Bulkeley (eds), Energy Justice in a Changing Climate: Social Equity and Low-carbon Energy (Zed Books, 2013). 11 J. Sze and J. K. London, ‘Environmental justice at a crossroads’, Sociology Compass 2(4) (2008), 1331–54. 12 R. Bullard, ‘Environmental justice in the 21st century’, in J. Dryzek and D. Sclosberg (eds), Debating the Earth (Oxford University Press, 2005), pp. 431–50. 13 R. A. Davies, ‘Environmental justice as subtext or omission: Examining discourses of anti-incineration campaigning in Ireland’, Geoforum 37 (2006), 708–24. 14 H. Todd and C. Zografos, ‘Justice for the environment: developing a set of indicators of environmental justice for Scotland’, Environmental Values 14 (4), 483–501. 15 G. Walker and P. Devine-Wright, ‘Community renewable energy: What should it mean?’, Energy Policy 36(2) (2008), 497–500.

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The third tenet is recognition justice. Although often a core element of procedural justice, recognition entails more than fair and effective participation and requires that individuals must be fairly represented, that they must be free from physical threats and that they must be offered complete and equal political rights. It may also manifest as misrecognising – a distortion of people’s views that may seem demeaning or contemptible.16 Thus it includes calls to recognise the divergent perspectives of different ethnic, racial and gender differences.17 These tenets are informed by research that is concerned with how justice is perceived in a real-world context,18 and whilst the tenets naturally intersect and carry differing conceptions and characterisations according to the context,19 in providing this tenet framework they contribute to effective policy. The tenets most frequently emerge in relation to fuel poverty and energy affordability,20 but this is just one means through which these principles can be applied. Indeed, I argue they should be integrated throughout the energy system, from resource extraction right through to consumption and waste; a shift towards energy ‘systems’ justice that necessitates an international policy focus on the entire energy chain: production, conversion, transmission, distribution, energy consumption and waste.21 This multi-scalar focus acknowledges that policy and practice in one location can have international consequences that affect multiple scales, and interact with global networks.22 As an example, the unequal weighting of benefits from nuclear power are frequently decoupled from the impacts of uranium mining; an externalisation of justice impacts that is all but neglected from policy. This chapter draws three conclusions. First, a sustainable energy system should be a just one, an idea that although perhaps embedded in some energy strategies is neither explicit nor widespread enough. Indeed, whilst the concept of energy justice has received early favour, appearing in a growing body of academic literature around cities and fuel poverty, it has yet to make policy 16

D. Schlosberg, ‘The justice of environmental justice: reconciling equity, recognition, and participation in a political movement’, in A. Light and A. De-Shalit (eds), Moral and Political Reasoning in Environmental Practice (MIT Press, 2003), pp. 77–107. 17 N. Fraser, ‘Social justice in the age of identity politics’, in G. Henderson and M. Waterstone (eds), Geographical Thought: A Praxis Perspective (Routledge, 2009), pp. 72–91. 18 G. Walker and R. Day, ‘Fuel poverty as injustice: integrating distribution, recognition and procedure in the struggle for affordable warmth’, Energy Policy 49 (2012), 69–75. 19 C. Butler and P. Simmons, ‘Framing energy justice in the UK: the nuclear case’, in K. Bickerstaff, G. Walker and H. Bulkeley (eds), Energy Justice in a Changing Climate: Social Equity and Low-carbon Energy (Zed Books, 2013). 20 S. Fuller and H. Bulkeley, ‘Energy justice and the low-carbon transition: assessing low-carbon community programs in the UK’, in K. Bickerstaff, G. Walker and H. Bulkeley (eds), Energy Justice in a Changing Climate: Social Equity and Low-carbon Energy (Zed Books, 2013). 21 K. Alanne and A. Saari, ‘Distributed energy generation and sustainable development’, Renewable and Sustainable Energy Reviews 10(6) (2006): 539–58; L. Gagnon, C. Belanger and Y. Uchiyama, ‘Life-cycle assessment of electricity generation options: the status of research in 2001’, Energy Policy 30 (2002), 1267–78. 22 R. Holifield, M. Porter and G. Walker, ‘Introduction: spaces of environmental justice: frameworks for critical engagement’, Antipode 41(4) (2009), 591–612.

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ground. Energy justice should be adopted as a fundamental policy concept in tandem with, and as a complement to, sustainable development. Second, the concept of energy justice and its tenet framework provides a matrix or checklist through which it is possible to assess the justice ‘performance’ and true social impacts of our energy system. By applying distributional, procedural and recognition justice concepts we can begin to analyse the true social costs and the real sustainability of our energy choices. Finally, recognising the globalised nature of our energy systems and their impacts, energy policy is required to take into account the international justice implications of energy choices – a cradle-to-grave approach that reveals the true social cost (and potential) of our energy infrastructures. Sovacool et al. conclude their book Energy Security, Equality and Justice by stating that ‘the incorporation of considerations of justice into energy policymaking will alter how we view entire energy systems’.23 In light of widespread socio-technical change in our energy systems, and as acceptance that sustainable development is a concept underpinned by concerns of justice and ethics, this certainly needs to be the case.

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B. K. Sovacool, R. V. Sidortsov and B. R. Jones, Energy Security, Equality and Justice (Routledge, 2013), pp. 209, 201.

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ASSESSING THE JUSTICE IMPLICATIONS OF ENERGY INFRASTRUCTURAL DEVELOPMENT IN THE ARCTIC Darren McCauley,1 Robert Rehner2 and Maria Pavlenko3

INTRODUCTION We propose the application of an emerging research agenda in ‘energy justice’ to the context of energy exploration in the Arctic region. The US is one of the Arctic states directly involved in energy exploration, alongside an increasingly observant European Union. Almost a third of the world’s undiscovered gas and 13 per cent of the world’s undiscovered oil may be found there, mostly offshore 1

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Darren McCauley held full-time lectureships at Trinity College Dublin, Queen’s University Belfast and the University of Stirling, as well as fellowships at the BMW Institute at Georgetown University in Washington, DC, the Institute for a Sustainable World at Queen’s University Belfast and the Centre for History and Policy at Stirling University. He is involved in a wide range of energy-based academic and commercially funded research and also retains a keen interest in complementary areas of research, seeking to understand technology-society relationships such as biofuels, biotechnology, micro-generation third-generation nuclear reactors. Robert Rehner was consultant and financial auditor at KPMG Germany for a range of different industries, including practitioners within the renewable energy sector, before joining the University of St Andrews as Research Fellow for sustainable energy. His research interests evolve around different energy sources and the implications of energy infrastructure on environmental and social structures. Complementary to this he is exploring possible electricity market implications in the context of the nuclear phase-out in Germany. Maria Pavlenko is a Research Analyst at West Sands Advisory Ltd, a consultancy firm that specialises in supporting strategic decisions of businesses in the emerging and frontier markets. This involves conducting research to identify, analyse and monitor developments and trends that may impact commercial interests in a variety of sectors, e.g. financial, energy, political and legal, in Russia, CIS and Latin America. Maria retains a keen interest in energy-related topics with a focus on the sustainability of Arctic resource exploration. Her research interests are largely in the Arctic oil and gas businesses, in particular their behaviours in regards to stakeholders as well as their social accounting and CSR practices.

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under less than 500 metres of water.4 In an age of resource depletion, researchers need to pay greater attention to justice concerns in energy policy. Energy justice provides a framework for assessing the justice implications – which are distribution, procedural, recognition – of current policy decisions as well as making practical recommendations.5 We therefore identify some key injustices and recommendations with regards to energy infrastructural development in the Arctic. THE CONTEXT OF ENERGY INFRASTRUCTURAL DEVELOPMENT IN THE ARCTIC Oil and gas extraction and production takes place on the basis of resource ownership. The Arctic states are Canada, Denmark (with Greenland, an autonomous Danish dependent territory, and the Faroe Islands), Finland, Iceland, Norway, Russia, Sweden and the United States. However, according to the 1982 United Nations’ Convention on the Law of the Sea (UNCLOS), the right to explore natural resources in the ocean belongs to the coastal states within the distance of their Exclusive Economic Zones (EEZ), that is, 200 miles (United Nations 1982). Therefore, only five of the Arctic states can legally exploit oil and gas within the Arctic Circle, namely Canada, Denmark, Norway, Russia and the USA. Non-Arctic states such as China, Japan, India and Singapore as well as the European Union have expressed their interest in engaging in Arctic-related activities from research programmes to direct extractive operations.6 Some non-Arctic-based companies take part in joint projects with companies from the Arctic states, for example Italian Eni currently has a joint exploration agreement with Russian Rosneft. This creates a unique operational environment where a few actors representing countries with diverse economic, political and cultural backgrounds are responsible for a vulnerable environmental complex and the intimately linked future of 400,000 indigenous people. Activities of energy companies that are exploring oil and gas in the Arctic are likely to determine the Arctic’s economic, social and environmental well-being in the years to come. DISTRIBUTIONAL JUSTICE The first tenet of energy justice is distributional justice. Energy justice is an inherently spatial concept that includes both the physically unequal allocation of environmental benefits and ills and the uneven distribution of their associated responsibilities,7 for example exposure to risk. Thus, energy justice can appear as a situation where ‘questions about the desirability of technologies in 4

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D. Gautier, K. Bird, R. Charpentier, A. Grantz, D. Houseknecht, T. Klett, T. Moore, J. Pitmand, C. Schenk, J. Schuenemeyer, K. Sorensen, M. Tennyson, Z. Valin and C. Wandrey, ‘Assessment of undiscovered oil and gas in the Arctic’, Science 324 (2009), 1175–9. D. McCauley, R. Heffron, H. Stephan and K. Jenkins, ‘Advancing energy justice: the triumvirate of tenets’, International Energy Law Review 32(3) (2013), 107–10. O. R. Young, ‘Arctic futures: the politics of transformation’, in J. Kraska (ed.), Arctic Security in an Age of Climate Change (Cambridge University Press, 2011). G. Walker, ‘Beyond distribution and proximity: exploring the multiple spatialities of environmental Justice’, Antipode 41(4) (2009), 614–36.

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principle become entangled with issues that relate to specific localities’.8 The siting of oil rigs could, of course, pose a significant threat for communities. The most recent examples of distributional injustices have, in fact, involved wind farms. A proposed development by Finnmark Kraft AS in the predominantly Sami county of Finnmark could, for example, disrupt reindeer populations – resulting in significant opposition. The recession of the ice caps is therefore encouraging the development of a wide range of infrastructural energy projects, both on- and offshore. Fluctuating oil prices will not hinder the appearance of distributional energy injustices. Perhaps the most striking developments in this area are, in fact, unsited. Russia’s Northern Sea Route (NSR) reduces shipping times between Europe and Northeast Asia by 30 to 50 per cent. Shipping routes threaten livelihoods such as fishing as well as establishing a permanent risk of future oil tanker spills in the region due to transportation activities. Despite significant fluctuations in shipping in the area, the increased interest from non-Arctic states from Asia will no doubt increase concern about the impact of shipping (leading to a new Polar Code under negotiation at the International Maritime Organization). PROCEDURAL JUSTICE Second, procedural justice manifests as a call for equitable procedures that engage all stakeholders in a non-discriminatory way.9 It states that all groups should be able to participate in decision-making, and that their decisions should be taken seriously throughout. Local communities such as the indigenous Sami people are scattered across mostly the northern parts of Norway, Sweden, Finland and Russia (all Arctic states) living off fishing and reindeer-herding. Thus they are heavily dependent on the local ecosystems. Hence, while indirectly benefiting from the financial advantages of the resource exploitation activities within the Arctic region, they are highly affected by any negative impacts of such activities, representing the distributional aspects of energy justice. Early intervention is paramount for an effective consultation process. The President of the Sami Parliament, Aili Keskitalo, commented in Tromso, Norway, in January 2015, ‘[t]here needs to be some prior agreement on the siting of infrastructural projects, rather than at a later stage, which is all too common’.10 She outlined several instances whereby communities were involved after development had taken place. More positive examples, however, were also raised, where companies took a more proactive and constructive approach. From siting decisions to projected habitat destruction, the Sami people can help developers achieve common outcomes. Procedural justice is therefore more than simply inclusion. It also involves the mobilisation of local knowledge. 8

S. Owens and L. Driffill, ‘How to change attitudes and behaviours in the context of energy’, Energy Policy 36(12) (2008), 4412–18. 9 B. Sovacool and M. H. Dworkin, Global Energy Justice: Principles, Problems, and Practices (Cambridge University Press, 2014). 10 European Energy Justice Network, ‘Mobilizing procedural justice in the Arctic’ (4 February 2015), available at www.energyjustice.eu/#!Mobilizing-Procedural-Justice-in-the-Arctic/ccdf/3ED6147E7312-4932-A163-EFB842FEE694

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RECOGNITION BASED JUSTICE The third tenet of energy justice is recognition justice. Recognition is not the same as participation, but instead manifests as ‘the process of disrespect, insult and degradation that devalue some people and some places identities in comparison to others’.11 It may manifest itself not only as a failure to recognise but also as misrecognising – a distortion of people’s views that may appear demeaning or contemptuous.12 Thus it includes calls to recognise the divergent perspectives rooted in social, cultural, ethnic, racial and gender differences. From this perspective, energy companies and governments need to recognise the significant potential of local knowledge. Indigenous people are central to monitoring not only the increase in tourism in the far north but equally the intentions of business to develop there. Cultural pluralism is a place for creative industry. ‘Companies need to realise that local communities offer more than opposition . . . [we] offer a wealth of local knowledge,’13 Aili Keskitalo elaborates further. Fishing- or reindeer-based livelihoods should be respected. But more attention should be paid to the knowledge creation this involves with its implications for siting and procedural-based decisions. Land use change is a key challenge for indigenous peoples – who moderates if and where land is used for other purposes? We therefore need holistic management plans where we focus on land and sea equally. IMPLICATIONS Dictated by the unequal distribution of benefits and threats of oil and gas, justice on the procedural and recognition level must be an imperative to not just respect or include, but rather to mobilise local communities within the decisionmaking processes for governments and businesses. Currently six international institutions representing indigenous Arctic peoples have representation within the Arctic Council as one of the main governance bodies of the Arctic, next to the eight Arctic member states. This is one of the engagement mechanisms for minority groups. It serves as a good example for inclusion in decision-making. Yet the influence of local communities on corporations and lower-level institutions within the exploitation processes of oil and gas, transport and processing is questionable. This self-reflection and acceptance to adapt must be reciprocated by energy companies, which would allow for economic growth in the region while minimising the risk of local habitat and ecosystem disruption.

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Walker, ‘Beyond distribution and proximity’. Sovacool and Dworkin, Global Energy Justice. 13 European Energy Justice Network, ‘Mobilizing procedural justice in the Arctic’. 12

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ENERGY POVERTY AND AFFORDABLE SUSTAINABLE ENERGY TECHNOLOGIES (ASETS) Lakshman Guruswamy1

The extent to which energy is arguably the primary determinant of human progress has been asserted and elaborated by a rich, albeit neglected seam of writers and thinkers spanning the life sciences, mathematics, sociology, anthropology, engineering and philosophy. They have described the phenomenon of exosomatic energy – the process by which societies have used a variety of technologies to convert natural resource to useful energy able to do jobs they could not otherwise undertake. These writers have also demonstrated that energy has and is changing and sustaining human social systems.2 What is undeniable is the extent to which modern industrialised societies – the high-energy world – assumes the ubiquitous availability of energy for domestic, commercial and industrial uses: transportation, food production, information technology, national security, health care, cooking, lighting, mechanical power, chemical production and general economic growth.

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Lakshman Guruswamy is Nicholas Doman Professor of Law, University of Colorado at Boulder. This chapter is derived from, and reproduces his earlier writings. For example, H. Spencer, The Principles of Sociology, 3 vols, vol. 3, p. 356 (D. Appleton and Company, 1896); A. McKinnon, ‘Energy and society: Herbert Spencer’s “energetic sociology” of social evolution and beyond’, Journal of Classical Sociology 10(4) (2010), 439–55, available at http://jcs.sagepub.com/content/10/4/439; Leslie White, The Evolution of Culture: The Development of Civilization to the Fall of Rome (McGraw-Hill, 1959); F. Cottrell, Energy and Society: The Relation Between Energy, Social Change, and Economic Development (AuthorHouse 2009), p. 7; N. Georgescu-Roegen, The Entropy Law and the Economic Process (iUniverse, 1999); Herman E. Daly, Beyond Growth: The Economics of Sustainable Development (Beacon Press, 1997).

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In stark contrast to the high-energy world, nearly one-third of the world’s population still lack access to appropriate forms of energy adequate to meet their basic needs. Globally, around 2.8 billion people (the ‘Other Third’ or ‘energy poor’ (EP)) have little or no access to beneficial energy that meets their needs for: (1) cooking and heating; (2) clean water and sanitation; (3) illumination; (4) transportation; and (5) basic mechanical power essential for performing a variety of domestic and commercial functions. More than 95 per cent of the EP live either in sub-Saharan Africa or developing Asia, predominantly (84 per cent) in rural areas. They cook by burning polluting energy such as biomass, resulting in 3.5 to 4 million deaths every year, primarily of women and children.3 A lack of energy for illumination prevents women and children from studying at night, affects the functioning of schools and hospitals and makes life dangerous after dark.4 Polluted drinking water causes 3.5 million deaths, largely among children.5 The lack of motive power or mechanical energy for pumping water for domestic and agricultural use, ploughing fields, transport, metal works and agro-processing, such as grinding food, thwarts any livelihoods requiring energy.6 Even the most rudimentary forms of rural agriculture need energy for water pumping, irrigation, ploughing, harvesting, milling, grinding and processing food. Generating income through small businesses requires energy to transport and distribute goods and services to markets, and for telecommunications. Water treatment plants that provide safe drinking water for communities and schools require energy. Hospitals need energy for refrigerating vital medications and vaccinations. Education calls for energy for lighting and heating of schools, while students need lighting at home to do their homework. Not surprisingly, access to efficient and affordable energy services is also a prerequisite for achieving the Millennium Development Goal (MDG) relating to poverty eradication.7 The EP cannot be situated within the simplistic socio-political division of the world into developing and developed countries, or north and south.8 For

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G. Legros, I. Havet, N. Bruce and S. Bonjour, The Energy Access Situation in Developing Countries: A Review Focusing on Least Developed Countries and Sub Saharan Africa (United Nations Development Programme: Environment and Energy Group, and World Health Organization, 2009). The World Health Organization estimates that indoor air pollution causes 4 million deaths: World Health Organization, ‘Household air pollution and health’ (2014), available at www.who.int/mediacentre/factsheets/fs292/en Generally, M. Luckiesh, Artificial Light: Its Influence Upon Civilization, 8th edn (Library of Alexandria, 1920). A. Prüss-Üstün, R. Bos, F. Gore and J. Bartram, Safer Water, Better Health: Costs, Benefits, and Sustainability of Interventions to Protect and Promote Health (WHO Library, 2004, updated 2008), Table 1. L. Bates, S. Hunt, S. Khennas and N. Sastrawinata, Expanding Energy Access in Developing Countries: The Role of Mechanical Power (Practical Action Publishing Ltd, 2009), p. 2. United Nations, ‘Millennium Development Goals and beyond 2015’, available at www.un.org/ millenniumgoals/index.shtml The WTO requires countries to self identify as developing or developed countries: World Trade Organization, ‘Who Are the Developing Countries in the WTO?’, http://www.wto.org.

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example, the least developed countries (LDCs) are a subset of nations within the developing world. The LDCs consist of forty-nine countries and 767 million people located primarily in Africa and Asia. The LDCs have been officially identified by the UN as ‘least-developed’ in light of their low income (three-year average gross national income (GNI) per capita of less than $992), weak human assets (low nutrition, high mortality, lack of school enrolment and high illiteracy), high economic vulnerability, exposure to natural shocks and disasters, prevalence of trade shocks, economic smallness and economic remoteness.9 A joint report of the United Nations Development Programme (UNDP) and the World Health Organization (WHO) addressing access to energy articulated some of the differences between LDCs and the rest of the developing world.10 While 28 per cent of people in developing countries lack access to electricity, the number in the LDCs is 79 per cent.11 The plight of the LDCs may be contrasted to other developing countries, sometimes called newly industrialised countries (NICs), that have made tremendous economic strides in recent decades.12 This category includes the BRIC countries of Brazil, Russia, India and China,13 South Africa and the ‘Asian Tigers’ of Taiwan, Singapore, Hong Kong and South Korea.14 It also includes Thailand, Indonesia, Malaysia and the Philippines, which are following the trajectory of exceptional economic growth and rapid industrialisation of the Asian Tigers and have consequently been dubbed ‘Tiger Cub Economies’.15 Important categories within these NICs have used fossil fuels to advance up the energy ladder. The LDCs, who are trapped at the bottom of the energy ladder, do not manifest such economic advances. While identifying at least two major categories within the developing countries, LDCs and NICs, it is important to establish that not all sectors within NICs have access to clean energy or electricity. In addition to the LDCs, the EP populate swathes of NICs like India and, to a lesser extent, China. The EP in these countries suffer from a dearth of energy in their households, are denied the chance of making a living whether by way of agriculture, industry or crafts, and lack energy for their hospitals and schools serving their communities. The lack of access to energy suffered by a significant share of the planet led the United Nations to declare 2012 the International Year of Sustainable Energy for All, and the entire decade as the Decade of Sustainable Energy for All.16 Moreover, the UN announced a goal of universal, primarily electrical,

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http://unohrlls.org/about-ldcs/criteria-for-ldcs/. Legros et al., The Energy Access Situation. 11 Ibid., p. 10. 12 These countries are also recognised as ‘Advanced Developing Countries’: US Aid, ‘List of Advanced Developing Countries’, available at http://www.usaid.gov 13 N. Akoukou Thompson, ‘BRICS: industrialized countries with growing economic power’, Latin Post (2 January 2014). 14 R. J. Barro, ‘The East Asian Tigers have plenty to roar about’, Business Week (27 April 1998). 15 Y. Makabenta, ‘No miracle, just a tiger cub economy’, The Manila Times (26 May 2014). 16 UN GA, Resolution adopted by the General Assembly, International Year of Sustainable Energy for All, UN Doc. A/RES/65/151 (16 February 2011). 10

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energy access by 2030.17 World leaders at the UN Conference on Sustainable Development 2012, also called the Rio+20 CSD, endorsed the outcome document of the conference that contains these goals, entitled ‘The future we want’.18 The Open Working Group (OWG) established by the Rio+20 CSD to better articulate its goals, submitted its report in July 2014.19 Among the eighteen goals enumerated by the OWG is a stand-alone goal on energy (goal no. 7) calling for access to affordable, reliable, sustainable and modern energy for all.20 This energy has been understood as electricity. While access to electricity must remain the laudable final objective, the daunting additional costs of electricity which requires an estimated $17 trillion21 and the time it will take to do so – realistically thirty years – will shunt the EP into limbo unless interim measures are also taken. Affordable Sustainable Energy Technologies (ASETs) seek to bridge the gap between the capitalintensive advanced technologies of the developed world, like electricity, and the traditional subsistence technologies of the EP. The purpose of ASETs is to free the EP from the oppressive impacts of unhealthy and unreliable energy access, and to facilitate sustainable development in the LDCs. Beneficial energy, based on ASETs, can provide such intermediate energy. ASETs include: clean fuels, clean stoves, illumination by photovoltaic lights, decentralised mini grids based on solar, wind and biomass-generated electricity, treadle pumps, improved harnesses and yokes which boost the performance of draft cattle, better axles for transport by cart, simple windmills for pumping water, grain grinding appliances and low-cost bicycles.

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UN, ‘Sustainable energy for all’, a vision statement by Ban Ki-moon, Secretary-General of the United Nations (November 2011), available at www.se4all.org/wpcontent/uploads/2013/09/ SG_Sustainable_Energy_for_All_vision_final_clean.pdf 18 UN GA Res. 66/288, adopted by the General Assembly on 27 July 2012, ‘The future we want’, UN Doc. A/RES/66/288, Annex (11 September 2012), available at www.uncsd2012.org/content/ documents/727The%20Future%20We%20Want%2019%20June%201230pm.pdf 19 UN GA, ‘Report of the Open Working Group of the General Assembly on sustainable development goals’, UN Doc. A/68/970 (12 August 2014), available at www.un.org/ga/search/view_doc. asp?symbol=A/68/970&referer=http://www.google.com/url?sa=t&Lang=E 20 Ibid., Goal 7. 21 M. Bazilian and R. Pielke, ‘Defining energy access for the world’s poor’, Issues in Science and Technology 29(4) (2013), 74–8. The authors assume access to electricity at a level provided by Bulgaria and South Africa.

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CHALLENGING ENERGY POVERTY POLICIES: INSIGHTS FROM SOUTH-EASTERN EUROPE Saska Petrova1

INTRODUCTION Energy poverty has been defined as a situation when a household suffers from inadequate energy services in the home.2 The condition is also known as fuel poverty in several developed-world contexts. Estimates show this form of deprivation affects approximately 10 per cent of the population in the European Union.3 While fuel poverty has been relatively well recognised in the United Kingdom and Ireland since the 1990s,4 it only received policy acknowledgment at EU level following the adoption of the Third Energy Package in 2009. Three factors have been identified as key determinants of energy poverty at household level: high energy prices, low incomes and energy efficiency. However, research has shown that not only is such a conceptualisation of the problem static and 1

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Saska Petrova is a Lecturer at the University of Manchester. Her main research interests are in intra-community relations and vulnerabilities as they relate to natural resource management, energy flows, social justice and local governance. She is also the research coordinator of the Centre for Urban Resilience and Energy (CURE), which combines the work of twenty world-leading scholars focusing on the spatial and social dimensions of sustainability transitions. Many of the findings from her work are reported in her monograph Communities in Transition (Ashgate, 2014) as well as a number of papers in leading scientific journals such as Environment and Planning A, Urban Studies, Geoforum, Area, Energy Policy and Geojournal. S. Buzar, Energy Poverty in Eastern Europe: Hidden Geographies of Deprivation (Ashgate, 2007). H. R. Thomson and C. Snell, ‘Quantifying the prevalence of fuel poverty across the European Union’ (2012), unpublished manuscript. B. Boardman, Fixing Fuel Poverty: Challenges and Solutions (Earthscan, 2010).

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reductionist, but it neglects important social and housing aspects5 and fails to reflect the real-life complexity6 and geographical contingency of the issue.7 Furthermore, there has been a limited amount of academic research into the everyday experience of energy deprivation at the household level.8 This chapter has, therefore, two aims: first, to challenge existing policy conceptualisations of energy poverty by providing an alternative theoretical framework; and second, to broaden existing understandings of the phenomenon by exploring a set of housing aspects that have been marginalised to date. The outline of energy poverty policies and concepts in the first part of the chapter is based on a series of conceptual and documentary analyses, while the discussion in the second part of the chapter uses evidence from an ethnographic case study of experiences of domestic energy deprivation in Thessaloniki (Greece) – a context that has seen a rapid rise in poverty and unemployment as a result of the post-2008 economic crisis.9 The final part of the chapter drafts several policy recommendations and opens questions for future discussion. ENERGY POVERTY POLICIES Energy poverty has been a challenging issue for both academics and policymakers. While the former have been struggling with the conceptualisation and investigation of the driving forces and implications of energy poverty, the latter have been faced by the challenge of how to identify, measure and combat the problem. Energy poverty became part of the EU policy agenda thanks to its inclusion within the Directives 2009/72/EC and 2009/73/EC regarding the rules for the internal market in electricity and natural gas supply.10 According to this set of policies, the member states are required to develop a definition of vulnerable customers which may refer to energy poverty and, among other things, not allowing their electricity to be disconnected in critical times. But the measures targeted at vulnerable customers fall under the responsibility of 5

S. Bouzarovski and S. Petrova, ‘The EU energy poverty and vulnerability agenda: an emergent domain of transnational action’, in J. Tosun, S. Biesenbender and K. Schulze (eds), Energy Policy Making in the EU (Springer, 2015). 6 S. Petrova, M. Gentile, I. H. Mäkinen and S. Bouzarovski, ‘Perceptions of thermal comfort and housing quality: exploring the microgeographies of energy poverty in Stakhanov, Ukraine’ (2013) Environment and Planning A 45(5) (2013), 1240–57. 7 S. Bouzarovski, S. Petrova, M. Kitching and J. Baldwick, ‘Precarious domesticities: energy vulnerability among urban young adults’ in K. Bickerstaff, G. Walker and H. Bulkeley (eds), Energy Justice in a Changing Climate: Social Equity and Low-carbon Energy (Zed Books, 2013). 8 S. Roberts, ‘Energy, equity and the future of the fuel poor’, Energy Policy 36(12) (2008), 4471–4; Boardman, Fixing Fuel Poverty. 9 The conceptual and documentary reviews were undertaken under the auspices of the EVALUATE project (funded by the European Research Council under grant no. 313478), while the ethnographic case study was part of the EVENT project (funded by the Royal Geographical Society, grant no SRG 14.13). 10 European Parliament, Directive 2009/72/EC of the European Parliament and of the Council of 13 July 2009 concerning common rules for the internal market in electricity and repealing Directive 2003/54/EC (Text with EEA relevance), available at http://eur-lex.europa.eu/LexUriServ/ LexUriServ.do?uri=CELEX:32009L0072:EN:NOT 2009)

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member states: EU countries were supposed to identify and define who is vulnerable in energy terms, and to develop a set of national policy measures that will protect specific socio-demographic groups. Although responses to this requirement have varied among member states, overall several types of criteria have been used to identify vulnerable consumers. These include income thresholds, personal characteristics (for example, age, number of children in the household, illness) and the energy burden (the percentage of income spent on fuel/energy services).11 The use of support mechanisms based on socio-demographic criteria has led to the poor targeting of benefits.12 The current legislation does not only address the issues of energy poverty in highly constrained terms (within the narrow triangle of income, prices and efficiency) but also lacks temporal flexibility – by failing to recognise that some people can enter and exit the state of energy deprivation numerous times during their lifetime. In order to address some of these obstacles, the EVALUATE project team has worked on providing a novel conceptual grounding for the notion of ‘energy vulnerability’.13 In this line of thinking, energy vulnerability is seen as the propensity of a household to become incapable of securing a socially and materially necessitated level of domestic energy services.14. As such, the approach introduces a wider range of temporal and spatial dimensions to the conceptualisation of energy poverty. Providing affordable energy, according to this framework, is just as much a question of ensuring an adequate match between housing types, heating systems and household needs as it is about incomes and energy efficiency.15 GREECE: EVERYDAY EXPERIENCES OF ENERGY POVERTY IN THE HOME The evidence gathered by the ethnographic study in Greece helped us to explore how experiences of energy vulnerability are underpinned by the social and spatial infrastructures of everyday life. This country offers an unprecedented opportunity to undertake a comprehensive exploration of the driving forces of energy vulnerability due to the recent economic crisis, which has led to a dramatic increase in poverty rates – principally due to falling real incomes and rising unemployment. The new situation has augmented antecedent problems in the country, whereby many people live in poorly insulated homes, often finding themselves in institutional and/or ownership arrangements that do not allow for improving the efficiency of the housing stock or switching to more

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Vulnerable Consumer Working Group, Vulnerable Consumer Working Group Guidance Document on Vulnerable Consumers (Vulnerable Consumer Working Group, 2013). 12 Ibid. 13 S. Bouzarovski, S. Petrove and S. Tirado-Herrero, ‘From fuel poverty to energy vulnerability: the importance of services, needs and practices’, SPRU Working Paper Series, SPRU – Science and Technology Policy Research, University of Sussex (2014); Bouzarovski and Petrova (n 5). 14 Bouzarovski and Petrova, ‘The EU energy poverty and vulnerability agenda’. 15 Bouzarovski et al., ‘Precarious domesticities’.

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affordable fuels.16 At the same time, energy prices have often been increased in order to allow for the privatisation of energy utilities. In terms of the energy poverty challenge, the most relevant Greek policy is Law 4001/2011,17 which defines the criteria, conditions and procedure for integration of power supply customers to the Register of Vulnerable Customers. The Greek regulation recognises several types of vulnerable customers: longterm unemployed or residents with low income, families with three or more children, disabled people and people on life support, as well as elderly people.18 In addition, electricity suppliers apply special protective measures to vulnerable customers in Greece. These measures might include the possibility of partial or interest-free payment of electricity bills as well as allowing more time for bills to be paid. In addition, the rules regarding when vulnerable customers can be disconnected from the electricity grids are stricter and disconnections due to unpaid bills are forbidden during the winter period (November–March) and summer period (July–August). All protective measures are set for four-month periods and cease to apply if the electricity use of a vulnerable customer for a defined four-month period exceeds the consumption limits set for their category of vulnerability.19 The combination of austerity measures, inadequate social support and strict top-down energy regulations led to the development of a range of householdlevel strategies and tactics. Often utilising informal support networks nested in communities of place and interest, these approaches have allowed people to deal with the new situation. Austerity and energy poverty: ethnographic anecdotes The findings of our fieldwork in Greece support the argument that austerity can create a wider space for informal and collective networking and action. The use of various collective practices has been essential in addressing energy vulnerability among urban and peri-urban households. Such problems were much less common before the economic crisis. Our research also showed that the lack of adequate household-level energy service provision has altered the territories and spaces of energy demand and consumption. As a result of the economic crisis, households have started to use less technologically advanced energy sources (such as firewood) for heating during

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M. Santamouris, K. Kapsis, D. Korres, I. Livada, C. Pavlou and M. N. Assimakopoulos, ‘On the relation between the energy and social characteristics of the residential sector’, Energy and Building 39(8) (2007), 893–905; N. Katsoulakos, ‘Combating energy poverty in mountainous areas through energy-saving interventions’, Mountain Research and Development 31(4) (2011), 284–92. 17 Ministry of Environment, Energy and Climate Change, ‘Law on the regulation of the energy markets of electricity and gas, for research, production and transportation networks of hydrocarbons and other regulations’ (2011), available at www.ypeka.gr/LinkClick.aspx?fileticket=9rVkIH6aN 2E%3D&tabid=506&language=el-GR 18 Ibid. 19 Ibid.

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winter. These have required the purchasing of new appliances, and alterations to the built fabric of homes (such as the installation of pipes). Many such modifications have been constructed in an improvised and inefficient manner, resulting in higher socio-ecological risks for the households involved. At the same time, however, the budgeting and planning of energy consumption in the home has become much more strategic and thrifty. The households that have been able to utilise technologically and socially flexible energy systems (particularly in terms of being able to rely on a wider range of energy sources) tend to be less vulnerable than those dependent on more rigid, fixed and uniform supply chains (such as petroleum or electricity). Although – as explained above – policy instruments for helping the most energy-vulnerable households exist, the process is hindered by the inadequate definition of vulnerable households and complicated bureaucratic processes, as well as pricing mechanisms that embed new fiscal schemes in electricity bills. CONCLUSION Energy poverty has been recognised as an issue affecting thousands of households across the EU. The current EU policies tackling energy poverty mostly focus on low household incomes, high energy prices and the inadequate energy efficiency of the building stock. Field-based research on energy poverty, including the findings presented here, has shown that the current policies still have not managed to incorporate some crucial aspects of domestic energy deprivation. These include energy needs and the socio-demographic circumstances of households. Therefore, future policies aiming to ameliorate domestic energy deprivation and vulnerability in Europe, and south-eastern Europe more specifically, should take into account: (1) the need to provide lifeline amounts of energy to the increasing number of households with basic domestic energy access difficulties; (2) the growth of community-level resources that can enable the growth of diverse economic practices and socio-technical flexibility in the provision of energy; and (3) systemic issues at the level of national utility and pricing policies to address issues of unjust energy pricing, neoliberal reforms of the electricity sector and inadequate support for vulnerable groups.

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POLICY CHANGES FOR FUTUREPROOFING HOUSING STOCK Charlotte A. Adams1

INTRODUCTION Half of the energy consumed in the UK is used for the production of heat, yet plans for future energy provision often focus on the generation of electricity whilst neglecting the need to find alternative sustainable and efficient sources of heat to meet future energy needs. One third of UK energy demand is attributed to the domestic sector (65 Mtoe) and most of this (45 Mtoe) is used for space and water heating.2 The UK domestic sector produced 77 Mt CO2 in 2013 with the average annual household consuming 16,500 kWh gas and 3,300 kWh electricity3 whilst producing CO2 emissions of around 20 tonnes.4 The UK currently builds over 100,000 new homes annually5 and this chapter presents a case for making amendments to policies that inform building control in order to future-proof new-build homes and make them more compatible with micro energy generation systems that could become more 1

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Dr Charlotte Adams trained as a hydrogeologist and has a keen interest in ground source heat and geothermal energy. Prior to joining Durham University in 2009 she gained industrial experience whilst carrying out energy audits and renewable energy assessments for a range of domestic and industrial buildings. Her research interests include micro-generation, efficient provision of heat, the built environment, energy efficiency and sustainability of historic buildings. She currently manages the BritGeothermal Research Partnership. Department of Energy and Climate Change, ‘Energy consumption in the UK’ (2014), available at www.gov.uk/government/uploads/system/uploads/attachment_data/file/338662/ecuk_chapter_3_ domestic_factsheet.pdf Ofgem, ‘Typical domestic energy consumption figures – factsheet 96 (2011), available at www. ofgem.gov.uk/ofgem-publications/64026/domestic-energy-consump-fig-fs.pdf WWF, ‘Counting consumption (2006), available at www.assets.wwf.org.uk/downloads/ecological_budget_northeast.pdf Department for Communities and Local Government, ‘House building statistics’ (2014), available at www.gov.uk/government/statistical-data-sets/live-tables-on-house-building

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commonplace in future.6 These suggestions are not exhaustive but provide an example of some of the changes that could be made to current domestic energy provision and practice with respect to heat. The benefits of incorporating the proposed changes include reduced energy costs and CO2 emissions, improved safety and comfort levels for occupiers combined with increasing the sustainability of new housing stock. This chapter presents the case for making changes to UK building regulations that could facilitate incorporation of more flexible heat provision systems into new-build properties. The changes that will be discussed include fitting homes with thermal stores rather than hot water cylinders and making underfloor heating mandatory for new builds. THE PRODUCTION AND STORAGE OF DOMESTIC HOT WATER The temperatures to which domestic boilers heat and store water (> 60°C) is far higher than the temperature at which we need to use it either for washing and bathing or heating. Current UK building regulations limit domestic hot water supply to temperatures not exceeding 60°C and bath taps must be limited to 48°C. To achieve a comfortable level of warmth within our living spaces, temperatures of between 18 and 21°C are generally maintained and it is not necessary to heat water to temperatures of 60°C and above to do

Figure 76.1 Gas consumption and CO2 emissions associated with heating 180 litres of water to a range of output temperatures

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N. Bergman and N. Eyre (2011), ‘What role for microgeneration in a shift to a low carbon domestic energy sector in the UK?’, Energy Efficiency, 4(3), 335–53.

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this. Storing water at lower temperatures reduces the energy requirement for attaining the desired water temperature and decreases the rate of heat loss. However, an important reason for heating water for washing and bathing to above 60°C is to destroy legionella bacteria that can lead to the potentially fatal Legionnaires’ disease.7 In addition to hot water storage at high temperatures most conventional central heating systems that use radiators require water circulating at temperatures of up to 80°–90°C. Figure 76.1 assumes an initial water temperature of 10°C and shows the gas consumption and associated CO2 emissions associated with heating a 180-litre tank of hot water at a range of output temperatures. Reducing temperatures to which water is heated and stored by 20°C from 80°C to 60°C decreases gas consumption and CO2 emissions by 29 per cent. On an annual basis, if this were applied to new housing stock (assuming it would apply to threequarters of new homes built annually) 87,000 tonnes of CO2 emissions could be avoided. Given the constraints provided by the need to protect against legionella how could these savings be safely achieved in reality? In a conventional arrangement, the heat produced by a boiler is stored in a hot water cylinder (Figure 76.2a) which is thermally stratified with hot water at the top and cooler water at its base. Hot water for domestic use is drawn directly from the upper part of the cylinder and the heating circuit passes through the cylinder accumulating heat as it is pumped through the tank. The water in the tank is then replaced by the cold water storage tank that is usually housed above the cylinder in the loft

Figure 76.2 Simplified schematic diagram showing the configuration of hot water cylinders and thermal stores

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B. S. Fields, R. F. Benson and R. E. Besser, ‘Legionella and Legionnaires’ disease: 25 years of investigation’, Clinical Microbiology Reviews, 15(3) (2002), 506–26.

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to maintain water pressure. The tank could not include an electric immersion heater to boost temperatures for when the boiler is not being used, for example, in summer when heating is not needed. Thermal stores (sometimes referred to as buffer tanks or accumulators) differ in that the water within the tank is used purely to store heat and is never drawn down. Heat is removed from the tank by a series of closed loops or heat exchangers that remove only the heat from the tank (Figure 76.2b), meaning that the hot water supply is provided by fresh mains pressure cold water heated as it passes through the heat exchanger within the tank, which removes the risk of legionella. Using thermal stores rather than a domestic hot water cylinder also facilitates the storage of water at lower but still useful temperatures. In addition, because they generally have the capacity for multiple inputs, they can accept heat from sources that produce a range of output temperatures such as heat pumps, solar hot water panels, wood-fired stoves or boilers in addition to micro combined heat and power and conventional condensing boilers.8 The risk of carbon monoxide associated with fuel combustion within the home can be eradicated by replacing conventional boilers with heat pumps that are powered by electricity. The proposed changes with respect to the replacement of hot water tanks with thermal stores are only relevant to properties that store hot water on site, therefore smaller properties with combi boilers that heat water instantaneously would be excluded. Thermal stores also have the facility to incorporate immersion heaters if required. THE PROVISION OF SPACE HEATING In a conventional system the boiler heats water that is then pumped round radiators that are sized appropriately to the calculated heat loss for each room. Conventional radiators can be replaced with underfloor systems which involve burying hot water pipes within the subfloor. Hot water circulates through them and to provide temperatures of around 18 to 29°C. Underfloor heating can be retrofitted but is easier to incorporate during new-build or major refurbishment. Underfloor heating systems increase the area of radiance which is why they can operate at lower temperatures of around 30–40oC. Heat pumps are very compatible with underfloor heating systems because they operate more efficiently when producing lower temperature outputs (in the range 40–50°C). Using a lower circulation temperature can also increase the efficiency of condensing gas boilers. An underfloor heating system that is used with a conventional condensing gas boiler could be substituted for a heat pump in future because this is compatible with low-temperature circulation systems. There are also aesthetic benefits to using underfloor heating systems – modern properties may be more compact and therefore not having to accommodate radiators increases the available space for furniture.

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K. Kaygusuz, ‘The viability of thermal energy storage’, Energy Sources 21(8) (1999), 745–55.

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CONCLUSIONS The systems briefly described in this chapter allow greater use of lower temperatures while facilitating the incorporation of a mixture of energy generation systems at the domestic level. These systems are currently popular amongst many self-builders because they reap the benefits of including them. A key challenge lies in getting mainstream housing developers to adopt these systems. They are only likely to do so if they are required as part of building regulations because their inclusion is likely to increase build costs. Although they have potential to make properties more affordable to run in the longer term these benefits are unlikely to be realised by the developers. Energy use incorporates a wide range of activities and products; the changes to policy and practice proposed in this chapter offer one route to ensuring that many homes built in the present can operate efficiently whilst being compatible with emerging technologies of the future.

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CHALLENGES FOR HEALTH SERVICES IN IDENTIFYING WHICH GROUPS ARE MOST VULNERABLE TO HEALTH IMPACTS OF COLD HOMES Anna Cronin de Chavez1

INTRODUCTION There are approximately 30,000 excess winter deaths in England and Wales each year, mostly due to heart-related and respiratory conditions.2 There is a peak in heart deaths two days after the coldest day, stroke five days after and respiratory conditions twelve days after.3 The fields of engineering, environment, social policy, law, psychology, economics and business have been involved in fuel poverty and energy research for decades but the field of health is relatively new to this topic. One of the main challenges for health services is to identify which individuals are most at risk of cold-related harm. This chapter looks at current ways of identifying those most at risk and some of the gaps in research, policy and practice in protecting people from cold-related harm.

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Anna Cronin de Chavez is a Research Fellow at the Centre for Health and Social Care Research at Sheffield Hallam University. She is a biological/medical anthropologist with an interest in fuel poverty and the impact of cold temperatures on health, and is currently conducting research into challenges in keeping warm and healthy faced by two vulnerable groups: children with asthma and people with sickle-cell disease. She has also worked on the evaluation of fuel poverty interventions with health improvement agencies. Her doctoral thesis examined the beliefs and practices of mothers from different cultures regarding protecting their babies from heat and cold. Office for National Statistics, ‘Excess winter mortality in England and Wales, 2012/13 (Provisional) and 2011/12 (Final)’, Statistical Bulletin (2013), available at www.ons.gov.uk/ons/ dcp171778_337459.pdf Public Health England, ‘Cold Weather Plan for England – Making the case: why long-term strategic planning for cold weather is essential to health and wellbeing’ (2014), available at www. gov.uk/government/uploads/system/uploads/attachment_data/file/365269/CWP_Making_the_ Case_2014_FINAL.pdf

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IDENTIFYING VULNERABLE PEOPLE USING FUEL POVERTY INDICATORS One way of identifying, on a population level, those at risk from exposure to cold at home is to identify those in fuel poverty. However, despite the strengths and weaknesses of different methods of identifying the fuel poor this does not include all individuals actually exposed to cold. Fuel poverty indicators are broadly based on income and the cost of heating a particular size and type of house. Keeping a house warm also requires a complex interaction of other factors such as the ability to deal with technology and heating systems, thrift, attitudes and values, awareness, payments and help available.4 Therefore those who are identified as living in fuel poverty may still be living in a warm house and those not identified may be living in a very cold house. This is problematic for health services trying to identify who might be at risk of cold related harm. IDENTIFYING THOSE MOST AT RISK THROUGH DETECTING LOW BODY TEMPERATURES The World Health Organization’s recommendation for healthy room temperatures is 18°C–24°C5 and has been used widely to calculate carbon emission targets, fuel poverty statistics and so on for decades. A recent review concluded that 18°C would be a healthy room temperature.6 The very young and very old are at particular risk of hypothermia even in mild temperatures due to immature and/or disturbed thermoregulation, thinner skin, poor muscle tone and, for newborns and malnourished older people, a high skin surface to body volume ratio. For example a naked baby at 23°C suffers the same heat loss as a naked adult at 0°C. A clothed and dry newborn baby requires a room temperature of 25–28°C to avoid the risk of neonatal hypothermia, a condition which can have lifelong or fatal consequences.7 Due to the different abilities of people of different ages and conditions to thermoregulate it is not therefore logical that one temperature can fit all at all times.

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A. M. Tod, A. Lusambili, C. Homer, J. Abbott, A. J. Stocks and K. A. McDaid, ‘Understanding factors influencing vulnerable older people keeping warm and well in winter: a qualitative study using social marketing techniques’, BMJ Open 2(4) (2012), available at http://bmjopen.bmj.com/ content/2/4/e000922.full.pdf:html World Health Organization ‘Health impact of low indoor temperatures’ (1987), available at www.theclaymoreproject.com/uploads/associate/365/file/Health%20Documents/WHO% 20-%20health%20impact%20of%20low%20indoor%20temperatures%20%28WHO,%20 1985%29.pdf R. Wookey, A. Bone, C. Carmichael and A. Crossley, ‘Minimum home temperature thresholds for health in winter – a systematic review’ (2014), Public Health England, available at www.gov. uk/government/uploads/system/uploads/attachment_data/file/365755/Min_temp_threshold_for_ homes_in_winter.pdf World Health Organization, ‘Thermal protection of the newborn: a practical guide’ (1997), available at http://whqlibdoc.who.int/hq/1997/WHO_RHT_MSM_97.2.pdf?ua=1

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Hypothermia admissions are now rising steeply alongside the increase in fuel poverty rates in England and Wales. Primary or secondary diagnosis of hypothermia for hospital admissions rose from 7,069 in 2005–6 to 17,874 in 2013–14. Analysis of Hospital Episode Statistics8 shows that hypothermia admission rate per 100,000 for 0–4 year olds in England has more than doubled from 27.33 in 2005–6 to 65.45 in 2013–14. The hypothermia admission rate per 100,000 for those aged 70 and over in England has increased by one and a half times from 17.14 in 2005–6 to 25.26 in 2013–14. Currently, 0–4 year olds are forty-six times more likely to be admitted to hospital with hypothermia than 15–69 year olds. People aged 70 and over are eighteen times more likely to be admitted to hospital with hypothermia than 15–69 year olds. There is probably a greater social awareness of older people being at risk to cold than the risk to young children. Few emergency departments in the UK have a hypothermia protocol and most have limited equipment to re-warm patients. Gordon and colleagues suggest there is little integration between the pre-hospital and hospital phases of hypothermia care.9 Hypothermia can also be an under-recognised symptom of sepsis, a condition more commonly associated with fever.10 A major obstacle in identifying hypothermia in the pre-hospital environment is the almost non-existent access to standard, non-invasive clinical thermometers that read below 34°C. Since the withdrawal of mercury clinical thermometers there has not been a widespread replacement using infrared and digital technologies. Accurate reading of low body temperature is vital for determining the level of emergency response required and for safe, controlled re-warming. However, despite the urgency to improve hypothermia detection and care there is still a far greater burden of disease created through cold stress on the body before the hypothermia occurs. Cold exposure can produce physiological reactions such as changes in blood pressure and viscosity which can adversely impact on a variety of pre-existing health conditions.11 IDENTIFYING THOSE MOST AT RISK THROUGH EXCESS WINTER DEATH AND ILLNESS STATISTICS AND SPECIFIC CONDITIONS Since 2010 the Office for National Statistics in England and Wales has published annual statistics on excess winter deaths. However, these statistics

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Health and Social Care Information Centre, ‘Hypothermia national stats by age 2005–06 to 2013–14’, Hospital Episode Statistics (2014), available at www.hscic.gov.uk/media/15004/ Hypothermia-national-stats-by-age-2005-06-to-2013-14/xls/Hypothermia_national_stats_by_ age_200506_to_201314.xlsx 9 L. Gordon. ‘Severe accidental hypothermia’, Editorial, British Medical Journal 348 (2014): g1675. 10 A. Cronin de Chavez, C. Childs, S. Kelly, A. M. Tod and D. Burke, ‘Hypothermia and the assessment of sick children’ British Medical Journal 347 (2013): f4220. 11 Marmot Review Team, ‘The health impacts of cold homes and fuel poverty’ (2011), available at www.instituteofhealthequity.org/projects/the-health-impacts-of-cold-homes-and-fuel-poverty

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are generated through associations between outdoor temperatures and mortality and morbidity statistics, and do not provide clear associations for cold indoor temperatures. A few studies have looked at indoor temperature associations12 or health improvement through warmer homes.13 There are potentially many more conditions exacerbated by cold than those listed in excess winter deaths statistics. To create an exhaustive list, which could include thousands of conditions, has been described as a potentially overwhelming task14 and has never been attempted. The following are just some conditions cited as affected by cold exposure: • • • • • • • • • • • •

arthritis and rheumatism – worsening of symptoms15 asthma16 development status of infant (caregiver rated)17 diabetes complications18 heart conditions and strokes (increased mortality and morbidity)19 hip fractures (severity and increased incidence)20 hypothermia (accidental/urban/sub-clinical)21 infant weight gain – reduced22 major trauma – increased mortality23 mental ill-health24 neonatal hypothermia25 Parkinson’s and dementia26

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P. Wilkinson, M. Landon, B. Armstrong, S. Stevenson, S. Pattenden, M. McKee and T. Fletcher, Cold Comfort: The Social and Environmental Determinants of Excess Winter Deaths in England, 1986–96 (The Policy Press, 2001). 13 C. Liddell and C. Morris, ‘Fuel poverty and human health: A review of recent evidence’, Energy Policy 38(6) (2010), 2987–97. 14 National Institute for Health and Care Excellence, ‘Evidence review & economic analysis of excess winter deaths – review 1’, available at www.nice.org.uk/guidance/gid-phg70/resources/ excess-winter-deaths-and-illnesses-guideline-consultation-supporting-evidence2 15 Ibid., 8. 16 Ibid., 11. 17 Ibid., 11. 18 Ibid., 11. 19 Ibid., 11. 20 Ibid., 11. 21 Ibid., 6, 7. 22 Ibid., 11. 23 S. Ireland, R. Endacott, P. Cameron, M. Fitzgerald and E. Paul, ‘The incidence and significance of accidental hypothermia in major trauma – a prospective observational study’, Resuscitation 82(3) (2011), 300–6. 24 National Institute for Health and Care Excellence, ‘Evidence review & economic analysis of excess winter deaths – review 1’, 11. 25 D. Bhatt, R. White, G. Martin, L. J. Van Marter, N. Finer, J. Goldsmith, C. Ramos, S. Kukreja and R. Ramanathan, ‘Transitional hypothermia in preterm newborns’, Journal of Perinatology 27 (2007), S45–S47. 26 National Institute for Health and Care Excellence, ‘Evidence review & economic analysis of excess winter deaths – review 1’, 11.

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Raynaud’s syndrome27 respiratory infections28 sepsis – symptoms of hypothermia29 sickle cell disease – increased pain and acute chest syndrome30 sudden infant death syndrome – overwrapping in cold homes31 systematic lupus erythematosus (worsening symptoms)32 ulcers (exacerbation of)33

There is therefore a significant clinical challenge in developing reliable, exhaustive and robust evidence to identify which conditions are affected by cold temperatures. IDENTIFYING THOSE MOST AT RISK USING A HOLISTIC MODEL OF PHYSIOLOGICAL, PSYCHOLOGICAL AND ENVIRONMENTAL FACTORS OF KEEPING WARM The model below details three different components of adaptation to cold environments: physiological, psychological and environmental, and what might prevent successful responses. The physiological element includes all the internal physiological systems that allow for the detection of cold stress on the body and the consequential physiological response of conserving and/or increasing the production of body heat. The psychological element includes how the cold stress signs are interpreted and translated into action to act on the immediate environment, such as adding clothing or increasing heating. The environmental element includes all the external factors that may help individuals make (or prevent them from making) their environment warmer, including physical, social, economical and political factors. In terms of prevention it is proposed that the model is helpful in mapping out aspects of how people maintain healthy body temperatures to identify who requires targeted help and protection from cold.

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H. R. Watson, R. Robb , G. Belcher and J. J. Belch, ‘Seasonal variation of Raynaud’s phenomenon secondary to systemic sclerosis’, Journal of Rheumatology 26(8) (1999), 1734–7. 28 National Institute for Health and Care Excellence, ‘Evidence review & economic analysis of excess winter deaths – review 1’, 11; P. Fleming, J. Young and P. Blair, ‘The importance of mother-baby interactions in determining night-time thermal conditions for sleeping infants: observations from the home and the sleep laboratory’, Paediatrics and Child Health, 11 (Suppl A) (2006), 7A–10A. 29 N. Hofer, W. Müller and B. Resch. ‘Neonates presenting with temperature symptoms: role in the diagnosis of early onset sepsis’, Pediatrics International 54(4) (2012), 486–90. 30 E. Vichinsky, L. A. Styles, L. H. Colangelo, E. C. Wright, O. Castro and B. Nickerson, ‘Acute chest syndrome in sickle cell disease: clinical presentation and course’, Blood 89(5) (1997), 1787–92. 31 Fleming et al., ‘The importance of mother-baby interactions’, 27. 32 I. Krause, I. Shraga, Y. Molad, D. Guedj and A. Weinberger, ‘Seasons of the year and activity of SLE and Behcet’s disease’, Scandinavian Journal of Rheumatology 26(6) (1997), 435–9. 33 National Institute for Health and Care Excellence, ‘Evidence review & economic analysis of excess winter deaths – review 1’, 11.

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Figure 77.1 HeaTmaPPE: model of healthy living temperatures and physiological, psychological and environmental responses in cold temperatures

The HeaTmaPPE model in Figure 77.1 has been created by the author by drawing on several sources from different disciplines.34 CONCLUSION Identifying those most at risk of cold-related harm on an individual level is highly problematic for health services. Fuel poverty and excess winter deaths statistics currently do not allow the identification of all individuals at risk to cold-related harm. Existing knowledge on specific conditions affected by cold need to be drawn together and new knowledge developed. This knowledge should be fed into policy and practice to give more people access to cold homes interventions. Standard-use low-reading thermometers should be

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K. Parsons, Human Thermal Environments – The Effects of Hot, Moderate and Cold Environments on Human Health, Comfort and Performance (CRC Press, 2003); M. Mallet, ‘Pathophysiology of accidental hypothermia’, QJM 95 (2002), 775–85; J. Worfolk ‘Keep frail elders warm!’ Geriatric Nursing 18(1) (1997), 7–11; A. Cronin de Chavez, A. M. Tod, C. Homer, P. Nelson, A. J. Stocks, V. Powell-Hoyland, Warm Well Families: Rotherham – Final Report (Rotherham Metropolitan Borough Council, 2013), p. 3; and Department of Energy and Climate Change, ‘Understanding the behaviours of households in fuel poverty – a review of evidence’ (2014), available at www.gov.uk/government/uploads/system/uploads/attachment_data/file/332122/understanding_ behaviours_households_fuel_poverty_review_of_research_evidence.pdf

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widely available for use in the community to detect the existence and severity of hypothermia and emergency department hypothermia protocols made universal. More attention should be paid to the effects of cold stress on health in even relatively mild temperatures. The HeaTmaPPE model provides an initial framework to identify all the potential physiological, psychological and environmental vulnerabilities in maintaining a healthy body temperature. This could be a useful tool to integrate and engage multiple disciplines to reduce cold-related illness and deaths. Warmth is one of the basic needs for human survival but the field of health faces a formidable challenge in addressing the research, policy and intervention development and building on existing interdisciplinary work to protect those most at risk of cold-related harm.

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ENERGY, LIFE, METABOLISM AND THE FOOD CHAIN James J. A. Heffron1

Welcome, O Life! I go to encounter for the millionth time The reality of experience and to forge In the smithy of my soul the uncreated Conscience of my race James Joyce, A Portrait of the Artist as a Young Man On our visually insignificant blue planet all life depends on the continuing flow of energy from the sun to the earth. The sun’s thermonuclear reactions empower the green pigment chlorophyll to sustain life by providing the energy to drive metabolism and all our physiological functions. But, as Professor Brian Cox and Andrew Cohen summarised in their thrilling book Wonders of the Universe2 and its accompanying BBC TV series, ‘the sun will eventually die incinerating the earth and obliterating all life on our planet’. What will be left behind will be a dark, dead, desolate and formless cosmos. There will be no hope of any life starting again. All energy will be dissipated. It will be the final end! The above passage provides a very negative summary of what energy is even though it clearly conveys that it is the sustaining principle of life in all living organisms from single-cell organisms such as bacteria through to plants and animals and ultimately to our own species Homo sapiens. In this short chapter

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Professor James J. A. Heffron, MRIA, FRSC is Professor Emeritus of Biochemistry, School of Biochemistry and Cell Biology, National University of Ireland, Cork, Ireland. His research interests are in energy metabolism, human metabolic diseases and toxicology of natural and synthetic chemicals. B. Cox and A. Cohen, Wonders of the Universe (HarperCollins, 2011).

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I wish to demonstrate the primacy of energy in the initiation and evolution of life on earth and by extension in the solar system and the universe itself. In the Oxford English Dictionary, the scientific definition of energy is stated as ‘the ability to do work’. But most of us are familiar with at least some of the many forms of energy, including, among others, kinetic, potential, thermal, electrical, osmotic and radiant. Life as we know it depends exclusively on radiant energy from the sun. Sunlight is a form of radiant energy which arises from nuclear energy. The core of the sun has a temperature of about 10 million degrees centigrade and consists mainly of hydrogen. Some of the enormous amount of energy locked in the nuclei of the atoms of hydrogen is liberated as the hydrogen is transformed into helium atoms and positrons by thermonuclear fusion: this is illustrated in the following reaction: 4 1H ® 4He + 2 1 e0 + hv3 where h is Planck’s constant and v is the frequency of the gamma radiation. After a complex series of reactions the gamma radiation is emitted in the form of photons of light energy. Thus, nuclear fusion reactions in the sun generate all of the biochemical energy on earth. This energy is harnessed on earth by the process of photosynthesis – the radiant energy is absorbed by the green pigment chlorophyll and converted to chemical energy – in which two inorganic substances (carbon dioxide and water) from the atmosphere are converted into glucose and other compounds such as protein, fat and cellulose.4 In most photosynthetic organisms such as the higher plants, O2 is the other major product. The overall reaction of photosynthesis is: 6 CO2 + 6 H2O ® 6 C6H12O6 + 6 O2 This simple reaction equation regrettably gives little idea of the complexity of photosynthesis which involves at least 100 biochemical steps each of which is catalysed by a specific enzyme or protein catalyst. The chemical energy that a green plant stores by photosynthesis provides all of the energy required by the plant. Plants provide all of the nutrients directly or indirectly for virtually all other living organisms on earth. It may be noted that most fossil fuels are reservoirs of the sun’s radiant energy converted by photosynthesis in earlier geological eras. So far, I have focused on energy, its nature and its origin and how it is captured and converted into the variety of chemical compounds which are the components of all known living organisms on the planet. But this leads one to the most fundamental question of all – what is life? – or, to put it another way, what is it that confers the characteristic of living on any entity/organism, be

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Abbreviations: Fe = iron; He = helium; H = hydrogen; J = joule; S = sulphur Reviewed by A. L. Lehninger, Bioenergetics, 2nd edn (Benjamin Cummings Publishing Company, 1973).

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it plant, animal or microbe? Over centuries many philosophers and scientists have deliberated and speculated about the meaning of living and life. Yet we still have no satisfactory understanding of the matter. Perhaps the most notable attempts at explaining the nature of life in the last hundred years have been those of the chemists Alexander Oparin5 in 1924 and Stanley Miller6 in 1953, and the physicist Erwin Schrodinger7 in 1946. It is generally agreed that life arose from inanimate matter by a series of chemical events which produced molecules of increasing complexity and activity, leading finally to the first cellular entities with the ability to reproduce themselves. Miller’s celebrated prebiotic chemical demonstration of the synthesis of several a-amino acids (precursors of proteins) and other biologically important organic acids in a simulated primitive gaseous atmosphere of ammonia, hydrogen, methane and water vapour provided a clear pathway towards understanding the first steps in the chemical evolution of life.8 These experiments in prebiotic chemistry do not show how or when living systems arose but they demonstrate that life probably first appeared with the complexification of organic matter. It is generally agreed that the transition from non-life to life on earth started about 3.5 to 3.9 billion years ago, some 0.6 billion years after the formation of the planet, and it is envisaged as developing in some form of primeval soup containing both inorganic and organic compounds. The first cells arose in what is called a reducing atmosphere, that is, in the absence of O2 and they probably obtained their energy initially from inorganic fuels such as ferrous sulphide and hydrogen sulphide as in the following reaction (Nelson & Cox):9 FeS + H2S ® FeS2 + H2 This reaction would provide sufficient energy to drive the synthesis of adenosine triphosphate (ATP) or similar organic compounds. Some of the compounds required by the early cells may have been synthesised during electrical storms or via heat from volcanoes or thermal vents. Indeed, there may have been an extraterrestrial source of many organic compounds – the so-called extraterrestrial hypothesis as suggested by the findings of the 2006 Stardust space mission. The early unicellular organisms gradually acquired greater ability to synthesise their own compounds independent of these external sources. Some time later there followed one of the most momentous events in evolutionary history – the development of pigments such as chlorophyll capable of transducing the sun’s radiant energy into the chemical energy required to ‘fix’ 5 6

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A. I. Oparin, The Origin of Life (Academic Press, 1957). S. Miller, ‘A production of amino acids under possible primitive earth conditions’, Science 117 (1953), 528–9; and G. Schlesinger and S. L. Miller, Prebiotic synthesis in atmospheres containing CH4, CO and CO2, Journal of Molecular Evolution 19 (1987), 376–82. E. Schrodinger, What is Life? (Cambridge University Press, 1944). F. Capra and P. L. Luisi, The Systems View of Life (Cambridge University Press, 2014). D. L. Nelson and M. M. Cox, Lehninger Principles of Biochemistry, 6th edn (Macmillan Higher Education, 2013).

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CO2 and convert it into glucose, proteins, fats, cellulose and ATP in the process we now call photosynthesis. Another significant product of this photosynthesis was O2; this appeared some 3.0 to 2.5 billion years ago and it marked a major transition to cells employing aerobic metabolism, the antecedents of all aerobic cells and organism we are familiar with today. Metabolism – the ability of a cell or organism to make its own structural and functional constituents from its own simpler chemicals as well as nutrients from the environment – gradually matured or evolved to make more complex organic compounds synchronously with the ability to produce energy-rich organic molecules for biosynthesis, reproduction, locomotion and neural functions. The most important energy-rich molecule produced by metabolism is ATP which has now achieved the status of ‘universal biological energy currency’ since it appears in most, if not all, organisms from bacteria to plants, animals and humans. ATP is the immediate source of ‘free energy’ for almost all biological functions. Free energy,10 denoted as G or Gibb’s free energy, refers to that energy component which is available for the performance of all forms of biochemical work; it maintains an organism in an ordered steady state at the expense of the environment which experiences an increase in entropy,11 that is, the form of energy inherent in the molecular disorder of the organism. Entropy is not available for the performance of work and is often referred to as ‘useless energy’. But an organism’s metabolism is in a constant clash with the tendency of a system to reach a maximum entropy; this phenomenon is enshrined in the Second Law of Thermodynamics which states that all physical and chemical processes proceed in such a direction that the entropy of the universe – the system and its surroundings – increases to the maximum possible. And it follows, since free energy is essential for life, that the thermodynamic index of death of an organism is ΣΔG = 0 where ΔG is the free energy change in any one reaction. A food chain consists of a hierarchy of organisms which provides the principal organism with the food and materials to sustain its life. In nature there will be a multitude of food chains with most of them interacting in what is called a food web, the common factor being free energy. The immensity of the biological energy cycle has been calculated by Lehninger: the total amount of carbon fixed by all photosynthetic organisms on the earth each year is thought to be about 16 x 1010 tons; assuming that all the carbon which is fixed is in the form of glucose and that each mole of glucose synthesised requires a free energy input of 2,870 kJ/mole it may be calculated that the biological energy flux is approximately 4 x 1018 J/year. Since an average of about 2 per cent of the light falling on a plant is actually converted into glucose, the total amount of solar energy absorbed by the plant world is about 2 x 1020 J/year. This, in

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D. Beattie, ‘Bioenergetics, mitochondria and oxidative metabolism’, in T. M. Devlin (ed.), A Textbook of Biochemistry with Clinical Correlations, 7th edn, John Wiley & Sons, Inc., 2009), Chapter 14. 11 P. Atkins and J. de Paula, Elements of Physical Chemistry (Oxford University Press, 2005).

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turn, represents just one-two-thousandth of the total solar energy falling on the surface of the earth each year. It can also be shown that the biological energy flux is about thirty times greater than the amount of energy consumed by all human-made machines and industrial activities on the earth per year, and one might reflect on the fact that the latter are energised mainly by the biologically sourced fuels, coal, oil and natural gas, derived from fossilised plant material in early geological eras. Additionally, there are non-biological sources of energy such as hydroelectric and nuclear which are somewhat marginal in the overall energy supply context. Without energy there is no life on earth, no thought, no action, in fact, nothing. But living cells and organisms evolved a complex and exquisitely finely tuned system of energy production called metabolism some three to four billion years ago while, in the eons of time since, living organisms underwent further energy-driven complexification and evolution and laid down massive reservoirs of energy in the form of fossil fuels. The entity we call energy is indeed a precious one; we need it for our health, for a clean environment and for a life-sustaining climate. Yet policy-makers, politicians and governments take energy for granted while reducing its significance to one merely of cost and trading battles between the various nations and proponents of coal, gas and oil. Energy and life are simply too important to be left in their hands.

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ENERGY EFFICIENCY AND ENERGY DEMAND Steve Sorrell1

Improved energy efficiency and reduced energy demand are widely expected to provide the dominant contribution to reduced carbon emissions in the short to medium term – and to do so at little or possibly negative cost. But the link between improved energy efficiency and reduced energy demand is not straightforward: the first need not necessarily lead to the second, and both can be interpreted and measured in multiple ways. This chapter briefly summarises the issues involved. Energy efficiency is the ratio of useful outputs to energy inputs for a specified system – such as a motor, a machine tool, an industrial process, a firm, a sector or an entire economy – while energy intensity is the inverse of this measure. In all cases, the measure of energy efficiency will depend upon how inputs and outputs are defined and measured. Depending upon the system, outputs may be measured in energy terms, such as heat content or physical work; physical terms, such as vehicle kilometres or tonnes of steel; or economic terms such as value-added or GDP.2 Different measures may be more or less appropriate in different situations and are unlikely to capture everything of value or interest: for example, vehicle kilometres and passenger kilometres both measure the quantity of mobility, but the former does not capture load factors, the latter does not capture passenger comfort and neither is necessarily correlated with the frequency and ease of access to relevant destinations.

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Steve Sorrell is an energy and climate policy specialist with over twenty years of experience in applied, problem-oriented research that is relevant to both academic and stakeholder audiences. Steve’s areas of expertise include resource depletion and the economics of energy efficiency, including in particular the phenomenon of ‘rebound effects’. M. G. Patterson, ‘What is energy efficiency? Concepts, indicators and methodological issues’, Energy Policy 24(5) (1996), 377–90.

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In many cases the most relevant output of a system is an energy service of some form, such as motive power, thermal comfort and accessibility. But energy services are difficult to measure and aggregate, dependent upon social context and partly subjective, so a different definition, interpretation or understanding of the relevant energy service(s) may lead to a different judgment on the energy efficiency of a particular system. For example, thermal comfort depends upon internal air temperature, but also upon radiant temperature, air velocity, humidity, activity levels, clothing, external temperature, behavioural norms and sociocultural context, so the thermodynamic efficiency of the boiler is far from the only consideration. The measurement of energy inputs also raises issues, especially when different energy carriers are combined.3 The most common approach is to sum the thermal content of each energy carrier (in joules), but this amounts to summing apples and oranges. Energy carriers vary on multiple dimensions (such as volumetric energy density, gravimetric energy density, ease of storage, ease of transport, cleanliness) and they are only partially substitutable. Higher-quality energy carriers receive a higher price since they are more flexible, suitable for a wider range of end uses and produce more economic output per joule.4 Pricebased weighting schemes should therefore be (but rarely are) used to account for the different quality of energy carriers and when this is done aggregate measures of energy efficiency are found to be improving more slowly than is commonly supposed.5 For example, Kaufmann shows that much of the reduction in US energy intensity between 1950 and 1990 was linked to the shift towards higher quality and hence more productive energy inputs – such as from coal to oil.6 Importantly, improvements in one measure of energy efficiency may not be reflected in improvements in a second measure, or in measures appropriate for a wider spatial or temporal boundary. Indeed, it is entirely possible for an improvement in one measure to be associated with deterioration in another. For example, an electric heat pump is more energy-efficient than a gas boiler when energy inputs are measured at the building level, but may be less energyefficient when those inputs are measured at the source level (such as the fuel into the power station) or on a lifecycle basis. Similarly, Kaufmann shows how the energy savings in the US forest products industry over the period 1958–84 were largely offset by the energy used to produce the relevant capital equipment.7

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C. J. Cleveland, R. K. Kaufmann and D. I. Stern, ‘Aggregation and the role of energy in the economy’, Ecological Economics 32(2) (2000), 301–17. Ibid. Ibid. and see also J. Zarnikau, ‘Will tomorrow’s energy efficiency indices prove useful in economic studies?’, The Energy Journal 20(3) (1999), 139–45; and N. V. Hong, ‘Two measures of aggregate energy production elasticities’, The Energy Journal 4(2) (1983), 172–7. R. K. Kaufmann, ‘A biophysical analysis of the energy/real GDP ratio: implications for substitution and technical change’, Ecological Economics 6(1 (1992), 35–56. R. K. Kaufmann and I. G. Azary-Lee, ‘A biophysical analysis of substitution: does substitution save energy in the US forest products industry?’, in C. A. S. Hall and D. P. Bradley, Ecological Economics: Its Implications for Forest Management and Research (St Paul, MN, 1990).

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In a similar manner, improvements in energy efficiency (however measured) may not always reduce energy demand, and reductions in energy demand may result from something other than improved energy efficiency. To claim ‘energy-savings’ or ‘demand reduction’ it is necessary to specify the reference against which those savings are measured or estimated. That involves specifying the relevant spatial and temporal boundary and unit of measure, as well as invoking ceteris paribus assumptions. The reference may be historical energy consumption or a counterfactual scenario of what energy consumption ‘would have been’ in the absence of specified changes. But since data on energy consumption is not always available (or accurate), counterfactuals are unobservable and countervailing variables are difficult to control (for), the causal link between specific changes and the resulting ‘energy savings’ can be hard to establish. Most approaches rely upon decomposition or econometric analysis of secondary data at the aggregate level and the results are frequently lacking in resolution and sensitive to model specification. Experimental or quasi-experimental studies can control for confounding variables at the micro level, but these are costly to conduct and comparatively rare. As a result, the literature is replete with unreliable estimates of historical energy savings and questionable claims about future energy savings – in relation to specific technologies and policies as well as to the determinants of aggregate trends. California, for example, is hailed as an energy efficiency success story since per capita electricity consumption has remained fairly constant since the 1970s and is more than 40 per cent below the US average. But a careful analysis of the contributory factors estimates that California’s ambitious energy efficiency policies account for less than one third of this difference.8 The link between improved energy efficiency and reduced energy demand is further complicated by the presence of multiple rebound effects. For example, since fuel-efficient cars make travel cheaper, consumers may choose to drive further and/or more often, thereby offsetting some of the energy savings achieved. Drivers may use the savings on fuel bills to buy other goods and services which necessarily require energy to provide – such as laptops made in China and shipped to the UK. Reductions in fuel demand will translate into lower fuel prices which in turn will encourage increased fuel consumption elsewhere. Similar mechanisms exist in industry, where cost-effective energy efficiency improvements allow firms to expand output, lower product prices and increase market demand which in turn stimulates economic growth and aggregate energy consumption. In some cases, energy efficient innovations may lead to new, unforeseen energy-using applications, products and industries.9 For example, the Bessemer process greatly

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A. Sudarshan and J. Sweeney, Deconstructing the ‘Rosenfeld Curve’ (Precourd Institute for Energy Efficiency, Stanford University, 2008), p. 38. S. Sorrell, ‘Jevons’ Paradox revisited: the evidence for backfire from improved energy efficiency’, Energy Policy 37 (2009), 1456–69; and J. Jenkins, T. Nordhaus and M. Shellenberger, Energy Emergence: Rebound and Backfire as Emergent Phenomena (Breakthrough Institute, 2011).

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improved the energy efficiency of steel-making, but also produced cheaper and higher-quality steel suitable for a wider range of uses, thereby increasing demand for both steel and coal. Rebound is therefore an emergent property of complex economic systems, with the multiple mechanisms and effects being difficult to isolate and measure, especially at the economy-wide level and over the longer term. But a growing body of evidence suggests that these effects are larger than was previously thought and frequently offset or even eliminate the energy savings from improved energy efficiency.10 From an engineering perspective, energy demand may be reduced by improving the thermodynamic efficiency of energy conversion devices such as boilers and engines; preserving, heat, light, momentum or materials in passive systems, such as houses, cars and steel bars; or reducing demand for final energy services such as thermal comfort and mobility.11 For example, gas use for home heating may be reduced by installing a more efficient boiler, insulating the walls or roof, or accepting lower internal temperatures; petroleum use for car travel may be reduced by improving the efficiency of the engine, reducing the size, weight, rolling resistance and/or air resistance of the vehicle, or simply driving less; and coal use for steel manufacture may be reduced by improving the efficiency of blast furnaces, increasing scrap recovery and product life, or designing buildings and products to use less steel. Globally, Cullen et al. estimate that that global average conversion losses could be reduced by a theoretical maximum of 89 per cent and passive systems losses by a practical maximum of 73 per cent, implying that current demand for energy services could be provided with much lower energy consumption.12 But this is a theoretical potential, so the technical and (especially) economic potential is likely to be much less. Also, the rate at which improvements in conversion efficiency or passive systems can be achieved is constrained by the rate of turnover of the relevant capital stock. For example, cars and white goods have an average lifetime of ten years, while the lifetime of power stations, blast furnaces, ships and aircraft can easily exceed thirty years.13 Premature replacement of existing equipment can accelerate the rate of efficiency improvement,

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Jenkins et al., Energy Emergence; S. Sorrell and J. Dimitropoulos, UKERC Review of Evidence for the Rebound Effect: Technical Report 3: Econometric studies (UK Energy Research Centre, 2007); H. D. Saunders, ‘Recent evidence for large rebound: Elucidating the drivers and their implications for climate change models. The Energy Journal 36(1) (2015), 23–48; and H. D. Saunders, ‘Historical evidence for energy efficiency rebound in 30 US sectors and a toolkit for rebound analysts’, Technological Forecasting and Social Change 80(7) (2013), 1317–30. 11 J. M. Cullen and J. M. Allwood, ‘The efficient use of energy: tracing the global flow of energy from fuel to service’, Energy Policy 38(1), 75–81. 12 J. M. Cullen and J. M. Allwood, ‘Theoretical efficiency limits for energy conversion devices’, Energy 35 (2010), 2059–69; and J. M. Cullen, J. M. Allwood and E. H. Borgstein, ‘Reducing energy demand: what are the practical limits?’, Environmental Science & Technology 45 (2011), 1711–18. 13 S. J. Davis, K. Caldeira and H. D. Matthews, ‘Future CO2 emissions and climate change from existing energy infrastructure’, Science 329 (2010), 1330–3.

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but this involves trade-offs between the energy used in constructing new equipment and the energy used in operating the old equipment.14 Further reductions in energy demand may be achieved by reducing demand for the relevant energy services (‘sufficiency’), but growing incomes create strong pressures in the opposite direction. This is particularly the case for countries at earlier stages of industrial development, but also applies more generally: for example, an analysis of lighting demand over three centuries and six continents finds no evidence of saturation even in the wealthiest countries.15 Changes in demand for energy services can often occur fairly rapidly, but these too may be constrained by the lifetimes of relevant technologies and infrastructures.16 For example, the physical characteristics and spatial location of houses, workplaces and other assets can lock in heating, cooling and mobility needs for decades. More generally, voluntary actions to reduce any form of consumption face multiple obstacles within a growth-based economy.17 In sum, equating improved energy efficiency with reduced energy demand can be misleading, while reducing energy service demand involves swimming against a strong tide. A failure to acknowledge this may partly account for the accumulation of estimates of ‘energy savings’ from specific interventions, while aggregate energy consumption continues to increase. This does not mean that energy demand cannot be reduced, but it does imply that it may be more challenging than many analyses, policy documents and political statements suggest.

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S. M. Lenski, G. A. Keoleian and K. M. Bolon, ‘The impact of “Cash for Clunkers” on greenhouse gas emissions: a life cycle perspective’, Environmental Research Letters 5(4) (2010), 044003, available at http://iopscience.iop.org/article/10.1088/1748-9326/5/4/044003#metrics 15 J. Y. Tsao and P. Waide, ‘The world’s appetite for light: empirical data and trends spanning three centuries and six continents’, LEUKOS 6 (2010), 259–81. 16 C. Guivarch and S. Hallegatte, ‘Existing infrastructure and the 2 C target’, Climatic Change 109 (2011), 801–5. 17 S. Sorrell, ‘Energy, economic growth and environmental sustainability: five propositions’, Sustainability 2 (2010), 1784–809.

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ENERGY DEMAND REDUCTION POLICY Katy Roelich1 and John Barrett2

THE NEED FOR ENERGY DEMAND REDUCTION One of the greatest challenges facing energy and climate change policy is the speed and scale of change needed to avoid exceeding cumulative emissions budgets that result in a greater than 2°C increase in global temperature. The most significant opportunities to reduce emissions are to reduce demand for energy and decarbonise the supply of that energy. These factors are not independent; they are strongly but inversely related – if less is achieved through reducing demand for energy then the energy supply will have to decarbonise further and faster. Furthermore, demand reduction can greatly reduce abatement costs and is an important transition mechanism while effective supply-side technologies are developed.3 Demand reduction can provide many parallel benefits, including fuel poverty alleviation, energy security, lower public health spending and job creation.4 Furthermore, it could reduce the need to invest in new supply capacity and grid

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Katy Roelich is a Senior Academic Fellow at the School of Earth and Environment and School of Civil Engineering, University of Leeds. Prior to joining Leeds Katy was co-leader of the Rethinking Development theme at the Stockholm Environment Institute and worked in environmental and engineering consulting in the UK and overseas for nine years. Her current research centres on the governance of sustainable transitions. John Barrett is Professor of Sustainability Research at the School of Earth and Environment, University of Leeds. His research interests include sustainable consumption and production (SCP) modelling, carbon accounting and exploring the transition to a low-carbon pathway. He has been an advisor to the UK government on the development of carbon footprint standards and the future of consumption-based emissions in the UK. S. Pye, W. Usher and N. Strachan, ‘The uncertain but critical role of demand reduction in meeting long-term energy decarbonisation targets’, Energy Policy 73 (2014), 575–86. International Energy Agency, Capturing the Multiple Benefits of Energy Efficiency (2014), pp. 18–25, available at http://www.iea.org/publications/freepublications/publication/capturing-themultiple-benefits-of-energy-efficiency.html

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reinforcement and requires no technological breakthrough. Despite this importance, support for demand reduction is marginalised in comparison to supply technologies.5 In this chapter we review current EU policy on demand reduction and suggest how it could be strengthened. CURRENT EU POLICY ON ENERGY DEMAND REDUCTION In 2014 EU leaders agreed on the 2030 framework for climate and energy policies, which introduced an indicative target of 27 per cent improvement in energy efficiency across the EU, compared to projections of future energy consumption. No binding targets for individual countries have been set but this will be reviewed, along with the target, in 2020. The overarching target is supported by a number of specific directives, including the Energy Efficiency Directive (2012), the Energy Performance of Buildings Directive (2010), the Energy Labelling Directive (2010) and the Ecodesign Directive (2009). Specific aspects of the directives, relating to key sectors of energy demand, are summarised in Table 80.1. Examples of specific energy policies in the UK have been provided in the right hand column to illustrate how EU requirements have been transposed into national policy. It is important to note that the majority of these policies are based on energy efficiency (using fewer units of energy for each unit of output) and not a reduction in energy consumption (reducing absolute demand for energy). Table 80.1 EU and UK policy on energy demand reduction

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EU policy

UK policy

Horizontal

EU-wide energy consumption target National Energy Efficiency Action Plans Information programmes

Energy Company Obligation Energy Saving Advice Service

Buildings

Requirement for zero-energy new buildings Energy performance certificates

Building regulations Energy Performance Certificates Display Energy Certificates (commercial buildings) Smart meters

Products

Energy labelling Eco-design minimum requirements

Energy-related products regulations Market surveillance and testing

Public bodies

Retrofit public estate Public sector procurement

Greening government commitments on retrofit and procurement

Industry

Emissions Trading Scheme

CRC energy efficiency scheme Mandatory GHG reporting Climate Change Agreements Energy Savings Opportunity Scheme

C. Wilson, A. Grubler, K. S. Gallagher and G. F. Nemet, ‘Marginalization of end-use technologies in energy innovation for climate protection’, Nature Climate Change, 2(11) (2012), 780–8.

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Energy conservation was superseded by energy efficiency as a UK policy goal in the late 1980s, as the threat of oil shortages receded and as the Conservative government of the time strengthened its focus on economic growth and productivity.6 Energy efficiency does not necessarily lead to a reduction in energy use. Considerable evidence of rebound effects demonstrate that efficiency gains drive further economic growth that, in turn, increase energy consumption.7 Evidence shows that the energy demand of the UK economy has barely reduced for the past twenty years, despite widespread energy efficiency policies. From a consumption perspective, in 1990 the primary energy demand of the UK economy was 11.5 EJ and in 2011 it was 11.0 EJ.8 THE LIMITATIONS OF CURRENT POLICY APPROACHES Energy efficiency policy in Europe, and in the UK in particular, has evolved to focus on technologies that use energy, such as buildings and products, and on efficiency, not absolute reduction. Furthermore, like many countries, the UK relies on market forces to deliver energy efficiency programmes. It is important that momentum on building and product efficiency is maintained, but there must be a parallel debate to address a series of limitations of this approach in achieving energy demand reduction. Wider drivers of energy demand Energy demand is driven by a complex range of factors including infrastructure, economics, habits and social norms. In this way it is a socio-technical system.9 Many of the factors that influence energy demand are affected by policy in departments with no responsibility for energy or climate change. For example, decisions on road-building, public transport and spatial planning will affect the demand for energy from transport; planning policy and building codes will affect demand from residential buildings; economic policies on VAT rates, interest rates and banking reserves all affect energy demand from

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P. S. Mallaburn and N. Eyre, ‘Lessons from energy efficiency policy and programmes in the UK from 1973 to 2013’, Energy 7(1) (2014), 23–41. H. D. Saunders, ‘Historical evidence for energy efficiency rebound in 30 US sectors and a toolkit for rebound analysts’, Technological Forecasting and Social Change 80(7) (2013), 1317–30; G. Blanco, R. Gerlagh, S. Suh, J. Barrett, H. C. de Coninck, C. F. Diaz Morejon, R. Mathur, N. Nakicenovic, A. Ofosu Ahenkora, J. Pan, H. Pathak, J. Rice, R. Richels, S. J. Smith, D. I. Stern, F. L. Toth, and P. Zhou, ‘Drivers, trends and mitigation’, in O. Edenhofer, R. Pichs-Madruga, Y. Sokona, E. Farahani, S. Kadner, K. Seyboth, A. Adler, I. Baum, S. Brunner, P. Eickemeier, B. Kriemann, J. Savolainen, S. Schlömer, C. von Stechow, T. Zwickel and J.C. Minx (eds.), Climate Change 2014: Mitigation of Climate Change. Contribution of Working Group III to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (Cambridge University Press, 2014). Department for Environment, Food and Rural Affairs, ‘Defra official statistics release: UK’s carbon footprint 1997–2011’ (2014), available at https://www.gov.uk/government/uploads/system/ uploads/attachment_data/file/261692/Consumption_emissions_28_Nov_2013.pdf G. P. J. Verbong and F. W. Geels, ‘Exploring sustainability transitions in the electricity sector with socio-technical pathways’, Technological Forecasting and Social Change, 77(8) (2010), 1214–21.

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industry and households. A focus on energy technology and on market forces alone will not deliver change in a complex socio-technical system. Rebound effect The effects of energy efficiency on demand reduction can be further diminished by what are termed rebound effects. Rebound effects can be direct: for example if a car is more fuel-efficient the owner may choose to drive further, offsetting any energy savings. They can also be indirect; for example, the savings in fuel costs of a more efficient car could be spent on other goods, which require energy to produce. And finally, a reduction in fuel demand could reduce fuel prices and increase fuel consumption in other parts of the economy. There is growing evidence to suggest that rebound effects can offset or eliminate savings from energy efficiency. While they are likely to be less than 100 per cent (which would result in no benefit), they are likely to be significant (in the region of 65–80 per cent). These are most significantly due to economy-wide changes such as market price and economic growth effects, adjustments in capital stocks as well indirect emissions associated with new energy infrastructure.10 Low price elasticity Energy price elasticity is low, meaning that broad-brush market-based instruments, like taxes, which aim to drive behaviour change by increasing the cost of energy, have limited success. This is compounded by the presence of a series of market barriers to reducing energy demand. Furthermore, in the face of rising energy prices, politicians are unwilling to tax at the level necessary to drive behaviour change. Therefore, broad economic instruments like taxes and cap and trade, on their own, are unlikely to be the most efficient way to reduce energy demand. HOW MIGHT WE ADDRESS THESE LIMITATIONS? An economy-wide approach that focuses on demand reduction is needed to overcome the challenges of the rebound effect and to address the wider drivers of energy consumption. Furthermore, energy demand policy needs to move from relying on orthodox economic instruments to those that address the socio-technical system that drives energy consumption. The current lack of coordination across government departments could be addressed, and action on demand accelerated, if a cross-government target for primary energy demand reduction was enforced alongside the current target for emissions reductions. This would increase the focus of policy-makers on the rebound effect and result in interventions that better represent the breadth of drivers of energy consumption. A wider range of interventions, beyond those that rely on orthodox economic assumptions about economic rationality and autonomous decision-making,

10

Saunders, ‘Historical evidence for energy efficiency rebound’.

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must be developed to address the infrastructural and social factors locking us into current patterns of energy demand. This can include providing appropriate information by trusted individuals, benchmarking against others’ performance and ensuring that default options are energy efficient.11 Mechanisms that apply only to the change in demand, not the whole of demand, could overcome some of the market barriers to demand reduction. This would also reduce the political risk of intervention because the ratio of energy reduction to revenue transfer would be high.12 An example of this would be a feed-in tariff (FiT) for demand reduction, where a payment is made for monitored reduction in energy usage, similar to the current FiT for generation of renewable energy.13 A price-based mechanism (like a FiT) has advantages over a quantity-based mechanism (like white certificates) because it is more likely to encourage new entrants.14 Furthermore, the transparency and bankability of FiTs can lower the risk and cost of finance, which can be a significant barrier to energy demand reduction. CONCLUSIONS Rapid and radical energy demand reduction is essential if we are to avoid dangerous climate change and could significantly reduce the cost of mitigation. Current approaches to energy reduction tend to focus on energy using technologies, promoting energy efficiency and relying on market forces to drive change. This is ineffective for a number of reasons, including the complex socio-technical system which drives energy demand, the results of rebound effects and the low elasticity of energy price. A more supportive policy environment would take an economy-wide approach, supported by a cross-government target for demand reduction. A wider range of interventions would be implemented to address the social and infrastructural issues locking us into current demand practices. Finally, an economy-wide approach would be supported by mechanisms which apply to the reduction in demand to incentivise reduction and increase access to finance.

11

S. Sorrell, ‘Reducing energy demand: A review of issues, challenges and approaches’. SPRU Working Paper series SWPS 2014-22. 12 N. Eyre, ‘Energy saving in energy market reform –The feed-in tariffs option’, Energy Policy 52 (2013), 190–8. 13 P. Bertoldi, S. Rezessy and V. Oikonomou, ‘Feed-in tariff for energy saving: thinking of the design’. Proceedings of the ECEEE Summer Study (2009). 14 C. Mitchell, The Political Economy of Sustainable Energy (Palgrave Macmillan, 2010).

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DEMAND RESPONSE IN WHOLESALE MARKETS Joel B. Eisen1

INTRODUCTION Demand response participation in wholesale markets is an important building block in a profound transformation of electricity systems in the United States and Europe. Technical and economic innovations, supported by governmental policies, are moving electricity systems toward smart grids2 that integrate generation, transmission and distribution in a more networked, environmentally responsible and efficient manner, incorporating distributed energy resources and delivering benefits for utilities and consumers.3 As one component of smart

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Professor Joel B. Eisen teaches and writes in the areas of energy law and policy, environmental law and policy, and the smart grid. He is a co-author of the leading law and business school text on energy law, energy, economics and the environment, and has written numerous books, book chapters, treatises and law review articles on electric utility regulation. His scholarship (available at Social Science Research Network, http://papers.ssrn.com/sol3/cf_dev/AbsByAuth. cfm?per_id=181414) has appeared in journals at Harvard, UCLA, Duke, Notre Dame, Fordham, Illinois, Wake Forest and William & Mary law schools, among other venues. In recognition of his contributions to scholarship, Richmond School of Law named him the inaugural Austin Owen Research Fellow in 2013. His article ‘Residential renewable energy: by whom?’ was honoured as one of the top four environmental law articles of 2011. He was the University of Richmond’s Distinguished Educator for 2010–11 and, in spring 2009, a Fulbright Professor of Law at the China University of Political Science and Law in Beijing, China. J. B. Eisen, ‘An open access distribution tariff: removing barriers to innovation on the smart grid’, UCLA Law Review 61 (2014), 1712, 1714 (contemplating a ‘multimodal grid featuring supply, demand, and network management taking place at multiple nodes on the network’). The US Energy Independence and Security Act of 2007 established a national policy for grid modernisation and described the smart grid as a system capable of accomplishing over ten diverse objectives. 42 USC Sec. 17381. See J. B. Eisen, ‘Smart regulation and federalism for the smart grid’, Harvard Environmental Law Review 37 (2013), 1–56.

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grids, consumers, utilities and regional grid operators may benefit from more use of demand response programmes that reduce peak power consumption and market price spikes, balance intermittency of renewables and achieve greater grid efficiency and reliability. DEMAND RESPONSE DEFINED The US Federal Energy Regulatory Commission (FERC) defines demand response as: ‘changes in electric use by demand-side resources from their normal consumption patterns in response to changes in the price of electricity, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized’.4 There are three broad categories of demand response programmes. Emergency/standby programmes, the most common, offer customers reduced rates or incentive payments if they agree to reduce their interruptible load. For decades, utilities have contracted with large industrial or commercial customers to allow curtailment when necessary to lower utilities’ costs of managing peak demand. Participants typically have little control: once enrolled, they generally must reduce load when ‘called’. A residential sector example is a programme in which customers agree to allow their utility to directly control air conditioners to reduce demand at peak hours. Price response bidding programmes allow customers to bid demand reductions into wholesale markets, often through the use of intermediaries (see below). Unlike emergency programmes, these allow customers to choose when and how much energy use they are willing to curtail. Customers can respond to real-time or day-ahead price signals, depending on the market. The third category is price-responsive demand. In these programmes, customers have variable retail electricity rates, and can reduce consumption when rates are high, or shift consumption to off-peak hours. In general, customers may handle curtailments in a variety of ways, including shifting electricity use to non-peak hours. At present, most demand response comes from large commercial and industrial users that can stagger equipment start-up, use electricity stored in batteries or produce power from on-site generators to replace power not purchased. These customers usually can provide demand reductions meeting grid operators’ minimum size requirements, and can afford to invest in necessary smart meters and communications systems. However, demand response opportunities in the residential sector are growing substantially with increased deployment of smart meters and related technologies.5

4 5

CFR 18, Sec. 35.28(b)(4). Bipartisan Policy Center, ‘Policies for a modern and reliable U.S. electric grid’ (February 2013), available at http://bipartisanpolicy.org/wp-content/uploads/sites/default/files/Energy_ Grid_Report[1].pdf, 50.

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DEMAND RESPONSE PARTICIPATION IN WHOLESALE MARKETS Demand response participation in organised wholesale markets is substantial in the US,6 and emerging in Europe and elsewhere.7 In the US, FERCapproved ‘regional transmission organisations’ (RTOs) administer regional transmission grids and oversee multistate wholesale electricity markets.8 More than half the electricity sold in the US trades on these markets, while some regions oppose the RTO model and rely on individual utilities to govern transmission. RTOs typically administer three types of markets: 1. Energy – in an energy market, utilities and other load-serving entities purchase electricity for delivery within the next hour or a day ahead. 2. Capacity – a capacity market is a forward-looking market, in which participants commit to serve future demand with new generating capacity.9 3. Ancillary services – these markets compensate providers of ‘regulation’ (an industry term of art for keeping grid frequency in balance) and reserve services that enable the reliable transmission of electricity.10 At first, the wholesale markets involved only electricity generators.11 Today, demand response resources can participate in energy markets to substitute for electricity sold at the market price. In capacity markets, demand response curtailments substitute for new power plants. Ancillary service markets have

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US Federal Energy Regulatory Commission, ‘2014 assessment of demand response and advanced metering’ (December 2014), available at www.ferc.gov/legal/staff-reports/2014/demandresponse.pdf, at 11, Table 3-3 (demand response programs in organised wholesale markets had a potential of 6.1 per cent of peak demand in 2014). 7 Smart Energy Demand Coalition, ‘Mapping demand response in Europe today: tracking compliance with Article 15.8 of the Energy Efficiency Directive’ (April 2014), available at http://sedccoalition.eu/wp-content/uploads/2014/04/SEDC-Mapping_DR_In_Europe-2014-04111.pdf 8 US Federal Energy Regulatory Commission, ‘Regional transmission organizations (RTO)/independent system operators (ISO)’, available at www.ferc.gov/industries/electric/indus-act/rto.asp. One RTO with substantial demand response is PJM Interconnection, LLC (PJM), which administers a large regional grid that includes thirteen states (mostly in the mid-Atlantic region) and the District of Columbia. 9 A principal difference between the US and Europe is that in Europe, ‘few countries currently allow DSR providers [aggregators] to participate in their energy market or a capacity mechanism’, so demand response does not yet have the same opportunities to participate in markets as in the US. Linklaters, ‘Capacity mechanisms: Reigniting Europe’s energy markets’ (2014), available at www.linklaters.com/pdfs/mkt/london/6883_LIN_Capacity_Markets_Global_Web_ Single_Final_1.pdf>, at 18 (contrasting the European experience with that of PJM). 10 J. B. Eisen, ‘Distributed energy resources, virtual power plants, and the smart grid’, University of Houston Environmental and Energy Law and Policy Journal 7 (2012), 191–213, at 198. 11 J. B. Eisen, ‘Who regulates the smart grid?: FERC’s authority over demand response compensation in wholesale electricity markets’, San Diego Journal of Climate and Energy Law 4 (2012– 2013), 69–103, at 80.

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comparatively little demand response participation,12 but demand response can increasingly help with frequency regulation.13 Intermediaries known as ‘curtailment service providers’ (CSPs) or ‘aggregators’ bid demand response into the markets. For example, CSPs in the PJM RTO in the US Mid-Atlantic region offer demand response in energy, capacity, day-ahead scheduling reserve, synchronised reserve and frequency regulation markets.14 Aggregators can also combine demand reductions from a number of customers, enabling smaller customers to participate in markets when they otherwise could not do so. By grouping customers into a block resource, aggregators give RTOs a more reliable and controllable volume of resources for a longer time period, spreading out the risk of customers not curtailing demand when called.15 Aggregators have begun to market to the residential sector, although this market is still small. DEMAND RESPONSE BENEFITS FOR REGIONAL GRIDS, UTILITIES AND CONSUMERS Demand response resources can achieve a variety of financial and operational benefits in wholesale markets. At present, demand on the grid peaks noticeably at a small number of hours each year. This can make the marginal cost of generating electricity highly variable, with prices spiking at peak hours. Unanticipated outages or unusually high demand exacerbate this problem. At peaks that stress the grid to its limits, grid operators traditionally responded by calling on available generation capacity. Yet reducing grid stress through demand response could cut marginal costs as much or more than generating additional power. A 2009 FERC report estimated potential reductions in peak demand of up to 20 per cent.16 Demand response programmes may also lead to increased conservation if usage at peak periods is eliminated rather than shifted. Demand response can help meet future anticipated demand and avoid unnecessary expenses of building new power plants. Demand ‘peakedness’ requires grid operators to have power plants on hand to meet peak demand, which leads to oversupply of generating capacity. Many peaking plants operate fewer than 100 hours per year, and demand response could eliminate the need to build them. Demand response can also lower the need for spinning reserves: power 12

J. MacDonald, P. Cappers, D. S. Callaway and S. Kiliccote, Lawrence Berkeley National Laboratory, ‘Demand response providing ancillary services: a comparison of opportunities and challenges in the US wholesale markets’ (2012), available at www.gridwiseac.org/pdfs/forum_ papers12/macdonald_paper_gi12.pdf (noting that ‘organized electricity and ancillary services markets are just beginning to support DR resources for ancillary services’). 13 US demand response providers may take advantage of FERC’s Order 755, which changed the policies for pricing of frequency regulation service. ‘Frequency regulation compensation in the organized wholesale power markets’, Federal Register 76 (20 October 2011), 67,260. 14 PJM Interconnection, LLC, ‘Demand response, markets & operations’, available at www.pjm. com/markets-and-operations/demand-response.aspx 15 Eisen, ‘Distributed energy resources’, 203–5. 16 US Federal Energy Regulatory Commission, ‘A national assessment of demand response potential’ (June 2009), available at www.ferc.gov/legal/staff-reports/06-09-demand-response. pdf, x, Figure ES-1.

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plants that run offline, burning fossil fuels continuously, to supply power on short notice. RTOs increasingly rely on regional planning processes and capacity mechanisms17 to decide whether new power plants are needed. Factoring demand response into these models can lead to less new construction. Also, demand response increases grid reliability when used as a balancing resource for wind and solar power.18 As more distributed energy resources are integrated to the grid, demand response will be more useful in stabilising the grid. Finally, by providing incentives for CSPs and other third party providers, it encourages market competition. NEW TECHNOLOGIES AND PROGRAMME DESIGNS ARE NEEDED Because demand response gives consumers incentives to lower or adjust their consumption at strategic times, they can benefit directly. These benefits depend on availability of smart meters and communications systems19 needed for measuring and verifying demand reductions. Smart meters are digital versions of traditional analogue meters that measure electricity consumption at short time intervals and generate near real-time data. By 2014, nearly one-third of US consumers had them,20 but less than 1 per cent had devices to work with them and help manage energy usage.21 Eventually, ‘smart’ devices will give consumers more flexibility to monitor and control electricity usage, with assistance from energy service companies.22 Achieving these benefits requires more use of ‘dynamic pricing’: real-time pricing or other variable electricity pricing structures that more closely match supply and demand. Currently, most US consumers pay a fixed price that does not conform to the cost of providing electricity. Less than 1 per cent of US consumers have any form of variable pricing, with the most common form being time-of-use pricing.23 Dynamic pricing gives consumers incentives to cut back on consumption, and is important to the success of demand response programmes.24 A 2012 survey of twenty-four utility pilot programmes in

17

An example of a capacity market is PJM’s ‘reliability pricing model’. PJM Interconnection, LLC, ‘Capacity market (RPM)’, available at www.pjm.com/markets-and-operations/rpm.aspx 18 Eisen, ‘Distributed energy resources’, 201–5. 19 US Department of Energy, ‘The smart grid: an introduction’ (2009), available at http://energy. gov/sites/prod/files/oeprod/DocumentsandMedia/DOE_SG_Book_Single_Pages%281%29.pdf, 12 (listing remote sensors and monitors, switches and controllers with embedded intelligence, and digital relays). 20 US Federal Energy Regulatory Commission, ‘2014 assessment of demand response and advanced metering’, 3, Table 2-1 (31.5 per cent deployment). 21 US Department of Energy, ‘Advanced metering infrastructure and customer systems’, available at www.smartgrid.gov/recovery_act/deployment_status/ami_and_customer_systems##Customer DevicesDeployed 22 US Department of Energy, ‘The smart grid: an introduction’, 11. 23 US Federal Energy Regulatory Commission, ‘2014 assessment of demand response and advanced metering’, 30. 24 A. Faruqui, R. Hledik and J. Palmer, ‘Time-varying and dynamic rate design’ (2012), available at www.ksg.harvard.edu/hepg/Papers/2012/RAP_FaruquiHledikPalmer_TimeVaryingDynamicRateDesign_2012_JUL_23.pdf, 39.

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North America, Europe and Australia found that dynamic pricing programmes yielded both cost savings and demand reductions.25 Besides taking advantage of smarter technologies, demand response programmes must be designed to respond to customers’ needs and wants, to prompt them to take part. Communication tailored appropriately to consumers is essential, as is proper design of the payments and incentives, the level of complexity and amount of customer control over the nature and duration of curtailments. For example, the Maryland-based utility Baltimore Gas & Electric (BGE), which serves 1.2 million electricity customers, has worked with the firm Opower, sending pricing signals to residential customers the night before an ‘energy savings day’ and asking them to take action. By summer 2015, BGE aims to roll out the programme to all of its residential customers.26 STRONGER AND MORE CONSISTENT GOVERNMENTAL POLICIES ARE NEEDED TO SUPPORT DEMAND RESPONSE New laws, regulations and market structures must be in place to promote effective demand response participation in wholesale markets in the US and Europe.27 An example of US federal policy is FERC Order 745, which required demand response bid into a wholesale energy market to be compensated at the ‘locational marginal price’, the price generators receive for selling electricity.28 In 2014, however, a US federal appeals court’s decision in Electric Power Supply Association v. FERC (EPSA) invalidated Order 745, putting the future of more widespread demand response in the wholesale markets in doubt.29 In the US, states control retail electricity sales and the federal government regulates wholesale transactions. The court held that demand response is exclusively a retail-level matter beyond FERC’s jurisdiction. Given demand response’s benefits, its severely reduced role in US wholesale markets after the EPSA decision would have widespread negative effects. Immediately after the decision, two petitions were filed with FERC to invalidate regional capacity auctions that included demand response resources. The PJM RTO removed demand response from bidding into its capacity auctions,30

25

Ibid., 27–8. US Federal Energy Regulatory Commission, ‘2014 assessment of demand response and advanced metering’, 24. 27 Policies needed in Europe are discussed in Smart Energy Demand Coalition, ‘Mapping demand response in europe today: tracking compliance with Article 15.8 of the Energy Efficiency Directive’. 28 US Federal Energy Regulatory Commission, ‘Demand response compensation in organized wholesale energy markets’, Federal Register 76 (24 March 2011), 16,658 (to be codified at CFR 18, pt. 35). 29 No. 11-1486 (2014) (DC Circuit Court of Appeals). 30 PJM Interconnection, LLC, ‘Revisions to the reliability pricing market (‘RPM’) and related rules in the PJM open access transmission tariff (‘tariff’) and reliability assurance agreement among load serving entities (‘RAA’)’ (14 January 2015), Docket No. ER15-852-000, available at www. pjm.com/documents/ferc-manuals/ferc-filings.aspx 26

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providing instead that load-serving entities controlling demand response could cut their obligation to procure capacity. This is controversial because it leaves out industrial customers and CSPs that bid substantial amounts of demand response into PJM’s markets. Concerned about impacts on wholesale markets, the federal government, demand response providers and others petitioned the US Supreme Court to reverse the EPSA decision. In May 2015, the Court granted the petition, which may well lead to a conclusion that ‘FERC has authority to regulate wholesale rates and activities that have a direct impact on rates, such as demand response’.31 The petitioners’ argument to this effect is supported in part by two recent decisions of US appellate courts. These decisions rejected state laws offering subsidies to new power plants above PJM capacity market prices, and affirmed FERC’s exclusive authority to regulate capacity markets.32 In a related case (ONEOK, Inc. v. Learjet, Inc.), the Supreme Court held in April 2015 that FERC’s statutory authority to regulate practices affecting wholesale market rates did not pre-empt state antitrust laws.33 However, the Court may distinguish this decision on the basis that demand response – like capacity market rules – has a more direct impact on rates than state antitrust laws, which the ONEOK court believed aim more broadly at businesses’ anti-competitive conduct.34 Efforts by grid operators controlling single-state grids in California35 and New York36 are also underway to design new legal structures to promote distributed energy resources and expand demand response programmes in wholesale markets. In Europe, Article 15.8 of the Energy Efficiency Directive outlined specific requirements to promote demand response programs, although progress lags behind the US.37

31

J. B. Eisen, ‘Supreme Court to hear major energy law federalism case’, CPR Blog, Center For Progressive Reform, available at www.progressivereform.org/CPRBlog.cfm?idBlog=9D7551F2DE35-1637-D13A016B799BBCC0. 32 PPL EnergyPlus, LLC v. Nazarian (2014) 753 F.3d 467 (4th Circuit), petition for cert. filed, No. 14-614, No. 14-623 (25 and 26 November 2014); and PPL EnergyPlus, LLC v. Solomon (2014) 766 F.3d 241 (3rd Circuit), petition for cert. filed, No. 14-634, No. 14-694 (26 November 2014 and 10 December 2014). 33 ONEOK, Inc. v. Learjet, Inc. (2015) 575 U.S. __ (2015); decided 21 April 2015. 34 Eisen, ‘Supreme Court to hear major energy law federalism case’. For further discussion of this and other energy law issues raised by the ONEOK decision, see E. Hammond, ‘ONEOK v. Learjet, energy law’s jurisdictional boundaries: a call for course correction’, George Washington Law Review Docket, available at www.gwlr.org/oneok-v-learjet 35 California Public Utilities Commission decisions promoting demand response are described in Jeff St. John, greentechgrid, ‘California’s demand response 2.0 creates new competitive markets’ (11 March 2015), available at www.greentechmedia.com/articles/read/Californias-DemandResponse-2.0-Creates-New-Competitive-Markets 36 New York’s ambitious framework called ‘Reforming the energy vision’ was adopted by the state’s Department of Public Service in 2015. New York Department of Public Service, ‘Order adopting regulatory policy framework and implementation plan’ (26 February 2015), available at www3. dps.ny.gov/W/PSCWeb.nsf/All/26BE8A93967E604785257CC40066B91A?OpenDocument 37 Smart Energy Demand Coalition, ‘Mapping demand response in Europe today: tracking compliance with Article 15.8 of the Energy Efficiency Directive’.

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CONCLUSION Demand response offers considerable energy saving and management capabilities, with further success depending on development and deployment of the right technologies required for participation, continued evolution of regulatory initiatives (particularly rules that promote participation in wholesale markets administered by regional grid operators), and encouragement of CSPs and other market participants. Even with these numerous challenges to full deployment, demand response is likely to be an increasing and important component of electricity wholesale markets.

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PERCEIVED EFFECTIVENESS OF DIFFERENT METHODS OF DELIVERING INFORMATION ON ENERGY EFFICIENCY Lucie Stevenson1 and Danny Campbell2

Public awareness campaigns are widely used to foster sustainable behaviour and often include attempts to encourage greater energy efficiency. An important, yet usually overlooked, aspect of these programmes is the effectiveness of different methods of delivering the information to the public. In this chapter best–worst scaling is used to show that communication delivered via group discussions and activities is a more effective way to communicate the merits of reducing emissions and energy efficiency. INTRODUCTION Much government intervention on reducing emissions has been designed and aimed at an organisational level rather than specifically targeting an individual level within society. In order to achieve such targets and reduce emissions it is vital that individuals within society have appropriate knowledge regarding climate change and that their behaviours that influence climate change are addressed.

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Lucie Stevenson works as a Compliance Systems Graduate within the Sustainable Solutions Business Unit at Jacobs Engineering UK, where she is involved in a range of projects relating to energy, carbon and environmental management. Lucie has an MSc in Energy Management from Stirling University and a BA in Applied Social Sciences from Robert Gordon University. Danny Campbell is a Senior Lecturer in Economics in the Economics Division at the University of Stirling. He is an expert on environmental valuation and has degrees in agricultural economics and rural development and a PhD in environmental economics from Queen’s University Belfast. His main area of research concerns the valuation of natural resources as well as methodological and econometric issues relating to discrete choice experiments.

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Increasing public awareness is an important objective when encouraging individuals to change their behaviour and energy consumption. Despite this, and the widespread growth in public awareness campaigns encouraging energy efficiency, relatively little is known about the effectiveness of different methods of delivering the information to the public. However, from a policy perspective, it is crucial to understand the most appropriate means of getting the message of energy efficiency across to the public. This chapter makes an important contribution in this area. As indicated above, we use a method known as best–worst scaling (BWS) to rank how the public perceives different methods of communication and delivery. Our results show that communication delivered via group discussions and activities is the most effective way of communicating the merits of reducing emissions and energy efficiency. METHODOLOGY AND DATA The best–worst scaling method While people can usually comfortably rank a small list of items, as the number of items that are to be ranked increases, the ranking task obviously becomes more cognitively challenging and, importantly, more susceptible to a range of anomalous behaviours. The BWS technique avoids this by breaking the list down into smaller lists of more manageable sizes, thereby reducing – if not eliminating – the difficulty in ranking the full list of items in terms of their importance (or preferability). Furthermore, as respondents only choose at the extreme (that is, best/worst or most/least), the process is considered to be ‘scale-free’ and prevents a scale-use bias. For example, in the case of a Likert scale for identifying respondents’ level of preferences, there may be situations where respondents only focus on one part of the scale. Moreover, there may be cases where respondents have difficulty in distinguishing the differences between the levels of the scale. For example, the difference between ‘strongly agree’ and ‘agree’ may be difficult to identify. This creates an ambiguity in the interpretation of these scale levels across respondents. In BWS, however, such ambiguity is absent, as only extremes need to be identified in a subset of items. There is also evidence that people use better judgment when they only need to identify the extremes, rather than preferences with levels.3 Modelling approach BWS is an application of the random utility maximisation theory, whereby respondents evaluate all possible pairs of items within the displayed BWS task

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J. J. Louvière, ‘The best-worst or maximum difference measurement model: applications to behavioral research in marketing’ (1993), American Marketing Association’s Behavioral Research Conference, Phoenix, AZ.

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and choose the pair that reflects their maximum difference in preference. The number of unique pairs, J, is given by S(S-1), where S represents the number of items in the BWS task. Overall utility, U, associated with respondent n’s chosen pair, i, in BWS task t is given by the difference in utility between the best and worst items:

where β is a vector of estimated parameters (subject to

) relat-

ing to the best and worst items, x (indexed by b and w respectively), and ε is an iid type I extreme value (EVI) distributed error term, with constant variance of π 2 /6. Given these assumptions, the probability of the sequence of best– worst choices made by individual n can be represented by the multinomial logit model:

where yn gives the sequence of best–worst choices over the Tn BWS tasks for respondent n. Data The BWS data is obtained from an empirical case study that investigates people’s perception of the effectiveness of different ways of delivering information for reducing emissions. Overall, we explored the relative effectiveness of six communication delivery methods: 1. individual activities 2. group discussions 3. verbal information 4. group game activities 5. reading materials 6. online materials Survey design plays an important role in obtaining reliable responses. In our survey, each respondent was presented with four items (that is, communication delivery methods) at each of six BWS choice tasks. For each choice task, they were asked to indicate the delivery methods that they considered to be the ‘most’ and ‘least’ effective means of communicating information on energy efficiency. Figure 82.1 illustrates a typical BWS task presented to the respondents.

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Figure 82.1 Typical best–worst scaling task The experimental design avoided any context- and ordering-based biases. In each BWS choice task, different combinations of four delivery methods were shown to respondents. The combinations of four communication methods in these choice tasks satisfied optimal design characteristics: frequency balance; orthogonality; positional balance; and connectivity among tasks. That is, the one-way frequencies reveal that the design was adequately balanced and that the two-way frequencies were relatively orthogonal, whereby each item appeared a similar number of times with every other item. The web-based surveys were conducted with a sample of 159 residents of Scotland in 2014. With each respondent answering six BWS tasks, we obtained a total of 954 observations for model estimation. RESULTS We present the results from the econometric model in Table 82.1, estimated using maximum likelihood estimation. Focusing on the estimated coefficients (i.e., the β terms), we observe that, on average, respondents consider group discussions as the most effective delivery method for reducing emissions, individual activities as the least effective and group game activities, verbal information, online materials and reading materials all ranked in between. To make the interpretation easier, we also provide the ratio-scaled prob abilities, Pr(x). These scores provide a more intuitive interpretation; they show, for instance, that 14 per cent of respondents ceteris paribus deem online reading materials to be the most effective delivery method. Moreover, the scores can also be interpreted to show that, for example, delivery information using group discussion activities is, on average, considered to be more than three times more effective compared to information delivery through individual activities (24.644 per cent to 8.137 per cent). A closer look at the ratio-scaled probabilities clearly reveals the perceived advantages of a group effect. Taken together, group discussions and group game activities are considered by almost half of the respondents (24.644 per cent + 22.634 per cent = 47.273 per cent) to be the most effective means of

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Table 82.1 Estimation results  Ratio-scaled probabilities (Pr(x))

Estimates (β)

Individual activities

estimated

t-rated

estimated

t-rated

–0.826

–9.82

8.137

12.79

Group discussion

0.633

9.23

24.644

25.77

Verbal information

0.125

1.89

17.510

21.44

Group game activities

0.498

8.54

22.634

28.19

Reading materials

–0.248

–3.45

13.189

17.19

Online materials

–0.183

–2.59

13.885

17.86

Log-likelihood ρ

2

reducing emissions. Importantly, such activities are thought to be almost twice as effective compared to the information that could be delivered online or via a mailshot (13.885 per cent + 13.189 per cent = 27.074 per cent). CONCLUSION Our results give a sure signal that group activities such as discussions and games are likely to have a much larger impact on behaviour than other forms of information delivery. Although specific to this dataset this finding has obvious implications for those engaged in designing public awareness campaigns. While material provided online or through mailshots will make a positive contribution in encouraging the public to adopt more sustainable behaviour, their overall impact will be small compared to group activities. The optimal public awareness campaign should, therefore, consider them in combination.

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DEVELOPING BEHAVIOURAL INTERVENTIONS: THREE LESSONS LEARNED FOR DELIVERING ENERGY POLICY Wändi Bruine de Bruin1 and Tamar Krishnamurti2

To curb climate change, the Intergovernmental Panel on Climate Change (IPCC) proposes that the energy sector must reduce global CO2 emissions to 90 per cent below 2010 levels between 2040 and 2070.3 Developed countries disproportionally contribute to climate change.4 The US produces 20 per cent

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Professor Wändi Bruine de Bruin holds a University Leadership Chair in Behavioural Decision Making at the Leeds University Business School, where she co-directs the Centre for Decision Research. She is Collaborating Professor at Carnegie Mellon University’s Department of Engineering and Public Policy. Her research focuses on public risk perception and communication, as for example applied to climate change and low-carbon technologies. Dr Tamar Krishnamurti is an Assistant Research Professor in Carnegie Mellon University’s Department of Engineering and Public Policy. Her research interests lie in understanding the human judgments that shape decision-making. She applies basic judgment and decision-making knowledge to the design of effective communications, decision aids and interventions, including those concerned with energy consumption and conservation. This work was supported by the Center for Climate and Energy Decision Making (SES-0949710; SES-1463492), through a cooperative agreement between the US National Science Foundation and Carnegie Mellon University, as well as by the UK Economic and Social Research Council (ES/L01189/1). The authors wish to thank Baruch Fischhoff, Daniel Schwartz and Gabrielle Wong-Parodi for their helpful feedback. IPCC, ‘Climate change 2014: mitigation of climate change. Summary for policy makers’ (2014), available at www.ipcc.ch/report/ar5/wg3 M. Den Elzen, J. Fuglestvedt, N. Höhne, C. Trudinger, J. Lowe, B. Matthews, B. Romstad, C. Pires de Campos and N. Andronova, ‘Analysing countries’ contribution to climate change: scientific and policy-related choices’, Environmental Science & Policy 8 (2005), 614–36.

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of the world’s energy-related CO2 emissions, with approximately 21 per cent of that coming from US households.5 Residential electricity use can be reduced through ‘curtailment’ or ‘energy efficiency’. ‘Curtailment’ interventions aim to change consumers’ understanding and motivations, in an attempt to induce decreased usage. Such interventions may include electricity use feedback via the electricity bill or in-home displays, programmable thermostats, social advertising, goal setting, neighbourhood competitions, tariff changes (alone or accompanied by smart metering) or a combination of these and/or other approaches. ‘Energy-efficiency’ interventions aim to promote structural improvements that lead to electricity savings without requiring consumers to change their usage behaviour, such as the installation of energy-efficient appliances, and weatherproofing of the home. Because consumers sometimes increase their usage behaviour after installing energy-efficient appliances,6 energy-efficiency interventions may need to be combined with communications that improve understanding and motivations to save electricity. Detailed reviews of residential energy conservation interventions appear elsewhere.7 In either case, effective energy-conservation policies require an understanding of consumer behaviour. Indeed, even the best policies can fail if consumers’ needs, motivations and preferences are not adequately considered. Therefore, we discuss three lessons learned from our research on reducing residential electricity use: (1) intervention design should be based on research with consumers; (2) interventions should be tested before their widespread implementation; (3) intervention design and evaluation requires interdisciplinary teams. LESSON 1: INTERVENTION DESIGN SHOULD BE BASED ON RESEARCH WITH CONSUMERS Because experts typically do not think or talk like non-experts, experts’ theorybased recommendations for how to promote behaviour change may not actually be effective for reducing residential electricity use. Hence, research is needed to obtain a better understanding of what drives consumers’ behaviours, and which interventions may be most effective for promoting behaviour change. Across multiple domains, there is a growing body of research that aims to better understand consumers, with the goal of developing more effective interventions.8

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US Department of Energy, ‘Emissions of greenhouse gases in the United States 2009’ (2009), available at www.eia.gov/environment/emissions/ghg_report/pdf/0573(2009).pdf B. A. Thomas and I. L. Azevedo, ‘Estimating direct and indirect rebound effects for U.S. households with input-output analysis. Part 1: theoretical framework’, Ecological Economics 86 (2013), 188–98. W. Abrahamse, L. Steg, C. Vlek and T. T. Rothengatter, ‘A review of intervention studies aimed at household energy conservation’, Journal of Environmental Psychology 25(3) (2005), 273–91; C. Fischer, ‘Feedback on household electricity consumption: A tool for saving energy?’, Energy Efficiency 1 (2008), 79–104. W. Bruine de Bruin and A. Bostrom. ‘Assessing what to address in science communication’, Proceedings of the National Academy of Sciences 110 (2013), 14062–8.

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One main finding from this research is that communications that accompany interventions should use plain language.9 Even recipients with higher literacy levels prefer materials that are easier to read.10 Yet outreach materials about energy conservation and other topics are often written in university-level language.11 Experts tend to express electricity use in kilowatt hours, which is hard for many consumers to understand.12 Even seemingly simple terms such as ‘smart meters’ may lead to confusion with ‘smart phones’ and to consumer dissatisfaction when smart meters do not provide personalised advice.13 It is possible to provide understandable information about energy programmes without undermining consumers’ perceived quality of the communication.14 Another main finding is that most consumers seem relatively unaware of whether their electricity use is high or low, or how much their overall electricity use is affected by specific appliances in their household.15 Perhaps, as a result, consumers often respond positively to communications that help them to understand their appliance-specific use, and how it changes over time.16 Some electricity companies send consumers home electricity reports that compare their electricity use with that of their neighbours, which can also provide indications of whether electricity use is high or low,17 but are often disliked.18 It has been argued that energy use feedback that involves such social comparisons is more effective than individual-level feedback

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L. Neuhauser and K. Paul, ‘Readability, comprehension, and usability’, in B. Fischhoff, N. T. Brewer and J. S. Downs, Communicating Risks And Benefits: An Evidence-based User Guide (US Food and Drug Administration, 2011). 10 T. C. Davis, M. S. Wolf, P. F. Bass III, M. Middlebrooks, E. Kennen, D. W. Baker, C. L. Bennett, R. Durazo-Arvizu, A. Bocchini, S. Savory and R. M. Parker, ‘Low- literacy impairs comprehension of prescription drug warning labels’ Journal of Internal Medicine 21(8) (2006), 847–51; S. K. Smith, L. Trevena, D. Nutbeam, A. Barratt and K. J. McCaffery, ‘Information needs and preferences of low and high-literacy consumers for decisions about colorectal cancer screening: utilizing a linguistic model’, Health Expectations 11(2) (2008), 123–36. 11 G. Wong-Parodi, W. Bruine de Bruin and C. Canfield, ‘Effects of simplifying outreach materials for energy conservation programs that target low-income consumers’, Energy Policy 62 (2013), 1157–64. 12 S. Darby, ‘Smart metering: what potential for householder engagement?’, Building Research & Information 38(5) (2010), 442–57. 13 T. Krishnamurti, D. Schwartz, A. Davis, B. Fischhoff, W. Bruine de Bruin, L. Lave and J. Wang, ‘Preparing for smart grid technologies: A behavioral decision research approach to understanding consumer expectations about smart meters’, Energy Policy 41 (2012), 790–7. 14 Wong-Parodi et al., ‘Effects of simplifying outreach materials’. 15 S. S. Attari, M. L. DeKay, C. I. Davidson and W. Bruine de Bruin, ‘Public perceptions of energy consumption and savings’, Proceedings of the National Academy of Sciences 107 (2010), 16054–9. 16 Fischer, ‘Feedback on household electricity consumption’. 17 P. Wesley Schultz, J. M. Nolan, R. B. Cialdini, N. J. Goldstein and V. Griskevicius, ‘The constructive, destructive, and reconstructive power of social norms’, Psychological Science 18 (2007), 429–34. 18 C. Canfield, W. Bruine de Bruin and G. Wong-Parodi, ‘Responses to electricity use feedback: effects of content, format, and individual differences’, manuscript in preparation.

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because it introduces energy-conservation norms.19 However, social comparisons may be less effective among consumers with more conservative political views, possibly because they are less interested in beating others at conserving energy.20 It is important to recognise that consumers may be motivated by different reasons for saving electricity. Interventions that provide financial incentives can motivate frugal consumers to change their behaviour, although they may revert back to baseline after incentives are discontinued.21 Yet advertising the financial benefits of saving electricity may also be counterproductive, especially among pro-environmental consumers, because it undermines the ‘warm glow’ of pro-environmental motivations.22 It may be more effective to only highlight the pro-environmental benefits of saving electricity, because most consumers are aware that their electricity bill will be reduced if they save electricity. LESSON 2: INTERVENTIONS NEED TO BE TESTED BEFORE THEIR WIDESPREAD IMPLEMENTATION Intervention researchers recommend that interventions be tested for effectiveness before their widespread implementation.23 Implementing untested interventions can be costly, if there is failure to deliver what was promised. Electricity providers and consumers may end up wasting money that could have been invested in effective interventions. Failing interventions can also undermine consumers’ trust, which is hard to restore once lost.24 Such concerns may be especially relevant for US electricity providers, for whom consumers’ trust is already relatively low.25 Even when evaluation studies are conducted, methodological problems often undermine conclusions about intervention effectiveness. One common problem is volunteer bias, which can occur when volunteers sign up for an

19

F. W. Siero, A. B. Bakker, G. B. Dekker and M. T. C. van den Burg, ‘Changing organizational energy consumption behavior through comparative feedback’ Journal of Environmental Psychology 16 (1996), 235–46. 20 D. L. Costa and M. E. Kahn, ‘Energy conservation “nudges” and environmentalist ideology: evidence from a randomized residential electricity field experiment’, Journal of the European Economic Association 11(3) (2013), 680–702. 21 Fischer, ‘Feedback on household electricity consumption’. 22 M. J. J. Handgraaf, M. A. van Lidth de Jeude and K. C. Appelt, ‘Public praise vs. private pay: Effects of rewards on energy conservation in the workplace’, Ecological Economics 86 (2013), 86–92; D. Schwartz, W. Bruine de Bruin, B. Fischhoff and L. Lave, ‘Advertising energy saving programs: The potential environmental cost of emphasizing monetary savings’, Journal of Experimental Psychology: Applied 21(2) (2015), 158–66. 23 Fischer, ‘Feedback on household electricity consumption’; A. L. Davis, T. Krishnamurti, B. Fischhoff and W. Bruine de Bruin, ‘Setting a standard for electricity pilot studies’, Energy Policy 62 (2013), 401–9. 24 Cvetkovich and R. Löfstedt. Social Trust and the Management of Risk (Earthscan, 2013); M. Siegrist, T. C. Earle and H. Gutscher, Trust in Cooperative Risk Management: Uncertainty and Skepticism in the Public Mind (Earthscan, 2007). 25 S. Darby. ‘Smart metering: what potential for householder engagement?’, Building Research & Information 38(5) (2010), 442–57.

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intervention that is being tested.26 To evaluate the effectiveness of the intervention, these volunteers’ electricity savings are then compared to those of other consumers who did not volunteer to receive the intervention. Because consumers who are already more motivated to save electricity may be more likely to volunteer for an electricity-saving intervention, such comparisons are likely to inflate the estimated effectiveness of the intervention. The best tests of intervention effectiveness would randomly select participants from the entire population of consumers and randomly assign them to the intervention or a no-intervention control group. If possible, consumers should remain unaware that they are part of a study, because the mere knowledge of being enrolled can motivate people to change their behaviour. Indeed, postcards that alerted consumers that their electricity use was being studied led to 2 per cent electricity savings.27 Of course, it may be unethical to force consumers to participate in an intervention study, especially when participation introduces potential risks or costs. Regulatory mandates may require volunteer-only samples. In those situations, volunteers could be randomly assigned to an intervention or a no-intervention control group. Additionally, statistical corrections (based on expected differences between volunteers and non-volunteers) have been proposed to help adjust for volunteer bias.28 Other methodological challenges for evaluation studies involve recruiting sufficient numbers of consumers to warrant statistical tests, preventing attrition, measuring actual behaviour change rather than just self-reported preferences and testing for effectiveness over longer rather than shorter periods of time.29 LESSON 3: INTERVENTION DESIGN AND EVALUATION REQUIRES INTERDISCIPLINARY TEAMS Developing and evaluating interventions requires expertise from across a variety of domains. Energy experts are, of course, crucial for informing the technical elements of proposed interventions. Social scientists should be involved to provide evidence about what drives consumer behaviour in the context of electricity use and effective intervention design, as well as to design methodologically sound evaluation studies. Statistical expertise is needed to manage and analyse large datasets of consumer behaviour. Yet intervention teams often consist of only technical experts. While many energy experts have decades’ worth of training and experience, they may misjudge what drives consumer behaviour. Indeed, most experts no longer think 26

Davis et al., ‘Setting a standard for electricity pilot studies’. D. Schwartz, B. Fischhoff, T. Krishnamurti and F. Sowell, ‘The Hawthorne effect and energy awareness’, Proceedings of the National Academy of Sciences 110 (2013), 15242–6. 28 A. L. Davis and T. Krishnamurti, ‘The problems and solutions of predicting participation in energy efficiency programs’, Applied Energy 111 (2013), 277–87. 29 Abrahamse et al., ‘A review of intervention studies aimed at household energy conservation’; T. Krishnamurti, A. L. Davis, G. Wong-Parodi, J. Wang and C. Canfield, ‘Creating an in-home display: Experimental advice and guidelines for design’, Applied Energy 111 (2013), 277–87. 27

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like novices in their domain.30 The resulting interventions therefore may reflect their intuitions rather than the social science evidence of what motivates consumers’ behaviour. Evaluation studies may be similarly lacking, due to missing methodological or statistical expertise. Forming interdisciplinary teams can be a challenge, because experts often remain isolated in their academic silos. As a result, they have developed their own specialist terminologies, theories, methodologies and professional networks. Moreover, organisations may view external perspectives as threatening.31 The teams in which we have worked successfully have tended to include individuals who were motivated to improve a specific real-world situation, and recognised that their own expertise would not be sufficient to promote the desired improvement. In our experience, even when interdisciplinary experts do get involved, one challenge is to promote a shared understanding. Effective team work can be facilitated by defining clear intervention design goals, and sharing the best evidence of how those goals have been met in the past.32 Furthermore, it is of course important to respect each other’s expertise.33 Indeed, the resulting interventions should reflect the up-to-date scientific information from relevant disciplines, so as to optimise the likelihood of promoting residential energy savings. CONCLUSION In conclusion, we have highlighted three main lessons for designing interventions as part of delivering energy policy: (1) intervention design should be based on research with consumers; (2) interventions should be tested before their widespread implementation; (3) intervention design and evaluation requires interdisciplinary teams. More information about effective intervention design is available in ‘how-to’ guides.34 We believe that these lessons will be helpful to those who aim to promote the development of effective interventions that reduce residential electricity use and curb climate change.

30

K. Anders Ericsson, R. Th. Krampe and C. Tesch-Römer, ‘The role of deliberate practice in the acquisition of expert performance’, Psychological Review 100(3) (1993), 363–406. 31 J. LaPalombara, ‘Power and politics in organizations: public and private sector comparisons’, in M. Dierkes, A. Berthoin Antal, J. Child and I. Nonaka (eds), Handbook of Organizational Learning and Knowledge (Oxford University Press, 2001). 32 G. Wong-Parodi and B. H. Strauss, ‘Team science for science communication’, Proceedings of the National Academy of Sciences 111 (2014), 13658–63. 33 A. M. O’Donnell and S. J. Derry, ‘Cognitive processes in interdisciplinary groups: problems, possibilities’, in S. J. Derry, C. D. Schunn and M. A. Aernbacher (eds), Interdisciplinary Collaboration (Lawrence Erlbaum Associates, 2005). 34 M. G. Morgan, B. Fischhoff, A. Bostrom and C. J. Atman, Risk Communication: A Mental Models Approach (Cambridge University Press, 2002); B. Fischhoff, N. T. Brewer and J. S. Downs, Communicating Risks And Benefits: An Evidence-based User Guide (US Food and Drug Administration, 2012).

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POLICY MIXES IN STIMULATING ENERGY TRANSITIONS: THE CASE OF UK ENERGY EFFICIENCY POLICY Florian Kern1

It is widely recognised that fundamental change in energy systems is needed to address the economic (for example, volatility of fossil fuel prices), social (for example, fuel poverty), political (for example, energy security) and environmental (for example, climate change) problems associated with current systems of energy provision.2 While much of the energy policy literature (and policymaking) so far has focused on the supply side, energy efficiency is one of the key options to make energy systems more sustainable and can provide a number of benefits, including increasing energy security, contributing to economic growth and job creation, reducing fuel poverty, leading to savings in public expenditure, and reducing carbon emissions.3 As a consequence, interest in energy efficiency has grown significantly over the last few years, both in policy-making and in

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Dr Florian Kern is Co-director of the Sussex Energy Group and Senior Lecturer at the Science Policy Research Unit (SPRU). He co-convenes the MSc in Energy Policy for Sustainability. Dr Kern’s research focuses on energy, climate and innovation policy in the context of transitions towards more sustainable energy systems. His research has been published in journals such as Energy Policy, Technological Forecasting & Social Change, Policy & Politics, Policy Sciences and Environment and Planning C. Work on this chapter was enabled through the Centre on Innovation and Energy Demand which is funded by the Research Councils UK’s EUED Programme (grant number EP/KO11790/1). This funding is gratefully acknowledged. Dr Kern’s thinking in this area has been influenced by working with colleagues including Paula Kivimaa, Mari Martiskainen, Karoline Rogge and Frank Geels, whom he would like to thank for their contributions. For example, I. Scrase and G. MacKerron, Energy for the Future. A New Agenda (Palgrave Macmillan, 2009); R. Haas, J. Watson and W. Eichhammer, ‘Transitions to sustainable energy systems – Introduction to the energy policy special issue’, Energy Policy 36 (2008), 4009–11. International Energy Agency, Capturing the Multiple Benefits of Energy Efficiency (IEA/OECD Publishing, 2014).

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academia.4 This chapter will reflect on energy efficiency policy and its potential contribution to stimulating transitions towards more sustainable energy systems. It uses the case of the UK to illustrate issues of relevance for policy-makers and analysts across the European Union and the United States. This chapter builds on the literature on socio-technical transitions. Scholars in this field argue that structural rather than incremental change is needed to deal with the problems of current energy systems.5 On the basis of historical evidence they show how difficult it is to achieve significant change in dominant socio-technical regimes which are constituted of closely aligned elements including existing technologies, infrastructures, market arrangements, consumer preferences, industry structures, and policy and regulatory frameworks.6 Change in such regimes occurs as a result of developments on several levels: the idea is that pressure from the niche level, where novel socio-technical configurations are developed, and pressure from the landscape level (including macro-political and macro-economic developments) can lead to the destabilisation of regimes and may enable radical change.7 Policy recommendations drawing on this analysis have emphasised the need to support the emergence of alternative niches but also to destabilise existing regimes.8 Seen from this perspective, much of existing energy efficiency policy is narrowly focused on affecting the behaviour of consumers or on stimulating the diffusion of more efficient technologies.9 It can be argued that ambitions for energy transitions, such as those planned in Germany or the UK, require much wider changes which need to be stimulated by a variety of policy instruments.10

4

H. Du, L. Wei, M. A. Brown, Y. Wang and Z. Shi, ‘A bibliometric analysis of recent energy efficiency literatures: an expanding and shifting focus’, Energy Efficiency 6(1) (2013), 177–90. 5 J. Grin, J. Rotmans and J. Schot, Transitions to Sustainable Development. New Directions in the Study of Long Term Transformative Change (Routledge, 2010); G. Verbong and D. Loorbach, Governing the Energy Transition. Reality, Illusion or Necessity? (Routledge, 2012). 6 F. W. Geels, ‘From sectoral systems of innovation to socio-technical systems: Insights about dynamics and change from sociology and institutional theory’, Research Policy 33(6) (2004), 897–920. G. P. J. Verbong and F. W. Geels, ‘Exploring sustainability transitions in the electricity sector with socio-technical pathways’, Technological Forecasting and Social Change 77 (2010), 1214–21. 7 F. W. Geels, ‘Technological transitions as evolutionary reconfiguration processes: a multi-level perspective and a case-study’, Research Policy 31 (2002), 1257–74; A. Smith and R. Raven, ‘What is protective space? Reconsidering niches in transitions to sustainability’, Research Policy 41(6) (2012), 1025–36; J. Markard, R. Raven and B. Truffer, ‘Sustainability transitions: An emerging field of research and its prospects’, Research Policy 41 (2012), 955–67. 8 F. Kern and A. Smith, ‘Restructuring energy systems for sustainability? Energy transition policy in the Netherlands’, Energy Policy 36 (2008), 4093–103; B. Turnheim and F. Geels, ‘Regime destabilisation as the flipside of energy transitions: Lessons from the history of the British coal industry (1913–1997)’, Energy Policy 50 (2012), 35–49; P. Kivimaa and F. Kern, ‘Creative destruction or mere niche creation? Innovation policy mixes for sustainability transitions’, SPRU Electronic Working Paper Series SWPS 2015-02: 1-31 (2015). 9 S. Sorrell, ‘Reducing energy demand: An overview of issues, challenges and approaches. Renewable and Sustainable Energy Reviews 47 (2014): 74–82. 10 K. M. Weber and H. Rohracher, ‘Legitimizing research, technology and innovation policies for transformative change: Combining insights from innovation systems and multi-level perspective in a comprehensive “failures” framework’, Research Policy 41 (2012), 1037–47.

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Given that single instruments (like the EU emissions trading scheme) on their own are insufficient to achieve energy transitions, the challenge for policy-makers is one of managing a portfolio of instruments.11 Literature on policy mixes argues that interactions between different goals and instruments have an effect on the likelihood that policy goals will be achieved.12 The extent to which the current mix of UK energy efficiency policies is coherent has been a matter of discussion. For example, the Department of Energy and Climate Change (DECC)’s 2014 National Energy Efficiency Action Plan was criticised for being ‘not fully coherent’.13 However, the department is aware of this challenge and published a report entitled D3: Opportunities for Integrating Demand Side Energy Policies. It argued that there is a wide range of government programmes supporting energy efficiency and distributed energy solutions but that a lack of integration could cause policies to compete or undermine each other’s effectiveness. While the report was a step forward in acknowledging the importance of policy mixes, there are a number of concerns. Most importantly, the reframing of energy efficiency policy as part of a ‘D3 programme’ is curious. D3 stands for demand reduction, demand-side response (that is, shifting or flexing loads) and distributed energy (such as the use of PV or heat pumps). While these areas are indeed closely related and may all contribute to change in current energy systems, energy efficiency policy in a classic sense is really only concerned with the first of the Ds: demand reduction. Two interpretations are possible: either this is an example of a particularly enlightened approach to energy policy which overcomes the separation of demand and supply and adopts systems thinking; or the D3 framing potentially allows a continued focus on supply-side policies under the guise of D3, instead of tackling the difficult challenges of energy demand reduction. Personal communication with DECC civil servants suggests the latter interpretation might be more plausible as they suggested that instruments like the renewable heat incentive or feed-in tariffs are seen as part of energy efficiency policy. Another concern is the fragmentation of responsibilities and capabilities within DECC. From a socio-technical point of view, which sees consumers, producers, markets and infrastructures as closely aligned elements, the separation of policy responsibilities within DECC into a ‘consumer and households’ and a ‘markets and infrastructure’ group is not helpful. How consumers behave, at least in part, is closely related to how energy markets are designed. While DECC civil servants started to talk about the importance of a ‘sociotechnical perspective’, their understanding is a narrow one, which emphasises

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B. K. Sovacool, ‘The importance of comprehensiveness in renewable electricity and energy-efficiency policy’, Energy Policy 37(4) (2009), 1529–41. 12 P. Del Rio, ‘On evaluating success in complex policy mixes: the case of renewable energy support schemes’, Policy Sciences 47 (2014), 267–87; F. Kern and M. Howlett, ‘Implementing transition management as policy reforms: a case study of the Dutch energy sector’, Policy Sciences 42 (2009), 391–408. 13 P. Hatchwell, ‘UK’s energy efficiency plan “not fully coherent”’, ENDS Report (2014).

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the ‘usability and acceptability of new technologies and their impact on energy use’.14 While these are important issues, the challenges of transitions are much wider than that and may require choosing one of a variety of competing pathways.15 For example, the report states that there is much growth on demandside activity but that ‘large scale generation, connected at the National Grid level, is likely to remain the backbone of the UK electricity system’ which in a sense is very much a self-fulfilling prophecy if policy is designed on that basis. Other European countries (like Germany or Denmark) experiment much more with decentralised solutions.16 There also seems to be a disconnect between demand-side policies and (energy) innovation policy. Civil servants at DECC’s Energy Efficiency Deployment Office are not necessarily experts in innovation processes. There also remain doubts about what practical implications the 3D report has had so far on policy design and policy evaluations. For example, despite acknowledging that interactions between policy instruments are important, DECC so far continues to evaluate single key policy instruments instead of looking at a range of related policies and evaluating them in terms of their overall contribution to transitions.17 Overall, this experience from the UK shines a light on how difficult it is to develop policy mixes which enable transitions towards more sustainable energy systems. It also highlights that policy-makers and analysts alike are now interested in developing novel ideas to tackle these challenges and suggests that a constructive dialogue on these issues between civil servants and academics is required. While there are no ‘optimal policy mixes’,18 there is much room for improving how energy policy is geared towards stimulating energy system change.

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Personal observation from attending a DECC social research stakeholder event in November 2014. 15 T. J. Foxon, P. J. G. Pearson, S. Arapostathis, A. Carlsson-Hyslop and J. Thornton, ‘Branching points for transition pathways: assessing responses of actors to challenges on pathways to a low carbon future’, Energy Policy 52 (2013), 146–58; T. J. Foxon, Transition pathways for a UK low carbon electricity future, Energy Policy 52 (2013), 10–24. 16 F. W. Geels, G. Fuchs, F. Kern, G. Kungl, N. Hinderer, M. Neukirch and S. Wassermann, ‘Unleashing new entrants versus working with incumbents: A comparative multi-level analysis of the German and UK low-carbon electricity transitions (1990–2013)’, Draft paper submitted to Research Policy (2014). 17 As suggested in, for example, P. Kivimaa and F. Kern, ‘Creative destruction or mere niche creation? Innovation policy mixes for sustainability transitions’, SPRU Electronic Working Paper Series SWPS 2015-02: 1-31 (2015) or F. Kern, ‘Using the multi-level perspective on socio-technical transitions to assess innovation policy’, Technological Forecasting and Social Change, 79(2) (2012), 298–310. 18 S. Borrás and C. Edquist, ‘The choice of innovation policy instruments’, Technological Forecasting and Social Change 80 (2013), 1513–22.

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THE JOURNEY OF SMART METERING IN GREAT BRITAIN: A REVISIT Tao Zhang1

INTRODUCTION The journey of smart metering in Great Britain2 has lasted for almost fourteen years since the establishment of the Smart Metering Working Group on 26 April 2001. As smart metering is a popular topic in energy policy, in the past few years some prominent studies have been published to address the economic,3 policy,4 social5 and technological6 aspects of the diffusion of smart 1

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Dr Tao Zhang is Lecturer in Marketing and Sustainability at Birmingham Business School, University of Birmingham. He gained his PhD in Energy Economics from the Energy Policy Research Group, Judge Business School, University of Cambridge. His research interests are in the areas of energy economics and policy, energy consumer behaviour and innovation management, and agent-based modelling for the energy market. He is a founding member of the Environmental and Energy Economics and Management research cluster in Birmingham Business School, an associate researcher of the ESRC Energy Policy Research Group and an external advisor to the State Grid Corporation China. The United Kingdom has two energy (electricity and gas) markets: an energy market in Great Britain (Scotland, England and Wales), regulated by the Office of Gas and Electricity Markets (Ofgem), and an energy market in Northern Ireland, regulated by the Northern Ireland Authority for Utility Regulation (NIAUR). This chapter discusses the journey of smart metering in Great Britain. A. Brophy Haney, T. Jamasb and M. G. Pollitt, ‘Smart metering and electricity demand: technology, economics and international experience’, EPRG Working Paper (2009). T. Zhang and W. Nuttall, ‘Evaluating government’s policies on promoting smart metering diffusion in retail electricity markets via agent based simulation’, Journal of Product Innovation Management 28(2) (2011), 169–86. M. Martiskainen and J. Ellis, ‘The role of smart meters in encouraging behavioural change – prospects for the UK’, SPRU Working Paper, University of Sussex (2009). S. Darby, ‘The effectiveness of feedback on energy consumption: A review for Defra of the literature on metering, billing and direct displays’, Environmental Change Institute, University of Oxford (2006).

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meters. These studies proposed some issues for debate on the UK government’s policy (announced in 2009) of installing smart meters for all residential energy consumers in Britain by 2020. Most of issues centre on the market model for rolling out smart meters, smart meter ownership, energy consumers’ awareness and active demand-side participation in Britain. In the past few years we have witnessed booming marketing initiatives for promoting smart meters from energy suppliers. The number of smart meter users (both residential and nonresidential) in Britain reached 1,189,000 by 30 September 2014.7 Have the major issues proposed in previous studies been sorted out? Is the UK government’s smart metering policy effective? What is the future of smart metering in Britain? With these questions, this chapter revisits the journey of smart metering in Great Britain. SMART METERING IN GREAT BRITAIN: A BRIEF HISTORY Arguably the journey of smart metering in Britain started in 2001 with the establishment of a Smart Metering Working Group. As published in its report, the remit of this group was ‘to consider how smart metering technologies can be applied in the energy arena’.8 The group held an optimistic view and summarised some key benefits of smart metering, which triggered wide interest in smart metering from various stakeholders in the British energy market. A major impetus to the development of smart metering in Britain was the 2006 EU Energy services Directive (2006/32/EC), which highlighted the role of demand side in improving energy efficiency in the member states. In 2006 the energy market regulator in Britain, Ofgem, consulted various energy market stakeholders in Great Britain and proposed six policy options.9 Ofgem’s later report in 2006 concluded that competition is the best market model for delivering smart meters to energy consumers.10 In the 2007 Energy White Paper the UK government set out its expectation of rolling out smart meters with separate displays in Britain over the next ten years; from 2008 British energy suppliers were required to install smart meters to business energy consumers with energy consumption above a certain threshold and provide real-time display units to all residential energy consumers who requested one and where meters were replaced or newly installed.11 In April 2008, the UK government required business energy consumers with high energy consumption in Britain to have smart meters by 2013.12 In 2009, the UK government announced its policy of installing smart meters in all British homes and small businesses in by 2020, covering nearly 50 million metering points.13 The roll-out of smart meters involves three

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DECC, ‘Smart meters, Great Britain, quarterly report to end September 2014’ (2014). Ofgem, ‘Smart metering working group report’ (2001). 9 Ofgem, ‘Domestic metering innovation. Consultation document’ (1 February 2006). 10 Ofgem, ‘Domestic metering innovation – next steps. Decision document’ (30 June 2006). 11 DTI (now BERR), ‘Meeting the energy challenge: a White Paper on energy’ (May 2007). 12 BERR, ‘Impact assessment of smart metering roll out for domestic consumers and for small businesses’ (April 2008). 13 DECC, ‘Smart metering implementation programme’ (July 2010). 8

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stages: (1) policy-design stage (June 2010 to March 2011, in which necessary smart meter roll-out implementation strategies and regulatory framework were worked out); (2) foundation stage (March 2011 to December 2015); and (3) main installation stage (late 2015 to the end of 2020, by which time most energy consumers will have smart meters installed).14 The latest statistical release shows that by 30 September 2014 a total of 621,600 domestic smart meters were installed, and around 543,900 smart meters are now operating in smart mode in domestic properties in Britain.15 SMART METERING IN GREAT BRITAIN: HAVE PREVIOUS ISSUES BEEN RESOLVED? Market model Which market model is most effective for the roll-out of smart meters given the distinctive characteristics of the energy system in Britain (that is, a regulated transmission market and a liberalised retail market)? A prominent study investigated four market models and suggested that the most effective market model is for government to subsidise the roll-out and energy suppliers to deliver smart meters via competition.16 In that sense, energy suppliers do not meet the ultimate cost of smart metering. Today the reality in Britain is that the smart metering journey is very similar to the most effective market model: energy suppliers install smart meters for energy users via competition; they recover the costs of meters and required maintenance from energy bills – energy users meet the ultimate cost. This market model can foster a competitive metering market in Britain. Therefore, the market model issue has now been resolved. Meter ownership As a legacy of traditional energy systems, most of the electricity and gas meters in Great Britain are owned by distribution network operators (DNOs). DNOs charge energy suppliers for metering services and their prices are regulated by Ofgem. Since 2001 energy suppliers have been able to choose alternative meter operators, data collectors or aggregators. Energy consumers have also been able to make their own metering arrangements. Therefore in Britain a regulated market and a competitive market for metering coexist. DNOs, energy suppliers, commercial metering service companies and energy consumers can all own meters. The current UK government’s smart metering policy and the supplierled smart meter roll-out will further diversify meter ownership in Britain. One key previous concern about meter ownership is that its diversification can cause problems when energy consumers switch energy suppliers. Ofgem has created regulations to ensure meter ownership does not present an obstacle to energy consumers wishing to switch energy suppliers. Energy suppliers regard smart

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Ibid. ‘Smart meters, Great Britain, quarterly report to end September 2014’. 16 Zhang and Nuttall, ‘Evaluating government’s policies’. 15

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metering as a means for competition. They (perhaps in collaboration with commercial metering service companies) design their own innovative smart meters for the market, which must meet the minimum technical specifications required by the UK government. With the development of the competitive metering market, it is expected that more and more smart meters will be owned by energy suppliers or commercial metering service companies. Meter ownership will not be an issue hindering the smart metering journey in Britain. Consumer awareness and demand-side participation Are consumers ready (that is, is their awareness of energy efficiency sufficiently high) for smart metering? Smart meters themselves cannot save money and energy automatically. Their benefits are highly dependent on energy consumers’ awareness of energy efficiency and their active participation in demand-side management. Many previous studies examining the benefits of smart metering were based on the assumption that energy consumers have a certain level of energy efficiency awareness (usually high) and that they actively participate in demand-side management.17 However, the reality in Britain, according to uSwitch, is that 55 per cent of energy consumers are ‘in the dark’ about smart meters, that is, they do not understand what smart meters do and how they can benefit from them.18 Some observations even show that after having smart meters installed energy consumers consume more energy than before (technically known as the ‘rebound effect’).19 Currently in Britain information on smart metering for the public is disseminated primarily via the websites of the UK government, Ofgem and some other non-government organisations, and the marketing initiatives of energy suppliers. With the progress of the smart meter roll-out, it is expected that more energy consumer education/marketing campaigns will take place to increase the level of energy consumers’ awareness of energy efficiency. SMART METERING IN BRITAIN: A SUCCESS? The success of smart metering in Great Britain is reflected not only by the number of smart meters installed but also (and perhaps even more) by whether the long-term benefits of smart metering can outweigh the cost of rolling the meters out. Previous economic assessments of smart metering in Britain were based on limited data and observations from international energy markets.20 Without A. Faruqui, D. Harris and R. Hledik, ‘Unlocking the €53 billion savings from smart meters in the EU: how increasing the adoption of dynamic tariffs could make or break the EU’s smart grid investment’, Energy Policy 38(10) (2010), 6222–31; J. Torriti, M. G. Hassan and M. Leach, ‘Demand response experience in Europe: Policies, programmes and implementation’, Energy 35(4) (2010), 1575–83. 18 uSwitch, ‘Smart meters explained’ (January 2015), available at www.uswitch.com/gas-electricity/ guides/smart-meters-explained/#step3 19 EEA, Achieving Energy Efficiency Through Behaviour Change: What Does it Take? (Publications Office of the European Union, 2013). 20 DECC, ‘GB-wide smart meter roll out for the domestic sector: Impact Assessment’ (2010) London: DECC. 17

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more empirical data and observations from the energy market in Britain, it is still very early to judge whether the journey of smart metering is a success. SMART METERING: LOOKING FORWARD The journey of smart metering in Britain is now reaching the end of the foundation stage. It is anticipated that from early 2016 supplier-led, large-scale installations of smart meters will take place. The journey, however, will not be smooth. Some consumer groups (such as Stop Smart Meters UK) are running campaigns calling for smart meters to be abolished. These campaigns, based on evidence from other countries, claim that smart meters are nothing but a tax machine to take more money from people.21 They aim to raise energy consumers’ awareness of the negative effects of smart metering. Moreover, a recent YouGov survey shows that the public tend to have a pessimistic view about the smart metering journey in Britain; 62 per cent of energy consumers believe the roll-out will be delayed while 37 per cent are convinced that smart metering will benefit energy suppliers most.22 Despite these negative factors, there is an overall public desire for the benefits that smart meters will deliver. Thus it is reasonable to anticipate that smart metering in Britain will reach the end of its journey and the ultimate benefit of smart metering will outweigh the cost of the roll-out. CONCLUSION This chapter revisits the fourteen-year journey of smart metering in Great Britain, discusses the major issues proposed in previous studies and provides an outlook on the UK government’s smart metering policy. The revisit shows that Britain has made substantial progress in smart metering: a nationwide smart meter roll-out is taking place; the ‘market model’ and ‘meter ownership’ issues have been cleared; and more energy consumer education campaigns will be introduced. Evaluating the effectiveness of the UK government’s smart metering policy for a nationwide adoption of smart meters is very complicated. Many previous studies in the field were based on the scenarios/evidence of a number of years ago. Without more empirical evidence from the energy market in Britain it is still quite early to judge whether smart metering is a success. Nonetheless the revisit of the smart metering journey in Britain can provide meaningful and up-to-date information for stakeholders.

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The Canadian Press, ‘End smart meter hydro program: Ont. opposition’ (15 September 2010), available at www.cbc.ca/news/canada/toronto/end-smart-meter-hydro-program-ontopposition-1.938350 22 M. Murphy, ‘Smart Smart meters: Energy customers believe UK rollout will be delayed because “IT projects always run late”’, ComputerWorldUK (5 January 2015), available at www.computerworlduk.com/news/public-sector/3592006/smart-meters-energy-customers-believe-uk-rolloutwill-be-delayed-because-it-projects-always-run-late

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RETHINKING HOUSEHOLD ENERGY CONSUMPTION STRATEGIES: THE IMPORTANCE OF DEMAND AND EXPECTATIONS Louise Reid1

The concern around domestic energy is a dynamic and growing area of inquiry.2 In the EU28, energy consumption increased between 1990 and 2012 by 2.3 per cent, decreasing between 2005 and 2012 by 7.1 per cent (4 per cent in households).3 Yet this only tells part of the story. Consumption – the total amount of energy used – is important, but energy demand is a different concept, indicating the rate of use. In the context of domestic energy, we need to understand both of these elements and demand in particular since it tells us more about patterns of energy consumption. Further, in terms of managing our energy systems, understanding demand is critical, yet social science research on domestic energy has until recently only been concerned with consumption

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Louise Reid is currently based at the University of St Andrews in the Department of Geography and Sustainable Development, where she is also Co-director of the Centre for Housing Research. Louise moved to St Andrews from the University of Aberdeen in 2010, initially taking up a research fellowship before moving into a lectureship in 2011. Louise completed her PhD in 2010 and also has an MSc in Sustainable Rural Development (2004) and an MA (Hons) in Environmental Geography (2003). M. Hand, E. Shove and D. Southerton, ‘Home extensions in the United Kingdom: space, time, and practice’, Environment and Planning D: Society and Space 25 (2007), 668–81; T. Hargreaves, M. Nye and J. Burgess, ‘Making energy visible: a qualitative field study of how householders interact with feedback from smart energy monitors’, Energy Policy 38(10) (2010), 6111–99; D. Southerton, A. McMeekin and D. Evans, ‘International review of behaviour change initiatives: climate change behaviours research programme’, Scottish Government Social Research Publication (2011). European Environment Age+ncy (2014), ‘Final energy consumption by sector and fuel’, available at www.eea.europa.eu/data-and-maps/indicators/final-energy-consumption-by-sector-8/assessment-2

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(in part because, at least in the UK, households are billed according to total consumption rather than demand). Thus, it is clear there is much we are yet to understand about domestic energy, particularly energy demand, and how that relates to everyday domestic life. It has long been recognised that household energy demand is complex, involving factors such as building design, the increase in ownership of appliances and their intensity and use, the size of homes and, crucially, the lifestyles of those who inhabit them. Campaigns have been mobilised to increase awareness of energy, including social media campaigns, educational initiatives and competitions. Hence, ‘traditional’ behavioural change programmes have often sought to draw attention to the resource in question, in this case energy, but equally it might be water or food and drink. Commentaries between Elizabeth Shove4 and Lorraine Whitmarsh5 have come to symbolise the tensions and the incompatibility between behavioural and more recent practice approaches. These commentaries, which ostensibly surrounded how different intellectual traditions are drawn upon by policy communities to frame problems such as climate change, and how these traditions are implicated in the ‘solutions’ to such problems, reflect entrenched positions. The exchanges between Shove and Whitmarsh are helpful in drawing attention to the provenance of research approaches: (1) on behaviour, premised around understandings of the atomistic individual whose cognitive processes underlie decision-making; and (2) on practices, which consider action to be representative of the competing socially embedded rationalities of everyday life, focusing on the ‘doing’ rather than the ‘doer’. Such differences are reflected in the delivery of domestic energy policies, which have, in the UK at least, typically been predicated on behavioural approaches. The legacy of this tradition of the behavioural approach is clear to see when looking at the academic literature on technical specifications of homes, and is reflected in a preoccupation with ‘solutions’ which presume that if the environment is designed ‘correctly’, householders will behave ‘correctly’ (for example, if thermostats are introduced, householders will use less heating, or if flow limiters are fitted to showers, householders will use less hot water). Much scholarship is increasingly demonstrating that not only are ‘technical solutions’, such as alterations to building fabric, inappropriate on their own6 to increase efficiency and reduce demand, but that the whole approach towards understanding householders as atomistic (un)rational consumers is unhelpful. The evidence for this is also found when looking at the relationship between efficiency and rebound such that ‘greater efficiency has led to greater consumption’7 is conceptualised as 4

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E. Shove, ‘Beyond ABC: climate change policy and theories of social change’, Environment and Planning A 42 (2010), 1273–85. L. E. Whitmarsh, S. O’Neill and I. Lorenzoni, ‘Climate change or social change? Debate within, amongst, and beyond disciplines’, Environment and Planning A 43(2) (2011), 258–61. Z. Gill, M. Tierney, I. Pegg and N. Allan, ‘Low-energy dwellings: the contribution of behaviours to actual performance’, Building Research and Information 38(5) (2010), 491–508. L. Steg and C. Vlek, ‘Encouraging pro-environmental behaviour: an integrative review and research agenda’, Journal of Environmental Psychology 29 (2009), 309–17.

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the ‘rebound effect’.8 A further potential limitation of behavioural approaches is that longer-term ‘desirable’ changes in lifestyles may not be fostered9 and, worse, that some incentives may serve to legitimise the activities being discouraged.10 Hence, perhaps instead of concerning ourselves with energy consumption and traditional behavioural change delivery mechanisms, we need to think about this problem differently. Elizabeth Shove and Gordon Walker11 have recently provided a timely reminder that we need to be cognisant of what energy is for, and that this should be foremost when thinking about policy delivery. For instance, they highlight that energy itself is not what is demanded, but it is the services that energy provides (heat, lighting, communication) that householders are interested in. Moreover, Shove and Walker stress the social, material and historical nature of energy demand, demonstrating how our energy consumption should be thought of as an outcome of the very many ways in which we live, and the practices we adopt to do so, rather than as something significant in its own right. Importantly, this attention to the historical nature and development of energy demand suggests that current and future energy policy is based on historical patterns of use and demand, taking for granted that how we use energy and what we use energy for will remain largely similar. Accordingly, delivery mechanisms should be less concerned with resources and technologies, and instead consider those services and the related practices implicated in everyday household life. What is required, then, is for policy-makers – instead of or at least in addition to looking to improvements in technology – to understand how we live in our homes, what we do, what we do not or cannot do, and what we might want to do in the future. Expectations of particular lifestyles are an obvious place to start. What would our future lives look like? Will we work more or less? With agile working we may increasingly work at home, but to do so we will require better and more communication devices. Whilst this might also change the nature of energy demand, it may also change the amounts of energy we consume. Knowing how our domestic practices vary by time (season, frequency, duration) and place (urban, rural, household type) and why these might change is also central to such understanding. So, how we want to live in the future, and what we expect our homes to do will undoubtedly influence energy demand and whilst this may be heavily informed by existing use and infrastructure, it might not be. Accordingly, approaches such as scenario planning and forecasting, albeit in a more sophisticated way, centring around lifestyles rather than energy per se, would be a good first step to enable delivery of better policies to manage household energy demand.

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S. Sorrell, ‘The rebound effect: an assessment of the evidence for economy-wide energy savings from improved energy efficiency’, UK Energy Research Centre Report (2007), available at www. ukerc.ac.uk/Downloads/PDF/07/0710ReboundEffect/0710ReboundEffectReport.pdf 9 J. Thøgersen and B. Berit Møller, ‘Breaking car use habits: the effectiveness of a free one-month travelcard’, Transportation 35(3) (2008), 329–45. 10 U. Gneezy and A. Rustichini, ‘Pay enough or don’t pay at all’, Quarterly Journal of Economics 115(3) (2000), 791–810. 11 E. Shove and G. Walker, ‘What is energy for? social practice and energy demand’, Theory Culture & Society 31(5) (2014), 41–58.

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FINANCIAL INCENTIVES FOR ENERGYEFFICIENT APPLIANCES Souvik Datta1

The energy sector emits around 65 per cent of anthropogenic greenhouse gases2 that are now almost unanimously accepted to be the main cause of climate change. The World Energy Outlook 2009 highlights the huge potential of CO2 reductions from increased end-use energy efficiency. This has also been mentioned in other studies.3 Energy efficiency is also considered to be ‘low-hanging fruit’ due to its low marginal cost.4 The future benefits of energy efficiency exceed today’s cost of investing in energy-efficient products. While energy efficiency can be applied to the residential, manufacturing, commercial and transportation sectors, this chapter will focus on the residential sector and, specifically, the impact of financial incentives on the purchase of energy-efficient white goods. They can be implemented by federal and local governments but

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Dr Souvik Datta completed his PhD in Economics at the University of British Columbia, Vancouver in 2011 and is currently a Postdoctoral Researcher at ETH Zürich. His research interests are on issues in environmental economics, energy economics and policy evaluation, with a particular focus on empirical analysis, for example analysing the cost-effectiveness of energy-efficiency programmes, estimating the price responsiveness of electricity demand and the environmental impact of a luxury tax on automobiles. International Energy Agency, ‘How the energy sector can deliver on a climate agreement in Copenhagen’ (2009), available at www.iea.org/publications/freepublications/publication/climate_change_excerpt.pdf J. Creyts, A. Derkach, S. Nyquist, K. Ostrowski and J. Stephenson, ‘Reducing US greenhouse gas emissions: how much at what cost?’, Technical Report (2007); H. Choi Granade, J. Creyts, A. Derkach, P. Farese, S. Nyquist and K. Ostrowski, ‘Unlocking energy efficiency in the US economy’, Technical Report (2009); T. Nauclér and P.-A. Enkvist, ‘Pathways to a low-carbon economy: Version 2 of the global greenhouse gas abatement cost curve’, Technical Report (2009). Marginal cost is the additional cost of engaging in one more unit of a particular activity.

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are usually a part of demand-side management (DSM) initiatives undertaken by utility companies.5 Adopting energy-efficient appliances has public (for example, reduced greenhouse gas emissions, other criteria air pollutants and use of other resources) and private (savings in utility bills) benefits. For example, the lifetime cost for washing machines using the product database from 2007 was $1,883 for a standard model and $1,726 for an energy-efficient ENERGY STAR model.6 While consumers benefit in terms of lower utility bills, there are reasons why utility companies promote energy-efficient appliances. The literature on DSM mentions that promoting energy efficiency costs less than building new power plants. There are also environmental reasons since utility companies need to follow environmental regulations. There are emission control strategies in place and saving electricity on the margin will allow the more polluting generators to be removed from producing electricity. The need to upgrade transmission and distribution networks can be reduced by decreasing electricity demand. Finally, grid reliability can be improved through a combination of reducing peak demand and electricity demand. If the private savings appear to be so clear why do consumers fail to make energy-saving investments for which the benefits exceed the cost? This observation about the slow diffusion of energy-efficient products has been referred to as the ‘energy efficiency gap’ or ‘energy efficiency paradox’. Several reasons have been put forward to explain this observation. They may arise from market failures that occur when goods and services are not allocated efficiently, for example (1) environmental effects not being internalised by the market system; (2) energy resources, like electricity, not being priced correctly; (3) lack of information, for example the absence of information on the amount of energy used by a particular appliance; (4) principal-agent problems, for example, the landlord and the tenant not investing in energy-efficient products because neither reaps the full benefits of that investment; and (5) liquidity constraints, for example low-income households being unable to borrow due to their low credit score. There has also been recent work about the effect of behavioural anomalies on the energy efficiency gap.7

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DSM refers to the ‘planning, implementation, and monitoring of utility activities designed to encourage consumers to modify patterns of electricity usage, including the timing and level of electricity demand’ (Energy Information Administration, Electric Power Annual 2007, 2009). These measures were initiated in the late 1970s primarily due to rising gas and oil prices. See J. Eto, ‘The past, present, and future of US utility demand-side management programs’, Technical Report, LBNL–39931, Lawrence Berkeley National Lab. (1996); S. Nadel and H. Geller, ‘Utility DSM. What have we learned? Where are we going?’, Energy Policy 24(4) (1996), 289–302 and S. Nadel, Utility Energy Efficiency Programs: A Brief Synopsis of Past and Present Efforts (American Council for an Energy-Efficient Economy, 2000) for a history of utility DSM programmes in the US. Calculations made by D&R International Ltd. ENERGY STAR is a voluntary eco-labelling programme introduced in 1992 by the United States Environmental Protection Agency (EPA) to promote the use of energy-efficient products. See K. Gillingham and K. Palmer, ‘Bridging the energy efficiency gap: Policy insights from economic theory and empirical evidence’, Review of Environmental Economics and Policy (2014) for a recent review of the energy efficiency gap.

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To overcome these barriers to promoting energy efficiency there are, primarily, three types of policies: information strategies, economic incentives and energy efficiency standards. In this chapter I focus on economic incentives. Revelt and Train consider the residential customers of a US electric utility company, Southern California Edison, and estimate the impact of rebates and loans on the choice of efficiency of refrigerators. They find that while the rebate programme leads 8.5 per cent of customers to switch to a high-efficiency refrigerator from a standard-efficiency one, loan programmes have a greater impact, with 22.6 per cent of buyers switching.8 In a similar paper, Train and Atherton find that attractive loans with, for example, low interest rates or long repayment periods are necessary to have the same effect as rebates and that offering customers the option of loans or rebates is more effective than programmes offering loans or rebates exclusively.9 Recently, there has been an upsurge in research on the efficacy of financial incentives on the purchasing decision of energy-efficient household appliances. Markandya et al. find that tax credits on boilers appear to be a cost-effective option in Denmark and Italy, while subsidies on compact fluorescent lamp bulbs in France and Poland are also cost-effective in terms of the cost per tonne of CO2 abated. They also find that subsidies are, in general, less cost-effective than an energy tax. They conclude that while incentives to promote the use of energy-efficient appliances can be cost-effective, results depend on the particular country and the policy options.10 Using a large-scale programme in Mexico that replaces households’ old refrigerators and air conditioners with energy-efficient models, Davis et al. find that refrigerator replacement reduces electricity consumption by 8 per cent and air conditioning replacement actually increases electricity consumption. They conclude that the programme reduces CO2 emissions at a cost of over $500 per tonne and is not cost-effective.11 Datta and Gulati analyse rebates for ENERGY STAR washing machines, refrigerators and dishwashers and find that rebates raise the share of ENERGY STAR washing machines but do not appear to affect dishwasher and refrigerator shares. They estimate the cost per tonne of carbon saved to be about $140 for the washing machines rebate programme while the cost of a megawatt hour saved, about $28, is lower than the estimated cost of building and operating an additional power plant and the average on-peak spot price. This makes

8

D. Revelt and K. Train, ‘Mixed logit with repeated choices: households’ choices of appliance efficiency level’, Review of Economics and Statistics 80(4) (1998), 647–57. 9 K. Train and T. Atherton, ‘Rebates, loans, and customers’ choice of appliance efficiency level: Combining stated and revealed-preference data’, The Energy Journal 16(1) (1995), 55–69. 10 A. Markandya, R. Arigoni Ortiz, S. Mudgal and B. Tinetti, ‘Analysis of tax incentives for energyefficient durables in the EU’, Energy Policy 37(12) (2009), 5662–74. 11 L. W. Davis, A. Fuchs and P. Gertler, ‘Cash for coolers: evaluating a large-scale appliance replacement program in Mexico’, American Economic Journal: Economic Policy 6(4) (2014), 207–38.

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the ENERGY STAR washing machines rebate programme, on average, a costeffective way for utilities to reduce electricity demand.12 Galarraga et al. analyse a rebate, a tax and a combination of the two for the dishwasher market in Spain. They find that, under the ‘Renove’ programme, an €80 rebate on both the energy-efficient labelled and non-labelled dishwasher markets increases the total number of dishwashers by 1.4–1.97 per cent while a tax of €40 levied on non-efficient dishwashers decreases the total number of appliances by 1.42–1.99 per cent. They conclude that the tax scheme is a better policy instrument than the subsidy scheme in promoting energy efficiency and advocate a combination of the two to improve energy policy.13 Boomhower and Davis find that participation in a large-scale residential energy-efficiency programme increases with larger subsidy amounts but that most households would have participated even with much lower subsidy amounts thereby making the large subsidies not cost-effective. They also find that about half of all participants would have adopted the energy-efficient technology even without a subsidy.14 Houde and Aldy evaluate the State Energy Efficient Appliance Rebate Program in the US and estimate the incremental impact of energy-efficiency rebates on refrigerators, washing machines and dishwashers in the presence of regulatory and information schemes. They find that, after accounting for purchases that would have been made even without the rebates, the cost-effectiveness ranges from $44 to $146 per MWh saved, which is higher than the average cost-effectiveness for utility-sponsored programmes. They note that the presence of multiple pre-existing instruments may undermine the efficacy and increase the cost of a new policy instrument.15 Analyses of the impact of financial incentive programmes on the uptake of energy-efficient appliances need to take into account the participation of individuals, known in the economics literature as free riders, who would have purchased an energy-efficient appliance even without the incentive. Another concern is that of a ‘rebound effect’. This could happen when the purchase of a more energy-efficient appliance lowers the cost of use and encourages

12

S. Datta and S. Gulati, ‘Utility rebates for ENERGY STAR appliances: Are they effective?’, Journal of Environmental Economics and Management 68(3) (2014), 480–506. See S. Datta and M. Filippini, ‘Analysing the impact of ENERGY STAR rebate policies in the US’, Energy Efficiency (forthcoming) for a related paper, available at http://dx.doi.org/10.1007/s12053015-9386-7 13 I. Galarraga, L. M. Abadie and A. Ansuategi, ‘Efficiency, effectiveness and implementation feasibility of energy efficiency rebates: The “Renove” plan in Spain’, Energy Economics 40 (2013), S98–S107. 14 J. Boomhower and L. W. Davis, ‘A credible approach for measuring inframarginal participation in energy efficiency programs’, Journal of Public Economics 113 (2014), 67–79. 15 S. Houde and J. E. Aldy, ‘Belt and suspenders and more: the incremental impact of energy efficiency subsidies in the presence of existing policy instruments’. NBER Working Paper Series, National Bureau of Economic Research (2014).

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a higher use of energy, thereby reducing the overall energy saved.16 Freeriding and the rebound effect will increase the cost of financial incentive programmes and, therefore, need to be taken into account when evaluating such programmes. There are relatively few papers that have evaluated the impact of financial incentives on the purchase of white goods and analysed its cost-effectiveness. This is, I believe, an area of research that should be on the agenda of researchers since the evidence is not very conclusive and it is important to resolve the argument about the benefits or costs and direct policy-makers on the appropriate choice of policy instrument or mix of policy instruments.

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The rebound effect can be direct or indirect. Direct rebound effect refers to the situation in which the purchase of an energy-efficient appliance leads to more use of the appliance, thus partially cancelling out the energy saved. Indirect rebound effect leads to the energy saving being offset by more energy usage in another activity. The literature on the rebound effect provides no consensus on the degree of rebound observed. While there are numerous studies, the interested reader may refer to a special issue on the rebound effect in Energy Policy 28 (June 2000) for a more detailed discussion.

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ENERGY SECURITY AND ENERGY POLICY INCOHERENCE Hugh Dyer1

The pursuit of energy security is a significant factor in the incoherence of energy policy. This is due in part to incoherence in the concept of energy security itself,2 as well as to the competing and sometimes contradictory demands made of energy policy. Understood simply as the availability of adequate energy at an acceptable price, energy security does not challenge a purely economic understanding of energy policy in the context of global markets. However, the more diverse political and social dimensions of energy security present a considerable challenge to both the objectives and implementation of coherent energy policy, at the levels of both structure and agency. As a corollary of social and economic choices, energy policy is one of the most important strategic issues facing governments. However, and particularly in respect of security and environmental dimensions, the relatively poor state of coordinated planning is often noted. This illustrates the more general absence of overall coherence in energy policy, as most choices are left to the market in a limited vision of the structures and agencies at work, and this reliance on markets rather than policy planning is a source of incoherence given the divergent priorities. Energy policy is typically presented as an issue of supply to which policy is expected to respond by providing secure access in the service of national economies. Broader social distributional issues may of course place 1

2

Hugh Dyer is Associate Professor of World Politics in the School of Politics and International Studies at the University of Leeds. His recent work includes the monograph Coping and Conformity in World Politics (Routledge, 2012), a co-edited volume International Handbook of Energy Security (Edward Elgar Publishing, 2013) and an article ‘Climate anarchy: Creative disorder in world politics’ in International Political Sociology 8(2) (2014). H. Dyer and M. J. Trombetta (eds), International Handbook of Energy Security (Edward Elgar Publishing, 2013).

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political limitations on unfettered market distributions, which can be addressed nationally as a matter of policy, and could be extended transnationally where there is political-economic integration (as in the European Union, and to a much lesser extent in free trade areas such as the North American Free Trade Agreement) or even potentially where there is only general interdependence (as in the globalised political economy), though such advanced levels of cooperation still seem challenging. Hence the structure of ‘state sovereignty’ and national authority mechanisms may also determine the current distribution of energy as much as markets, with implications for consumer and producer agency. Incoherence is compounded by the diverse range of issues closely linked to energy, in particular both development and sustainability. In pointing to these interconnected issues it has been noted that ‘in the future energy security will be almost as important as defence to our national security’, but with simultaneous and ‘ambitious goals for climate security and international development’ suggesting that ‘an aggressively single-minded pursuit of energy security will compromise these other goals’.3 DIMENSIONS OF ENERGY POLICY The International Energy Agency’s World Energy Outlook 20144 refers to energy efficiency gaps being closed through competitiveness, though it is less concerned about reducing demand than about meeting growing demand with greater economic efficiency. It notes the phasing-out of nuclear power (in reference to Germany), and the concern that the global carbon budget (with regard to limiting global warming) may soon be exhausted. It also notes that socioeconomic development in sub-Saharan Africa will depend on access to modern energy services. All of these concerns are presented in terms of market solutions, rather than energy policy interventions. This reflects a shared conventional assumption that energy supply should be stabilised to avoid endangering livelihoods and the global political economy, which in itself is not controversial, and yet relying on markets to manage supply and price in the short term is probably not a reasonable approach to energy policy (if it is a policy choice at all) in view of long-term objectives of energy security. At an international level, relations between producers and consumers involve both cooperation and nationalist concerns to reduce mutual dependence, driven by the imbalances between energy demand and ownership of resources.5 For example, European ambitions for energy supply interconnection infrastructure 3

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Oxford High-Level Task Force on UK Energy Security, Climate Change and Development Assistance, ‘Energy, politics and poverty: a strategy for energy security, climate change and development assistance’ (2007), available at www.fanrpan.org/documents/d00349/Energy_politics_GEGP_Jun2007.pdf International Energy Agency, ‘World Energy Outlook 2014’, available at www.worldenergyoutlook.org/publications/weo-2014 E. Kirchner and C. Berk, ‘European energy security co-operation: between amity and enmity’, Journal of Common Market Studies 48(4) (2010), 859–80; A. Goldthau, A Liberal Actor in a Realist World: The EU Regulatory State and the Global Political Economy of Energy (Oxford University Press, 2015).

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reflect a common purpose across the three pillars of EU energy policy (sustainability, competitiveness and security), and yet benefits to national energy security in terms of resilience may be offset against unwanted levels of interdependence. If energy policy is thus partly determined by geography (and geopolitics is a traditional perspective on energy), it should be noted that the underlying energy landscape is also changing for technical and political reasons; a global economy may ‘shrink’ the world, yet some features are recalcitrant – for example, gas markets of the Pacific and Atlantic basins are rather different. Energy markets thus involve not just the global economy but also global governance in managing future supply and demand, and diversification of both. Renewable energy technologies figure highly in energy policy considerations, if some show greater potential than others, and certainly a more decentralised energy structure based on renewables could enhance energy security. For policy to promote a sustainable energy system and social welfare the externalities of energy technologies must be identified and internalised in the costs and choices of energy, however, in terms of structure and agency, policy intentions in themselves may not determine social outcomes. Lipschutz and Mulvaney note that various socio-technical systems, such as electrification, have different path-dependent effects on human well-being and security.6 Thus public policy debate, regulatory intervention, as well as consumer activism may be needed to reorient energy interests towards sustainability. New technological developments and policy aspirations for a ‘green’ or low-carbon economy may yet enhance the sense of security in respect of energy and its corollaries in our societies and economies, but this is likely to require considerable political-economic restructuring and rethinking of political agency. As Winzer observes, while ‘energy security’ is an important aspect of energy policy, ‘the term has not been clearly defined, which makes it hard to measure and difficult to balance against other policy objectives’.7 Barnett argues that energy security is simply ‘the use of national power to secure supplies of affordable energy’ in support of national economic growth.8 The European context illustrates the tension between economic marketoriented understandings of energy security and more political understandings that generate differences in national interest and identity, while at the same time Goldthau and Sitter characterise EU-level energy governance as exporting a liberal economic approach, in terms of regulatory norms and market rules, to other countries.9 In the United States, energy security most obviously relates 6

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R. D. Lipschutz and D. Mulvaney, ‘The road not taken, round ii: centralized vs. distributed energy strategies and human security’, in H. Dyer and M. J. Trombetta (eds), International Handbook of Energy Security (Edward Elgar Publishing, 2013). C. Winzer, ‘Conceptualizing energy security’, EPRG Working Paper 1123, University of Cambridge (2011), available at www.eprg.group.cam.ac.uk/wp-content/uploads/2011/08/EPRG1123_ complete.pdf J. Barnett, The Meaning of Environmental Security: Ecological Politics and Policy in the New Security Era. (Zed Books, 2001), p. 35. A. Goldthau and N. Sitter, ‘The power of paradigms: The EU and global energy policy’, Social Science Research Network Working Paper (2012), available at http://dx.doi.org/10.2139/ssrn.1986832

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to national self-sufficiency in supply, rather than reduced consumption, but market forces still prevail (and often weirdly so, since the stock prices of solar firms seem to go up and down with the price of oil, even though solar PV substitutes for non-petroleum electricity sources). Energy security remains broadly about meeting demand at a politically acceptable price, rather than reducing demand or diversifying supply into renewables, and in particular thus reducing carbon intensity, in spite of some obvious win-win efficiencies to be had. This is perhaps easier to explain if energy security is understood as a linguistic expression of vulnerability and threat influencing apparently pragmatic policy choices, through securitisation.10 Energy security thus influences energy policy directly and indirectly: even understood from a limited economic perspective the global energy system may struggle to meet the rising demands of a growing and developing global population, while a wider interpretation of energy security raises a variety of longerterm issues which have not yet been reflected in strategic planning, with the unsurprising consequence of overall incoherence in energy policy.11 The problem of energy policy incoherence is not of course restricted to the mature democracies and developed political economies of Europe and North America,12 but appears to be nearly universal, if in somewhat different guises.13 Thus, in a variety of structural contexts, agents may deploy energy security discourses instrumentally in ways which undermine coherence of energy policy.14 For example, in the UK, policy incoherence has energy security concerns pulling energy policy in the opposite direction to decarbonisation (e.g. developing shale gas, especially if north sea production is reduced), as an economic understanding of energy security limits planning. The policy statements emphasise energy prices and liberalised energy markets (with some reference to physical risks), while conceding 10

T. Balzacq, ‘The three faces of securitization: political agency, audience and context’, European Journal of International Relations 11(2) (2005), 171–201. 11 A. Goldthau, The Global Energy Challenge. Environment, Development and Security (Palgrave Macmillan, 2015). 12 D. MacShane, ‘Europe’s energy policy: just say no’, The Independent (27 May 2014), available at www.independent.co.uk/voices/comment/europes-energy-policy-just-say-no-9440936.html; B. Johnson, ‘“Energy independence” will destroy the planet: U.S. politicians are fooling themselves on climate change’, New Republic (15 September 2015), available at www.newrepublic.com/ article/119449/politicians-want-both-energy-independence-and-stop-global-warming; Centre for International Governance Innovation, ‘Does Canada’s current energy policy make sense?’ (2014), available at www.cigionline.org/blogs/front-row/does-canadas-current-energy-policy-make-sense; Green Party, ‘Government’s energy policy is “incoherent and irresponsible”’ (2014), available at www.greenparty.org.uk/news/2014/11/20/green-party-government%E2%80%99s-energy-policy -is-%E2%80%98incoherent-and-irresponsible%E2%80%99; C. Crook, ‘More on Germany’s energy incoherence’, available at http://blogs.ft.com/crookblog/2011/06/more-on-germanys-energy -incoherence/#axzz3OnVUeTF5 13 I. Okonta, ‘Nigeria: policy incoherence and the challenge of energy security’, in Andreas Goldthau (ed.). The Handbook of Global Energy Policy (Wiley, 2013) . 14 I. Fischhendler and D. Nathan, ‘In the name of energy security: the struggle over the exportation of Israeli natural gas’, Energy Policy 70 (2014), 152–62.

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the need for considerable change to meet low-carbon objectives, and the main areas of action are thus concerned with electricity market reform and ‘barriers to competitive markets’.15 At the time of writing, low oil prices (due to largely to politically motivated over-production) may favour the conventional short-term energy security calculation for consumers, in terms of supply at an acceptable price, while also creating insecurity for over-reliant producers. However, this may also reduce the impetus to diversify into renewable energy sources and invest in more efficient infrastructures, and as always price fluctuations can have corrupting economic consequences. It is a short-term illustration of the long-term insecurities arising from incoherent planning for a different energy future.

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United Kingdom, ‘Energy strategy 2012 to 2015’, available at www.gov.uk/government/publications/energy-strategy-2012-to-2015; ‘Maintaining UK energy security’, available at www.gov.uk/ government/policies/maintaining-uk-energy-security--2

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DESIGNING INTERNATIONAL TRADE IN ENERGY GOVERNANCE FOR EU ENERGY SECURITY Rafael Leal-Arcas1

INTRODUCTION: WHAT IS THE PROBLEM? Energy security is one of the main problems that humanity faces today and the European Union has to rely on energy-rich countries for its energy needs. The European Innovation Union, the Energy Community and the Europe 2020 initiative address energy security as a priority, but policies seem to be reactive instead of addressing energy security in its complexity. This problem can be solved with appropriate legal tools. Energy governance has links with several policies: trade, investment, environmental protection, energy transit, energy security, finance and so on. Of these policies, energy trade has a high impact for European energy security policy. Currently, the international community does not address trade in energy as a cohesive entity and its governance is fragmented. 1

Professor Dr Rafael Leal-Arcas is Professor of European and International Economic Law at the Centre for Commercial Law Studies, Queen Mary University of London. He has a PhD (European University Institute, Florence), a JSM (Stanford Law School), an LLM (Columbia Law School), an MPhil (London School of Economics and Political Science), and a BA and LLB (Granada University), and is a 2015 Research Fellow at the Energy Community Secretariat. Professor Dr Leal-Arcas is a member of the Madrid Bar and author of the books Energy Security, Trade and the EU: Regional and International Perspectives (Edward Elgar Publishing, 2016); The European Energy Union (Claeys & Casteels Publishing, 2016); International Energy Governance: Selected Legal Issues (Edward Elgar Publishing, 2014); Climate Change And International Trade (Edward Elgar Publishing, 2013); International Trade And Investment Law: Multilateral, Regional And Bilateral Governance (Edward Elgar Publishing, 2010) and Theory And Practice of EC External Trade Law and Policy (Cameron May, 2008). He is editor-in-chief of Renewable Energy Law and Policy Review.

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Therefore, it is necessary to develop effective trade policy instruments for EU energy security to identify the existing gaps in energy trade governance. Thus the idea is to develop a concept of ‘governance by design’ through the interplay of various legal regimes and institutions, with the ultimate aim of facilitating the creation of the planned European energy union. The aim is to achieve affordable, secure and sustainable energy. This energy union is based on five pillars: security, solidarity and trust; the completion of a competitive internal market; moderation of demand; the decarbonisation of the EU energy mix (that is, greater use of renewable energy); and technologies. The EU is the first region in the world to set up the ambitious target of decarbonising its economy by 2050. All of this could be reproduced in other regions of the world and eventually create a new international energy order. This requires a fresh and comprehensive approach to legal instruments. To do that, some fundamental questions need to be answered: 1. How does current energy trade governance affect EU energy security? 2. How should the international trade in energy system be adapted to ensure EU energy security? 3. How can the EU diversify its energy supply to improve EU energy security? 4. How can the EU’s preferential trade agreements facilitate renewable energy for the EU? INTERNATIONAL TRADE IN ENERGY GOVERNANCE Currently, there is no cohesive governance for global energy trade. On the contrary, governance of energy trade arises by default, rather than design, through the ad hoc interplay of different aspects of the international economic system.2 This has implications for the EU, which relies heavily on the rest of the world for its energy supply and, consequently, its energy security. The governance regime for energy trade is not conducive to EU energy security because of the fragmentation of the global and European energy trade regimes, the lack of cohesiveness of the global and European energy trade systems, divergent national interests, and the diversity of energy sources.3 It is vital that the EU take the right steps and decisions to ensure a more secure, clean, competitive and sustainable energy system. At the global level, a more cohesive global governance system for energy trade would facilitate energy flows, avoid unnecessary legal disputes and provide predictability. Achieving this will require a thorough understanding of the elements, workings and evolution of the current global energy trade governance regime and its consequences for European energy security.

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A Florini and B. K. Sovacool, ‘Who governs energy? The challenges facing global energy governance’, Energy Policy 37(12) (2009), 5239–48. R. Leal-Arcas and A. Filis, ‘Conceptualizing EU energy security through an EU constitutional law perspective’, Fordham International Law Journal 36(5) (2013), 1225–301.

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Energy trade is a key component of both the global and EU economies, and international trade in energy spans a number of policy areas, including trade, investment, economic development, and environmental protection (see Figure 89.1). The very nature of energy – namely its centrality to almost every field of human endeavour – and the very nature of traditional energy resources – namely finiteness, uneven distribution and high desirability – lead to the politicisation of energy and encourage intense competition for control over energy resources between actors.4 While energy supply and consumption are important aspects of the global and EU energy economy, they do not exist in an equilibrious relationship. Rather, they are heavily mediated by political considerations and by the very operation of global markets, which dictate the extent to which energy needs are ultimately met. The dominant opinion is that trade liberalisation will increase economic activity and therefore energy consumption. All countries require energy resources, but few possess them, and thus trade in energy (primarily oil and gas) is crucial to fulfil global energy needs. Internationally, there is more trade in oil than in anything else. ‘Fully half of world trade in services is intensely energy-dependent.’5 Yet the General Agreement on Tariffs and Trade (GATT)/ World Trade Organization (WTO) has historically not preoccupied itself with

Figure 89.1 The various aspects of energy governance 4

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P. Andrews-Speed (ed.), International Competition for Resources: The Role of the Law, the State, and of Markets (Dundee University Press, 2008); N Schrijver, Sovereignty over Natural Resources: Balancing Rights and Duties (Cambridge University Press, 1997); A. Wenger, R. W. Orttung and J. Perovic (eds), Energy and the Transformation of International Relations (Oxford University Press, 2009). J. Gault, ‘A world of introduction from the energy industry perspective’, in J. Pauwelyn (ed.), Global Challenges at the Intersection of Trade, Energy and the Environment (The Graduate Institute, 2010), p. 9.

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energy trade. Very few energy-rich countries saw a need to join the GATT/ WTO club, given that the reduction of import restrictions – one of the main goals of the multilateral trading system – is not an issue when it comes to energy. Saudi Arabia, the main energy-producing country in the world, only joined the WTO in 2005 and many energy-producing countries are still not WTO members. This chapter challenges the dominant assumptions of the energy trade system in its capacity to address EU energy security. Despite apparent overlaps between institutions and regimes involved in energy trade governance, there are significant gaps in the system. The result is a mixed bag of incidental outcomes arising from an array of disjointed energy-related institutions and processes operating at various scales (bilateral, regional and so on), often each with its own selective membership. SOVEREIGNTY OVER NATURAL RESOURCES Energy is one of the biggest challenges facing the EU today. With very few energy reserves of its own, the EU currently imports over half its energy, making it extremely reliant on the rest of the world for its energy supply. It is in the EU’s interest to diversify its energy sources and supply channels, and also increase energy efficiency by promoting more sustainable practices and greater energy market integration. In fact, we see efforts in those directions through the promotion of the Internal Energy Market and the Energy Community. Trade policy and regulation can be instrumental in achieving these goals. For example, there is potential to incorporate energy-efficient provisions within regional and multilateral agreements; there are trade incentives to better manage competition and invest in technologies such as up-to-date energy grids, and possibilities for exporting cutting-edge EU technologies through the EU’s trade and bilateral cooperation agreements. EU energy security depends upon institutionalised energy-related internal as well as international cooperation. For instance, effective systems for energy trade and energy transit arguably enhance energy security for those economies involved in such cooperation. At the domestic level, a single agent – namely the state – is the authority that adopts measures towards the energy security of the territory/ economy that it controls. Such an agent is not omnipotent in its attempts towards energy security, given that energy security often relies on factors – for example, energy commodities’ price and availability – over which it has little or no control. At the EU level, there are numerous actors who have influence over the energy economy, including EU and member state bodies. This plurality of actors and the variety of interests at play – for example, interests across the national-regionaluniversal spectrum, the public-private spectrum and the policy spectrum – mean that the achievement of EU energy security is a considerably complex challenge. While all sovereign actors/economies have an interest in their respective energy security, global energy security is essentially a concern to none. In that sense, it is not a common concern as is the case of climate change.6 6

R. Leal-Arcas, Climate Change and International Trade (Edward Elgar Publishing, 2013).

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At the international level, the EU is one of a patchwork of institutions that may have implications for cross-border energy trade. While the EU lacks the powers of a sovereign actor to diplomatically pursue its energy security in the manner that China or the US may, it does possess a comprehensive energy policy that is multifaceted and that makes good use of the powers that lie within its competences. The WTO also provides governance over trade within its scope, including over energy trade. The WTO does not handle energy commodities any differently from other tradable commodities within its scope. In that sense, it provides energy trade governance by default. Another example is the Energy Charter Treaty (ECT), whose principal concerns surround the investment protection and trade aspects of energy between contracting states.7 Many other institutions exist that provide degrees of governance over aspects of trade in energy at the inter-state level. This patchwork of institutions and regimes amounts to a sort of ‘accidental’ energy trade governance, and presents some areas of overlap. For instance, both the WTO and the ECT have rules that apply to the trade, investment and environmental-protection aspects of energy. These overlaps in no way amount to cohesive governance of energy trade. FUTURE CHALLENGES Without a deep understanding of the current systemic aspects of energy trade governance and their implications for EU energy security, it is impossible to achieve effective change. Our world faces two major challenges when it comes to energy. For one thing, one person in five on the planet still lacks access to electricity, and almost three billion people still use wood, coal, charcoal or animal waste for cooking and heating. The other main global energy challenge is that, in places with access to modern energy services, the lion’s share of energy usage stems from fossil fuels. A fuller understanding of the link between energy trade governance and EU energy security is necessary to propose reforms.

7

T. Wälde, The Energy Charter Treaty: An East-West Gateway for Investment and Trade (Kluwer Law International, 1996).

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NATO AND EUROPEAN ENERGY SECURITY Behrooz Abdolvand1 and Konstantin Winter2

INTRODUCTION With the Russian-Ukrainian conflicts of 2006 and 2009, and the civil war of 2014, threats to the security of energy supply have reached a new dimension for European countries and European Union member states. Even though Russia has been a reliable supplier of fossil fuels to Western Europe, the fear of Russia politicising its strong geopolitical position as an energy supplier persists – especially among the highly dependent Baltics, the Visegrad Group3 and the Balkans. This dependence in combination with expansionist behaviour has alarmed the EU, and these energy security concerns echo across the Atlantic. Washington is aware that one of the most critical US security challenges lies in Eurasian energy politics. It is therefore vital that the North Atlantic Treaty Organization (NATO) intensifies its energy security efforts. European-Russian energy relations had developed gradually since the 1960s into a relationship of mutual dependence. European countries supplied the technical and financial means to exploit the vast Siberian reserves, while the Soviet energy sector grew to become the most important pillar of its national 1

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Dr Behrooz Abdolvand has been a Lecturer in International Relations and Energy Policy at the Otto-Suhr-Institute of the Freie Universität Berlin since 1998, where he is the coordinator of the graduate school programme ‘Caspian Region Environmental and Energy Studies’ (CREES). Since 2002 he has worked as a consultant in the energy sector, and since 2013 has been Associate Fellow at the German Council on Foreign Relations (DGAP). Konstantin Winter was awarded an MA in Political Sciences at the Freie Universität Berlin. He wrote his thesis on the dimensions of German natural gas supply security. He has been a Research Assistant at the Berlin Centre for Caspian Region Studies (BC CARE) since 2011, and has published several articles regarding security and energy policy in Central Asia and the Caspian Sea region. The Visegard Group consists of the Czech Republic, Hungary, Poland and Slovakia.

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economy. With the dissolution of the Soviet Union, President Boris Yeltsin (1991–9) attempted to privatise the greatest part of the state-monopolistic energy industries. The energy sector became open to foreign investment and Russia signed Production Sharing Agreements (PSA) with large international companies in order to stimulate foreign investment in technologically complex projects. Under Vladimir Putin’s presidency, the Russian government then reasserted state control over the energy sector and reemphasised not just the sector’s economic importance as the most valuable area of commerce but also its strategic importance in Russia’s foreign policy agenda. The state-owned companies Rosneft and Gazprom were systematically built up to become international heavyweights. In addition, the government restricted foreign influence in domestic hydrocarbon projects, with the result that PSAs were no longer a viable method of foreign investment in the Russian energy sector.4 Disagreements over gas prices between Russia and Ukraine led to various incidents concerning supply to the European downstream market.5 Ukraine’s location and its vast Soviet-era transit infrastructure make it an essential link in the Eurasian gas value chain. Between 2010 and 2015, Gazprom transited an annual average of 94 billion cubic metres6 of gas through Ukraine to Europe.7 During the gas crises of 2006 and 2009, Russia cut gas supplies to Ukraine and stalled the flow of gas to south-east Europe, which made governments on both sides of the Atlantic doubt Russia’s reliability.8 The view that Russia regards energy as an important means of projecting its political power and influence internationally became ever more present.9 INSTITUTIONAL ENERGY SECURITY: ‘ENERGY NATO’ OR ‘ENERGY OSCE’ In order to gain sovereignty over its energy supply, Europe has to be able to control energy systems by economic, technical, political and even military means. Reliability of energy supply can be enhanced by energy diplomacy, by securing sufficient spare production and storage capacity and by strategic reserves, but especially by diversification of supply sources and transportation routes, which reduces the impact of a disruption in supply from one source by providing 4

5

6 7

8

9

T. F. Krysiek, Agreements from Another Era – Production Sharing Agreements in Putin’s Russia, 2000–2007, WP 34, Oxford Institute for Energy Studies (November 2007). A. Goldthau, The Geopolitics of Natural Gas – The Politics of Natural Gas Development in the European Union, Havard University’s Belfer Center and Rice University’s Baker Institute Center for Energy Studies (October 2013), p. 14. However, as much as 110–12 billion cubic metres were contractually stipulated. Naftogaz, ‘Naftogaz initiates arbitration procedure regarding transit contracts with Gazprom to ensure stability of gas transit to EU’, Naftogaz (21 October 2014), available at www.naftogaz. com/www/3/nakweben.nsf/0/DA5433A36F4A9C01C2257D780036DD5F J. Stern, The New Security Environment for European Gas: Worsening Geopolitics and Increasing Global Competition for LNG, NG 15, Oxford Institute for Energy Studies (October 2006), p. 3. Ibid., p. 4.

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alternatives.10 Further, it is the supranational and national government’s task to cooperate in promoting high-quality and timely information as well as developing emergency plans.11 In 2006, Poland proposed an energy security alliance for EU and NATO members. The concept became known as ‘Energy NATO’ and included a mutual energy-security guarantee clause, under which signatories would agree to support each other in the event of a threat to their energy security – basically, the principle of NATO’s collective defence12 applied to energy. The members would also commit themselves to delivery assistance, the development of new infrastructure on a multilateral basis and greater diversification.13 The alliance would be open to all EU and NATO members, and would thus exclude Russia. Germany developed another concept that was inspired by the Helsinki Accords in including Russia as a dialogue partner. This ‘Energy OSCE’14 concept would create a common energy security architecture in which members could develop multilateral measures that would enhance the security of all with the help of an impartial body for dispute settlement. The interests of a variety of actors involved in the energy chain could be satisfied by promoting a continuous and institutionalised dialogue.15 Both concepts of collective energy security are difficult to develop into a special organisation, as many parallel structures already exist. Meanwhile, Russia strengthened its grip on Europe by implementing NordStream, connecting Russian gas directly to Germany, and by torpedoing the EU-favoured Nabucco project that was to bring Caspian gas through Turkey to Europe. The highly Russia-dependent Baltic states and Poland intensified their efforts in building terminals for liquefied natural gas (LNG). The US might be able to export large volumes of LNG due to the shale revolution. However, US exports need approval by the Department of Energy and the Federal Energy Regulatory Commission.16 For countries without a US free trade agreement (FTA) this is difficult. 10

D. Yergin, ‘Ensuring energy security’, Foreign Affairs 85(2) (2006), 76, available at www.un.org/ ga/61/second/daniel_yergin_energysecurity.pdf 11 J. Elkind, Energy Security – Call for a Broader Agenda (Brookings Institution Press, 2010), pp. 124 f. 12 The principle of collective defence is enshrined in Article 5 of the North Atlantic Treaty. See NATO, ‘Collective defence’ (11 November 2014), available at www.nato.int/cps/is/natohq/ topics_110496.htm? 13 O. Geden, A. Goldthau and T. Noetzel, ‘“Energie-NATO” und “Energie-KSZE” – Instrumente der Versorgungssicherheit?’, Stiftung Wissenschaft und Politik (May 2007), available at www. swp-berlin.org/fileadmin/contents/products/arbeitspapiere/Energie_KS_KSZE_geden_goldthau_ noetzel.pdf 14 OSCE stands for ‘Organization for Security and Cooperation in Europe’. 15 Geden et al., ‘“Energie-NATO” und “Energie-KSZE”’. 16 F. Umbach, ‘U.S. LNG exports to the rescue of Europe? – Does a decision on LNG exports to Europe really matter?’ Energlobe (12 June 2014), available at http://energlobe.eu/politics/us-lngexports-to-the-rescue-of-europe

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US Senator Richard Lugar pledged support for NATO plans of concerted actions of collective energy security, as part of the alliance’s conflict-prevention role.17 In 2012, Lugar introduced the ‘LNG for NATO Act’18 that would reduce US allies’ vulnerability to over-reliance on Russia19 and provide automatic approval for exports to NATO countries.20 Another bill, the ‘Expedited LNG for American Allies Act’, was introduced in 2013 by Senator John Barrasso, and also aimed at enabling exports of LNG to countries that do not have FTAs. NATO’S ENERGY SECURITY EFFORTS NATO intensified consultation on energy security after the 2008 Bucharest Summit. Five fields of engagement were defined: information and intelligence fusion; projecting stability; advancing international cooperation; supporting consequence management; and supporting the protection of infrastructure.21 Both within the Alliance and with partner countries, a number of programmes and research projects are ongoing. In 2010, the Strategic Concept22 was worked out at the Lisbon Summit stating that NATO has to develop ‘the capacity to contribute to energy security, including protection of critical infrastructure and transit areas, cooperation with partners, and consultations among Allies on the basis of strategic assessments and contingency planning’.23 Accordingly, an Energy Security Section in the Emerging Security Challenges Division (ESCD) at NATO Headquarters was established. The Chicago Summit Declaration of 2012 underlined these objectives and called for further development of the outreach activities in consultation with partners.24 Following the Summit, the NATO Energy Security Centre of 17

V. Socor, ‘Lugar urges active role for NATO in energy security policy’, The Jamestown Foundation, Eurasia Daily Motion 3(222) (1 December 2006), available at www.jamestown.org/single/?tx_ ttnews%5Btt_news%5D=32287&no_cache=1#.VLFCuGSG-oU 18 United States Senate, ‘Energy and security from the Caspian to Europe – a minority staff report prepared for the use of the Committee on Foreign Relations’ (12 December 2012), available at www.foreign.senate.gov/imo/media/doc/Energy%20and%20Security%20from%20the%20 Caspian%20to%20Europe.pdf 19 B. Geman, ‘Senate bill would greenlight natural gas exports to US allies’, The Hill (31 January 2013), available at http://thehill.com/policy/energy-environment/280429-senate-bill-would-greenlight-gas-exports-to-nato-allies-japan 20 R. Rampton, ‘US should let NATO allies tap natural gas exports-Senator Lugar’, Reuters (12 December 2012), available at www.reuters.com/article/2012/12/12/usa-lng-exports-idUSL1E8 NC0TP20121212 21 NATO, ‘Bucharest Summit Declaration’, Paragraph 48 (3 April 2008), available at www.nato. int/cps/en/natolive/official_texts_8443.htm 22 NATO, ‘Strategic concept for the defence and security of the members of the North Atlantic Treaty Organization’, adopted by Heads of State and Government at the NATO Summit in Lisbon (19–20 November 2010), available at www.nato.int/nato_static_fl2014/assets/pdf/pdf_ publications/20120214_strategic-concept-2010-eng.pdf 23 NATO, ‘Active engagement, modern defence – strategic concept for the defence and security of the members of the North Atlantic Treaty Organization adopted by Heads of States and Government in Lisbon’ (23 May 2012), available at www.nato.int/cps/en/natolive/official_texts_68580.htm 24 NATO, ‘Chicago Summit Declaration’ (20 May 2012), available at www.nato.int/cps/en/natolive/ official_texts_87593.htm

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Excellence was accredited in Lithuania in 2012. It operates as an international military organisation with the aim of providing expert advice on questions related to energy security and focuses on the uninterrupted access to reliable energy supplies.25 Further, NATO’s strategic commands are also involved in activities related to energy security. One of them is Allied Command Transformation (ACT), which is enhancing training, conducting concept experiments and promoting interoperability. In 2014, the North Atlantic Council’s seminar on global energy developments underscored the security implications of recent energy trends.26 CONCLUSION The cross-cutting nature of energy security in Europe demands greater NATO involvement. Energy overdependence in one NATO country automatically constitutes a concern to others, as significant interruptions could threaten the organisation’s security as a whole. Therefore, one of NATO’s geopolitical objectives is the stability and reliability of European energy supply that can be enhanced through greater multilateral cooperation in diversification strategies and the strengthening of existing institutional bodies. It has to be noted, however, that political and institutional means will only provide security buffers and not change the game – energy market dynamics still remain the most important factor in this regard. Europe’s one-dimensional dependence on Russia is a pressing security threat. But it will be neither wise nor possible to exclude Russia completely. Mutually coordinated efforts in diversifying supply routes, suppliers and also energy resources should be at the core of transatlantic and inner-European energy cooperation.

25

NATO, ‘Centre of Excellence’ (13 March 2013), available at www.enseccoe.org/en/about-us/ centre-of-excellence.html 26 NATO, ‘NATO’s role in energy security’ (13 August 2014), available at www.nato.int/cps/en/ natolive/topics_49208.htm

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GENEALOGY OF THE CURRENT GAS SECURITY SITUATION IN THE EU–UKRAINE–RUSSIA ENERGY TRIANGLE AND THE ROLE OF INTERNATIONAL LAW Maksym Beznosiuk1

Recent Russian attempts to build a new order in Europe which has undermined the post-Cold War order, coupled with the inadequacy of contractual provisions of gas contracts between Gazprom and Naftogaz, might lead to future disruption of the supply of gas to Ukraine and the transit of gas across Ukraine, putting in risk the EU–Ukraine–Russia energy triangle. This chapter will briefly explain the genealogy of the current gas security situation in the EU–Ukraine–Russia energy triangle and the possibility of resort to dispute settlement mechanisms at contractual, intergovernmental and international levels. The possibility of modernisation with a view to prevent and address potential risks to supply and transit of gas in the EU–Ukraine–Russia energy triangle will also be considered. In the past, there were no transit and supply risks within the EU–Ukraine– Russia energy triangle during the Soviet era, due to the fact that Ukraine was a part of the Soviet Union and appropriate Soviet state authorities had full control over gas transit flows that had to be transferred across the USSR territory and the COMECON area to Europe.2 1

2

Maksym Beznosiuk has more than two years of experience in the energy sector. He earned his LLB and LLM from the Kyiv National Taras Shevchenko University, Institute of International Relations. As a Chevening Scholar, he also earned his LLM in Global Environment and Climate Change Law at the University of Edinburgh. He has recently worked as an Atlas Corps Fellow at NCSEJ in Washington, DC, conducting research on political issues in Eastern Europe with a focus on Ukraine, Russia and Belarus. Currently, he is an Erasmus Mundus Scholar studying and researching at both Uppsala University and Jagiellonian University. A. Konoplyanik, ‘Gas transit in Eurasia: transit issues between Russia and the European Union and the role of the Energy Charter’, Journal of Energy and Natural Resources Law 27(3) (2009), 445, 450.

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However, the collapse of the USSR in 1991, and the disbanding of the COMECON in 1989 led to the fragmentation of a de facto single Soviet jurisdiction into a multitude of new independent jurisdictions. This eliminated the control ‘umbrella’ of the former Soviet Ministry of Gas and Soyuzgazexport over the stable supply and transit of gas across Ukraine and the former East European satellite states to delivery points at the EU-15 border.3 As a result, transit states like Ukraine emerged. Moreover, by the end of the 1960s, Soyuzgazexport (which was a predecessor of Gazprom) signed the so-called long term gas export contracts, with an average length of twenty to thirty-five years, with Western European buyers of gas (France, Finland, Austria, Germany, Italy). As a consequence, the Russian Federation inherited gas supply obligations under these long-term supply contracts, after the collapse of the Soviet Union, and these have been extended for several decades.4 Today, Gazprom (controlled by the Russian state) is obliged to deliver gas at the same delivery points as Soyuzgazexport during the Soviet period. At the same time, it has to agree on the terms of transit and supply of gas, with Naftogaz (controlled by the Ukrainian state).5 The EU companies do not have direct contracts with Naftogaz and the EU has a limited influence on energy relations between Ukraine and Russia, and on the secure supply of gas from Russia across Ukraine to delivery points located in the EU. After the collapse of the Soviet Union, export and transit supplies of natural gas were not contractually separated between Russia and Ukraine. They were based on political pricing and not on the ‘replacement value’ principles that are usually used in international gas contracts.6 At the beginning of 2005, the situation changed with the initiatives on both sides to revise the provisions of the intergovernmental agreement that was concluded in 2001 which contained provisions on a gas-for-transit payment scheme. According to the scheme provided in the intergovernmental agreement (that is, between Russia and Ukraine), the Russian state company Gazprom paid for transit by gas supplies to the Ukrainian state company Naftogaz, with a minimal transit payment fee and fixed gas price.7 However, both countries agreed to complement the existing intergovernmental agreement by two separate commercial transit and long-term gas export contracts that were signed by Naftogaz and Gazprom.8 3

4 5 6

7 8

K. Yafimava, The Transit Dimension of EU Energy Security (Oxford Institute for Energy Studies, 2011), p. 29. Ibid., 22. A. Konoplyanik, ‘Gas Transit in Eurasia’ (n 2) 450. Energy Charter Secretariat, ‘Putting a price on energy: international pricing mechanisms for oil and gas’, Energy Charter (2007), available at www.energycharter.org/fileadmin/DocumentsMedia/ Thematic/Oil_and_Gas_Pricing_2007_en.pdf Yafimava, The Transit Dimension of EU Energy Security, p. 149. K. Westphal, ‘Russian gas, Ukrainian pipelines, and European supply security’, SWP Research Paper 5, 10.

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It was expected that these contracts would make the transit and supply of gas more transparent and economically beneficial for Ukraine and Russia. This assumption turned out to be wrong, however, due to conflict over provisions of the supply contract between Gazprom and Naftogaz that led to the subsequent major supply interruptions to Ukraine and transit interruptions to EU countries in 2006, 2008 and 2009.9 Moreover, dispute settlement mechanisms provided at contractual, intergovernmental and international level were unable to prevent these gas disputes. In this context, it should also be stressed that the gas transport systems of Ukraine and Russia have always been unified, and there are no separate pipelines for gas supply to the Ukrainian market and transit supply across Ukraine to Europe.10 As a result, it is only possible to separate them at a contractual and not a physical level.11 Hence, in case of suspension of gas supplies to Ukraine, due to the failure of Naftogaz to comply with provisions of the supply contract, it will have simultaneous impact on the transit of gas to Europe because of the inability to simultaneously guarantee domestic demands of Ukraine and transit supplies to Europe. Contractual provisions of the signed ten-year long-term gas export contract (LTGEC) between Gazprom and Naftogaz in 2009, which is based on the modernised Groningen model of long-term gas export contracts, contain contractual provisions that might lead to future disruption of the supply of gas to Ukraine and the transit of gas across Ukraine, putting in risk the EU–Ukraine–Russia energy triangle. Thus, there is an urgent need to revise the LTGEC between Naftogaz and Gazprom. In this regard, in light of current arbitration and negotiations between Gazprom and European companies, it is doubtful that such dispute settlement mechanisms as negotiation and arbitration could adequately address potential supply and transit risks between Gazprom and Naftogaz at contractual level. Recent negotiations and arbitration cases concerning revision of the contractual provisions of LTGEC between ENI, Edison, PGNiG, RWE and Gazprom could make Naftogaz actively pursue revision and resort to such dispute settlement mechanisms as negotiation and arbitration with a view to revising inadequate contractual provisions on the gas pricing formula clause and the take-or-pay clause in its LTGEC with Gazprom. Nevertheless, it is highly unlikely that such negotiations between Gazprom and Naftogaz concerning the revision of the LTGEC will be successful, and arbitration could serve as the only remaining dispute settlement mechanism at the contractual level. However, the Stockholm Chamber of Commerce will not be able to render any award 9

F.Umbach, ‘Ukraine’s energy security challenges: implications for the EU’, in T. Kuzio and D. Hamilton (eds), Open Ukraine. Changing Course towards a European Future (John Hopkins University, 2011), p. 96. 10 A. Konoplyanik, ‘The gas transportation system of Ukraine and Russia has always been unified’ (Interview), OGEL 7(2) (2009), available at www.konoplyanik.ru/ru/publications/articles/448_ The_gas_transportation_system_of_Ukraine_and_Russia_has_always_been_unified.pdf 11 A. Konoplyanik, ‘Modernization and expansion of the gas transportation system will create positive macroeconomic effects for Ukraine’ [2009] 2 OGEL, available at www.ogel.org/article. asp?key=2895

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quickly because of its Regular-track Rules and Rules for Expedited Arbitration, which state that any award should be rendered within a three- to six-month period from the transmission of the file to the tribunal.12 Moreover, even prior to resorting to arbitration, due to current non-compliance of Naftogaz with the contractual provisions of its LTGEC with Gazprom, the latter could suspend its obligations concerning the supply of gas to Ukraine: this could adversely affect the contractual obligations of Ukraine related to non-interruptive transit of gas to Europe in its transit contract with Gazprom. Despite the great significance of the transit and supply of gas, today’s dispute settlement mechanisms at intergovernmental and international level are not adequate to prevent and address potential risks to the supply and transit of gas in the EU–Ukraine–Russia energy triangle. The key reason for that is that the CIS-level, EnCT and ECT mechanisms can only play a very limited role in addressing transit and supply risks in the EU–Ukraine–Russia energy triangle. In the event of resort being made to CIS-level dispute settlement mechanisms, the inadequate Rights of Procedure of the Council of the Heads of State of the CIS and the nature of its decisions as recommendations, together with inadequate conciliatory procedures within the Economic Court of the CIS would make it impossible for Ukraine and Russia to use these mechanisms quickly and effectively to resolve their disputes over the supply or transit of gas.13 With regard to the EnCT mechanisms, the absence of the Procedural Act of the Ministerial Council on the Rules of Operation for the Mutual Assistance Obligations makes it impossible for Ukraine to resort to the use of the Mutual Assistance Mechanism, refer its request to the Ministerial Council in case of external disruption of gas and apply for an urgent assistance from the Energy Community members.14 At the same time, even if Ukraine could take part in the activities of the Security of Supply Coordination Group, it is doubtful that it could be useful because of its primary focus on coordination of actions at the national level and narrower focus on the Mutual Assistance Mechanism.15 Such ECT mechanisms as State-to-State Dispute Settlement and conciliation procedure cannot adequately address potential supply and transit risks. In the case of conciliation procedures, there are problems as to when it could be applied, the role of conciliator and the introduction of interim transit tariffs.16 With the State-to-State Dispute Settlement, there are unclear provisions on the

12

Rules for Expedited Arbitration of the Arbitration Institute of Stockholm Chamber of Commerce (2010), Art. 9. 13 Rules of Procedure of the Council of the Heads of State of the CIS 2009 (in Russian), available atwww.cis.minsk.by/page.php?id=3962; Rules of Procedure of the Economic Court of the CIS 1997 (in Russian), available at http://sudsng.org/download_files/statdocs/regulations_2013.pdf 14 ‘Secondary Legislation’, available at www.energy-community.org/portal/page/portal/ENC_ HOME/ENERGY_COMMUNITY/Institutions/Ministerial_Council/Secondary_Legislation 15 ‘Security of Supply Group’, available at www.energy community.org/portal/page/portal/ENC_ HOME/AREAS_OF_WORK/Security_of_Supply/Group#tasks 16 The Energy Charter Treaty and the Energy Charter Protocol on Energy Efficiency and Related Environmental Aspects (17 December 1994), 2080 U.N.T.S.100, Art. 7.7, available at www. encharter.org/fileadmin/user_upload/document/EN.pdf

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use of diplomatic channels and time-constraints imposed by UNCITRAL rules that are not ideally suited in certain aspects to state-to-state arbitration.17 The adoption of a separate ECT Protocol on Early Warning and Prevention Mechanism of Emergency Situations in the Sphere of Energy could help integrate an Early Warning and Prevention Mechanism of Emergency Situations within the ECT as part of the procedures of dispute settlement mechanisms: this could serve as a second prior-to-arbitration option together with a conciliation procedure.18 As a result, this has a potential to prevent any potential escalation of transit conflict between Ukraine and Russia.

17 18

Ibid., Art. 27. A. Konoplyanik, ‘Energy Charter Plus, Russia to take the lead role in modernizing ECT’ OGEL 4 (2009), available at www.ogel.org/article.asp?key=2955

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GERMAN ENERGY LAW Katharina Vera Boesche1

In order to comply with the requirements of the Gas and Electricity Acceleration Directives of the European Union (Directives 2003/54/EC and 2003/55/ EC, respectively), the German parliament passed extensive amendments to the nation’s existing Energy Industry Act (Energiewirtschaftsgesetz – EnWG) in June 2005.2 The federal government also outlined detailed guidelines on electricity and gas grid access and on tariff calculation methods in draft ordinances. The electricity and natural gas sectors in Germany have been characterised by their large number of enterprises (approximately 1,000) and by the strong involvement of municipalities. Exclusive concession contracts with municipalities and demarcation agreements have impeded competition. There also are cross-shareholdings among energy enterprises, industry and finance, and among same-sector enterprises. Although the tendency is toward privatisation, there is additionally a mix of private/public ownership as the federal states (Länder) and municipalities own shares in many electricity and natural gas 1

2

Katharina Boesche was a Scientific Assistant (Assistant Professor) with the Institute for German and European Antitrust Law, Competition Law and Energy Law in the Faculty of Law, Freie Universität Berlin, Germany from 2002 to 2009, earned a doctorate of law in 2003 and a Masters from the same institution. She has been a lecturer at the Berlin School of Economics, the University of Indonesia’s Faculty of Law, the Institute for German and European Energy Law (Berlin) and the Faculty of Law at the University for State and Law (Moscow). As a lawyer, Dr Boesche has held positions with the firms of Baker & McKenzie (Berlin), and Girdhani Lal Sanghi (New Delhi, India), as well as the Superior Court of Justice of Berlin. She specialises in energy and competition law. Since 2009 she has been head of the ‘Legal Framework’ project group of the National Research Projects E-Energy as well as ICT of Electro mobility of the Federal Ministry of Economics and Technology. Her articles have appeared in such publications as Betriebs-Berater, Europäische Zeitschrift für Wirtschaftsrecht, Neue Zeitschrift für Energierecht. In 2015 the 5th revised edition of her book on Competition Law (Wettbewerbsrecht) will be published. Bundesgesetzblatt (BGBl), I 2005, 1970.

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enterprises. Municipal companies (Stadtwerke) are involved in natural gas distribution, electricity production and distribution as well as other activities such as public transport. Revenues from natural gas and electricity sales are used partially to finance other activities. Municipalities collect concession fees from gas and electricity distribution companies. Most energy suppliers used to have their own clearly demarcated market that was inaccessible to competing suppliers. Thus, many German public utility enterprises, in effect, were monopolists in their regional and local markets. Since 2000 there have been enormous changes in the market structure. On 13 June 2000, the Commission cleared the merger between Viag and Veba, and on 3 July the same year the Federal Cartel Office (Bundeskartellamt) cleared the merger between VEW and RWE. The two entities resulting from these mergers are assumed to control the majority of the German energy markets. THE REQUIREMENTS OF THE EUROPEAN UNION DIRECTIVES OF INTEREST The EU Directives of 2003 have departed from Directives 96/92/EC and 98/30/ EG, which they superseded, in two major areas. The Directives have sharpened unbundling requirements and set out the minimum set of competences, which all the member states’ regulatory authorities should share. Since Germany was unique in Europe for not having a regulatory authority with ex ante rule-making powers, the regulatory provisions of the EU Directive pose some of the greatest cultural and law-making challenges for Germany. According to the EU Directives of 2003, regulatory authorities are required to be entirely independent from electricity and gas industry interests. Their minimum responsibilities include ensuring non-discrimination, effective competition and efficient functioning of the market.3 In this context, regulation contributes to guaranteeing non-discriminatory access to networks. National regulatory authorities should be able to fix or approve tariffs, or the methodologies underlying the calculation of the tariffs. The regulatory authority can be required to submit its tariffs or calculation methods to a relevant body in the concerned EU member state, such as the Economics Ministry in the case of Germany. The relevant body, in such a case, will have the power either to approve or reject a draft decision submitted by the regulatory authority.4 More specifically, the relevant body should be permitted to either accept or reject the decision; however, it may not amend the regulatory authority decision. UNBUNDLING The German energy sector’s high degree of vertical integration has contributed to the large number of grid access disputes since that sector’s liberalisation in 1999. One of the crucial aspects of the German Energy Industry Act of 2003 was to provide rules on legal, operational (management and information) 3 4

For example, Articles 10 and 15 of Directive 2003/54/EC. Directive 2003/54/EC, Article 23.3.

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and accounting unbundling, which closely mirror the EU Directive provisions in their wording. The Act, however, does not foresee separate accounting for power generation and marketing activities.5 The German regulator has the power to institute administrative proceedings against a grid operator in the event that it is not compliant with the provisions of the German Energy Industry Act or it abuses its dominant market position. Such proceedings may be initiated ex officio or upon request by a person concerned by the abusive behaviour. REGULATED THIRD-PARTY ACCESS Germany’s historical reliance on negotiated rather than regulated third-party access was unique in Europe and contravened the provisions of the new EU Directives. The EnWG and the two network access ordinances6 introduced provisions for non-discriminatory, regulated third-party access based on point of connection charges independent of distance in electricity, and an entry-exit regime in gas.7 Immediately prior to passage of the EnWG of 2005, the German Parliament adopted a significantly simplified entry-exit model for gas network charges. Only one entry and one exit capacity have to be reserved in order to access the comprehensive German gas grid, comprising about 700 different operators. In order to facilitate gas transport employing only two reservations, the gas network operators are obliged to fully cooperate with each other. However, such access arrangements can be denied for technical reasons or concerns about economic efficiency. Furthermore, access to network capacity may be denied if this capacity is needed to fulfil long-term import contracts. NETWORK TARIFFS In accordance with the EU Directives of 2003, the EnWG states that network tariffs for energy network operators are to be appropriate, non-discriminatory and transparent, and are to be no higher than those which network operators charge de facto or nominally to companies with which they have ownership 5 6

7

Directive 2003/54/EC, Article 23.4. J. F. Baur, K. U. Pritzsche and S. Klauer, Ownership Unbundling (Nomos, 2006); PricewaterhouseCoopers (ed.), Entflechtung und Regulierung in der deutschen Energiewirtschaft (Haufe/ PricewaterhouseCoopers, 2007); A. Schönborn, ‘Konzernzugehörigkeit contra Unbundling – ein (un)lösbarer Konflikt?’, in F. J. Säcker and W. Busse von Colbe (eds), Wettbewerbsfördernde Anreizregulierung (Peter Lang, 2007), p. 37; F. J. Säcker, ‘Aktuelle Rechtsfragen des Unbundling in der Energiewirtschaft’, Recht der Energiewirtschaft (2005), 85; F. J. Säcker, ‘Entflechtung von Netzgeschäft und Vertrieb bei den Energieversorgungsunternehmen: Gesellschaftsrechtliche Möglichkeiten zur Umsetzung des sog. Legal Unbundling’, Der Betrieb (2004), 691; F. J. Säcker, ‘Der Independent System Operator. Ein neues institutionelles Design für Netzbetreiber. Veröffentlichungen des Instituts für deutsches und europäisches Wirtschafts-, Wettbewerbs- und Regulierungsrecht der Freien Universität Berlin Bd. 5, 2007; F. J. Säcker, ‘Die wettbewerbsrechtliche Beurteilung von Netzkooperationen, Beteiligungen an Netzgesellschaften, Netzpacht und Betriebsführungsverträgen’, Zeitschrift für Neues Energierecht (2005), 270. EnWG, Sec. 20.1.

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ties. Network charges must be determined ‘on the basis of the typical costs of an efficient and structurally comparable grid operator’. The EnWG requires that, when setting tariffs, the cost of maintaining the real value of the existing grid (Nettosubstanzerhaltung), incentives for cost-efficient operation and adequate invested capital interest be taken into account. For new network elements, only the initial costs can be taken into account. One of the most controversial issues in the legislative process was, and still is, the question of whether the regulator should set network tariffs ex ante, or should only set the methodology for tariff determination. The first draft of the EnWG did not foresee any ex-ante regulation of prices. The EnWG provides for an ex-ante tariff setting for third-party access to the electricity and gas grid in the event of price increases. Since 2009, in Germany incentive regulation is applied as a governmental instrument to regulate monopolistic markets.8 It is used for setting compensation fees for electricity and gas by the Federal Network Agency. This instrument should lead to lower energy prices for consumers. Furthermore, new electricity and gas suppliers as well as renewable energies will benefit from it. Incentive regulation will create incentives to reduce costs for the operators of gas and electricity networks in order to pass this on to consumers. Network operators have to limit their fees (price caps) or revenues (revenue caps). In Germany, revenue caps are intended for the approximately 1,600 network operators. A nationwide efficiency comparison determines individual company estimations for cost efficiency. All operators must then compete with the most efficient operator. Less efficient companies have a few years to reduce the respective inefficiency determined by the Federal Network Agency. In addition, the revenue cap of every single network operator is reduced annually by a percentage determined by the regulatory authority (sectorial productivity factor). However, cost-cutting instruments may lead to quality and stability losses in the network. In order to secure necessary network investments specific regulations are provided (investment allowances and exemptions). An additional quality control enables the regulatory authority to increase or reduce network revenues of individual companies depending on the determined network quality. The regulation (ARegV) sets a revenue cap for the companies concerned corresponding with the total network costs, including calculatory depreciations and the equity yield rate. The revenue cap of a company that may be covered by an operator with revenues from network fees and miscellaneous revenues determined by the regulatory authority before the start of the period for each year of the next regulatory period. A regulatory period lasts five years. The network operator can carry out individual revenue cap adjustments on price developments. If unforeseen changes arise an adjustment may be applied in order to avoid undue hardship. 8

N. Angenendt and O. Franz, ‘Von der Kalkulation zur Anreizregulierung. Die Drei-Phasen der Netzentgeltregulierung nach dem EnWG’, emv 3(5) (2005), 50–5; A. Böwing, O. Franz and M. Thiel, ‘Investitionen und Anreizregulierung’, Netzwirtschaft & Recht 4(3) (2007), 90–6.

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The companies’ revenue caps are to be determined through a cost review. A chartered accountant must confirm the data. The difference between the revenue cap and the actual proceeds will be registered by the Federal Network Agency annually on a ‘regulation account’. If the total actual revenue exceeds 5 per cent of the revenue cap for gas and electricity network fees must be adjusted without any delay. Network operators with fewer than 30,000 electricity or 15,000 gas customers can participate in a simplified method for determining the efficiency comparison. For those, an averaged efficiency value will be assumed. THE FEDERAL REGULATORY AUTHORITY: FEDERAL AGENCY FOR GRID OPERATION (BUNDESNETZAGENTUR) Creating a sector-specific regulator was one of the major compliance challenges Germany faced. The EnWG provides a split of power between the federal regulatory authority (Bundesnetzagentur) and regulatory authorities in each federal state. The latter will only work well for network operators with up to 100,000 network connections. The EU Directives and, in particular, the associated interpretative notes make it clear that the regulatory authority is intended to have broad powers for all regulatory tasks associated with the core duties and responsibilities assigned by the EU Directive. However, since the EnWG and the draft ordinances contain very detailed provisions concerning such items as the price cap formula calculation of grid tariffs, it is questionable to what extent the regulatory authority is left with decision-making power to adapt and develop further the regulatory methodology using the existing administrative means. Grid access and power transmission The amendment of the EnWG in 2005 fully opens up the German power market to competition. Every customer has free choice of his or her supplier. Competition on the electricity market is expected to occur primarily using the current existing grid. Construction of new power lines is unlikely to play a major role. The EnWG 1998 already contains an explicit right to access the power grid.9 Grid owners are obliged to transport the energy to the consumer under conditions no less favourable than for comparable services to affiliated enterprises. In addition to EnWG 1998, Sec. 6, a right to access power grid may be based on GWB Sec. 19(4) No. 4. These rights are enforceable in civil courts. There are, however, certain specific exceptions where third-party access can be denied, for example if transmission is impossible or inappropriate for operational or other reasons. The burden of proof for these exceptions is imposed on the owner of the grid. Additionally, discrimination against third-party users is prohibited; they must be treated on equal terms as subsidiaries of the owner. 9

For more details see www.e-energy.de; www.ikt-em.de

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SMART GRIDS While in the past power grids with centralised power generation dominated, the trend is now towards decentralised ‘plants’ (Erzeugungsanlagen), both in the production of fossil primary energy by small power stations and in generation from renewable sources like photovoltaic systems, solar thermal power, wind power and biogas plants. This leads to a much more complex structure, primarily in the area of load control, voltage stability in the distribution network and to maintain network stability. The current Energy Act provides for the introduction of smart metering systems a more flexible and dynamic load switching and dynamic tariff.10

10

Ibid.

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DELIVERING ENERGY LAW AND POLICY IN MALTA Simone Borg1

INTRODUCTION Malta is the smallest member state of the European Union2 with a total land area of approximately 320 km2 and a coastline of 140 km.3 Its population density, with 1,300 persons/km2, 3 is amongst the highest in the world.4 Malta’s economic activity is rather services-oriented, namely tourism, financial services and shipping. Malta’s GDP per capita stood at €17,919 in 20135 and the economy experienced a 3.3 per cent growth in GDP per capita in 2014.6 Due to its minute size and population, Malta has a centralised system of government, with local councils having very limited powers. Parliament is unicameral. Laws are published in both English and Maltese and may be of two types. Acts of Parliament 1

2 3

4 5 6

Professor Simone Borg LLD, MJur (International Law), PhD is Deputy Dean and Head of Department of Environmental Law and Resources Law at the University of Malta. She is also a visiting professor at the University of Leuven and the IMO International Maritime Law Institute in Malta. She is currently Malta’s Ambassador on Climate Action. Professor Borg has published various law books and legal articles on environmental law, resources law, climate change law and the conservation of living marine resources. Malta became independent on 21 September 1964 and an EU member state on 1 May 2004. The archipelago consists of Malta, the largest of the three islands, which has an area of 245 km2 and a coastline of approximately 100 km, while Gozo and Comino have an area of 67 km2 and 3 km2 respectively. The other islands, Selmunett, Cominotto and Filfla, are very small and uninhabited. Malta’s climate is typically Mediterranean, with distinct winter and summer seasons and an average rainfall of around 476 mm. Temperatures, although relatively mild, still require buildings to be heated in winter and cooled in summer. Malta has no permanent surface water resources and the demand for water consumption is met by harvesting rain water, desalination of sea water by reverse osmosis plants and groundwater abstraction. www.tradingeconomics.com/malta/population-density-people-per-sq-km-wb-data.html www.focus-economics.com/countries/malta http://ec.europa.eu/economy_finance/eu/countries/malta_en.htm

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(statutes) are known as primary legislation, whilst Legal Notices are referred to as secondary legislation and published whenever an Act of Parliament gives specific enabling powers to a minister to issue regulations thereunder. Judgments of national courts have no binding law of precedent.7 ENERGY GENERATION AND ENERGY MARKETS IN MALTA Energy generation in Malta depends upon imported fossil fuels. Only around 1 per cent of its energy is generated from renewable energy sources. Malta has no gas distribution network and only one power plant. The electricity generation8 market in Malta is open to competition and generators may produce for their own consumption as well as sell to Enemalta Corporation.9 There is no wholesale market for electricity and its retail is not subject to competition because the public company, Enemalta Corporation, remains the only licensed supplier of electricity to final customers. As a result, customer switching cannot be implemented. All customers of electricity are on a regulated retail tariff. Enemalta Corporation is also the distribution system operator. There are no transmission systems and associated operators in Malta. Following EU membership and particularly due to the EU Climate and Energy Package of 2009, Maltese authorities are diversifying the energy supply and augmenting the use of renewable energy sources. The installation of new, efficient generation capacity and the upgrades in generation equipment will lead to a reduction of around 40 per cent of greenhouse gas emissions by 2020 from 1990 levels. This target will also be achieved via the first interconnection cable between Malta and Sicily, which will also enable Malta to purchase electricity from the European grid.10 Malta was connected to the European grid, thus ending its energy isolation, in the first quarter of 2015. GOVERNANCE, POLICY-MAKING AND REGULATION The Ministry for Energy and Health (MEH)11 is entrusted with formulating energy policy and its executive governance. The Sustainable Energy and Water Conservation Unit (SEWCU), within MEH, performs a number of functions including the setting up of national policies related to sustainable energy and the preparation of national plans to meet national and EU targets in the fields of energy. It oversees the implementation of measures necessary to achieve 7

See D. J. Attard, The Maltese Legal System Vol I (Malta University Press, 2012), pp. 20–42. See http://mra.org.mt/wp-content/uploads/2012/08/8.2.Maltas-CHP-Report.pdf 9 The Electricity Market Regulations (S.L.423.22) transpose Directive 2009/72/EC and take into account the derogations granted to Malta by virtue of Article 44 of Directive 2009/72/EC from the requirements of the following articles: Article 9: Unbundling of transmission systems and transmission system operators, Article 26: Unbundling of distribution system operators, Article 32: Third-party access, Article 33: Market opening and reciprocity. 10 See ‘Malta’s report to the European Commission on the implementation of Directive 2009/72/ EC, Directive 2009/73/EC and Directive 2005/89/EC’, MRA Publication (July 2013), available at www.ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/NATIONAL_REPORTS/ National%20Reporting%202013/NR_En/C13_NR_Malta-EN.pdf. See also http://mra.org.mt/ wp-content/uploads/2012/07/216/Malta s-Annual-Report-2014-3.pdf 11 See www.energy.gov.mt 8

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these targets, as well as carrying out projects to increase renewable energy generation and energy efficiency. It is the minister responsible for energy who has the enabling powers to issue subsidiary legislation under the Malta Resources Authority Act.12 This statute also establishes the Malta Resources Authority (MRA), the energy regulatory body that has a separate and distinct legal personality from the government. MRA is the national (and only) entity that is legally responsible for regulating13 practices, operations and activities in the energy sector14 in Malta. It regulates the energy utility service provider, namely EneMalta Corporation, a public entity,15 and its subsidiary companies. It also regulates retailers and operators in the energy sector, such as fuel stations, gas and kerosene suppliers, offshore bunkering companies and operators of road tankers, energy price structure regulation, licensing of operators and tradespeople in the sector. MRA has a climate change unit that is entrusted with regulating and implementing climate action, the emissions trading scheme, energy efficiency and renewable sources of energy. Ministerial responsibility for climate action, however, falls under the remit of the ministry responsible for sustainable development, environment and climate change (MSDEC). MSDEC is entrusted with the executive governance of climate action policy-making, namely adaptation, mitigation and reporting to the United Nations Framework Convention on Climate Change (UNFCCC) Secretariat and the EU Commission in relation thereto. ENERGY LAW IN MALTA The Malta Resources Authority Act16 is an enabling Act whereby the minister responsible for energy may issue subsidiary legislation that would provide for more specific laws (regulations) to implement the objectives of the same Act. Table 93.1 shows the main sources of subsidiary legislation published under the MRA Act which regulate the energy sector and any operations/operators relating thereto. All legislation is accessible online.17 EMISSIONS TRADING Emissions trading in Malta is also closely linked to energy law as only the power plants fall within the scope of ‘stationary installations’ under the EU ETS directive.18 Malta’s legal framework for the implementation of the EU emissions trading scheme (ETS) is made up of EC Regulation 525/2013 establishing a Mechanism for Monitoring and Reporting Greenhouse Gas Emissions as well

12

MRA Act (Chapter 423 of the Laws of Malta) and all the subsidiary legislation issued under it may be found at http://justiceservices.gov.mt/DownloadDocument.aspx?app=lom&itemid=8889&l=1 13 Article 4 of the MRA Act establishes the functions of the Authority and gives wide-ranging responsibilities. 14 MRA also regulates the regulation of water and minerals as resources as well as climate change. 15 See www.enemalta.com.mt 16 See above at 11. 17 Ibid. 18 Directive 2003/87/EC as subsequently amended. See note 19 below.

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Table 93.1 Energy regulations in Malta Energy generation storage and supply of fuels S.L. 423.26

Natural Gas Supply (Safeguard of Security) Regulations

S.L. 423.27

Cogeneration Regulations

Energy marketing S.L. 423.28

Petroleum for the Inland Wholesale Fuel Market, Bottling of LPG and Primary Storage Facilities Regulations.

S.L. 423.31.

Liquefied Petroleum Gas Market Regulations

S.L. 423.37

Petroleum for the Inland (Retail) Fuel Market Regulations

Quality control, certification and authorisations S.L. 423.42

Bunkering Authorisation Regulations

S.L. 423.44

Autogas (Installation and Certification) Regulations

S.L. 423.39

Electrical Installations Regulations

S.L. 423.29

Quality of Fuels Regulations

S.L. 423.30

Authorisation (Suspension, Refusal and Revocation) Regulations

Low-carbon energy generation, energy efficiency and renewables S.L. 423.33

Energy Performance of Buildings Regulations

S.L. 423.34

Energy End-use Efficiency and Energy Services Regulations

S.L. 423.38

Guarantees of Origin of Electricity from High Efficiency Cogeneration and Renewable Energy Sources Regulations

S.L.423.24

Biofuels and Bioliquids Market Regulations

S.L.423.25

Minimum Requirements on the Energy Performance of Buildings Regulations

S.L.423.43

Energy Performance of Buildings (Fees) Regulations

S.L.423.46

Feed-in Tariffs Scheme (Electricity Generated from Solar Photovoltaic Installations) Regulations

S.L.423.48

Lifecycle Greenhouse Gas Emissions from Fuels Regulations

as two other legal notices published under the Environment and Development Planning Act.19 S.L. 504.6620 transposes the Directive on Emissions Trading as subsequently amended,21 with respect to stationary installations. S.L. 504.11522 supplements it and transposes EU Directive 2008/101/EC that included aviation 19

Chapter 504 of the Laws of Malta. The text of this Act and all subsidiary legislation issued thereunder is available at www.justiceservices.gov.mt/LOM.aspx?pageid=27&mode=chrono&g otoID=504 20 S.L. 504.66 the European Union Greenhouse Gas Emissions Trading Scheme for Stationary Installations Regulations establishes the roles and responsibilities of the principal players in the scheme, including competent authorities and operators and rules relating to the main functions of the scheme. 21 Directive 2003/87/EC as amended by the Linkages Directive 2004/101/EC and Directive 2009/29/EC on the 2009 Climate and Energy Package. 22 S.L. 504.115 the European Union Greenhouse Gas Emissions Trading Scheme for Aviation Regulations, 2012

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activities in the EU ETS thereby.23 In Malta’s case, non-ETS emissions include also all non-CO2 GHG emissions from the two local energy generation power plants (these plants fall under the EU ETS in respect of CO2 emissions).24 ENERGY POLICY INSTRUMENTS Apart from the legal framework energy governance is also subject to a number of policy instruments in the form of Strategies, Plans and Reports. GREENHOUSE GAS MITIGATION FROM ENERGY GENERATION To implement the emissions reduction targets from the energy generation sector, Malta published, in September 2009, a National Strategy for Policy and Abatement Measures relating to the reduction of greenhouse gas emissions.25 The Strategy, commonly referred to as the Mitigation Strategy, identifies measures to meet Malta’s mitigation targets under the EU Climate Energy Package of 2009. It seeks to prioritise each action on the basis of its financial cost, the ability to implement it, its economic and environment impact, its immediate positive impact and whether an abatement measure stems from a specific EU and international law obligation. The actions stipulated in the strategy are updated by the Report on Projections, Policies and Measures, commonly referred to as the PAMS report, which outlines the specific actions being undertaken26 and their effect on greenhouse gas emissions. The Report, published in 2011, highlights sectoral measures in energy.27 As an EU member, Malta has the obligation to submit an annual National Greenhouse Gas Emissions Inventory.28 23

See http://mra.org.mt/climate-change/emissions-trading-intro/and http://mra.org.mt/climate-change/ mitigation-of-greenhouse-gas-emissions/ 24 Non ETS emissions also include emissions from road transport and domestic navigation, waste, agriculture, industrial processes, solvent and other product use, fuel combustion in industry and in the residential, institutional and commercial sectors, as well as fugitive emissions from fuels. These emissions currently account for approximately one-third of Malta’s total greenhouse gas emissions. 25 Ministry for Resources and Rural Affairs, Government of Malta, ‘National Strategy for Policy and Abatement Measures Relating to the Reduction of Greenhouse Gas Emissions’ (2009). A Consultancy Report was drawn up by an independent panel of experts appointed in June 2008 and then their Report was subjected to a national consultation process between January and March 2009. It was then endorsed by government as a National Strategy. The Strategy may be found at www.gov.mt/en/Government/Publications/Documents/MSDEC/National%20 Climate%20Change%20MITIGATION%20Strategy.pdf 26 ‘Malta’s biennial report on policies and measures and projected greenhouse gas emissions’, MRA Report (2013), available at http://mra.org.mt/wp-content/uploads/2013/07/Malta-PAMsReport-2013-V1.5.pdf 27 The PAMS report includes measures that have or are being undertaken as well as those planned in the near future. The report also includes emission reduction measures from the following sectors: waste, transport and agriculture. 28 See ‘National greenhouse gas emissions inventory for Malta 2013’, Annual Report for Submission under the United Nations Framework Convention on Climate Change, MRA Publication, Report 4/13 (2003). This obligation stems from Article 3(1) of the EU Regulation 525/2013 on the Monitoring Mechanism. The most recent GHG Inventory for Malta is available at http://mra.org.mt/wp-content/uploads/2013/07/Malta-National-Emissions-Inventory-Report1990-2011-V1_3.pdf

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RENEWABLES The Strategy for Renewable Electricity Exploitation in Malta consists of two volumes: one on renewable energy targets29 and one on policy options.30 The Mitigation Strategy as well as the Policies and Measures Report31 referred to above advocate a number of measures to promote renewable energy sources. Government is annually providing a number of incentives to encourage renewable energy production by the industrial and domestic sectors.32 ENERGY EFFICIENCY The National Energy Efficiency Action Plan33 was published in 2008. The implementation of the Plan has led to the implementation of energy efficiency initiatives in the domestic and industrial sectors to help Malta achieve its national energy efficiency targets.34 CONCLUSION Energy law and policy in Malta will now have to be revised in the light of the new EU Energy and Climate Package agreed upon by the European Council and the formulation of the Low Carbon Development Strategy which is in its initial phase. To improve the energy security of supply and environmental performance, the authorities will continue to focus on diversifying the energy mix, phasing out heavy fuel oil dependency of the electricity sector by 2016.

29

M. MacDonald, ‘Strategy for renewable electricity exploitation in Malta. Volume 1: renewable electricity target’, MRA (July 2005), available at http://mra.org.mt/wp-content/uploads/2012/08/ 15.1.MM-Phase-1.pdf 30 M. MacDonald, ‘Strategy for renewable electricity exploitation in Malta. Volume 2: policy options review’, MRA (August 2005), available at http://mra.org.mt/wp-content/uploads/2012/08/15.2 .MM-Phase-II-.pdf 31 See note 21 above. As an EU member, and in accordance with the EU’s Monitoring Mechanism Articles 3(2) respectively, Malta has to submit biennial reports on climate change policies, measures and projections (PAMs) The PAMs Report can be considered as the basic policy and implementation management tool for countries to monitor progress towards achieving their targets on the limitation and reduction of greenhouse gas emissions until the year 2020 for the same sectors as those covered by the national emissions inventory. 32 Examples include investment in photovoltaic solar water heaters, micro-wind turbines and other forms of renewable energy production. These are being incentivised through a number of schemes managed by the Malta Resources Authority and Malta Enterprise (schemes specific to industry) as well as through specific projects financed by central government and European funds. 33 Malta Resources Authority, National Energy Efficiency Action Plan (2008), available at http:// mra.org.mt/wp-content/uploads/2012/08/12.National-Energy-Efficiency-Action-Plan-2008.pdf 34 Most of the measures direct the end-user towards utilisation of fewer energy-intensive products and, when not avoidable, the most energy-efficient products are encouraged. The introduction of smart metering, giving the consumer the possibility of monitoring consumption more accurately, together with incentive schemes on the purchasing of energy-efficient home appliances and incentives awarded to facilitate the uptake of energy-efficient lighting have helped reached meaningful goals in undertaking a drastic mentality change in the conception of value of energy.

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Import dependency will remain high for gas and electricity even if the electricity generation system becomes less carbon-intensive. The major legal and policy challenge for Malta will be its renewable energy targets. Solar energy is the only option available as a source of renewable energy that is cost effective and technologically feasible at this point in time. The lack of renewable energy options is not, however, the only impediment as Malta’s geophysical realities also prevent it from maximising its solar energy potential.

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DELIVERING ENERGY EFFICIENCY POLICIES IN ROMANIA Sebastian Radocea1

INTRODUCTION This chapter briefly sets out the status of the Romanian legislation in respect of energy efficiency, as well as a practitioner’s perspective on a few of the most important questions in its application concerning energy efficiency contracting for Romanian public buildings. The goal of the discussion is ultimately to highlight the need for legislative intervention in order to remove barriers to the development of the energy efficiency services market for both domestic and foreign investors. LEGAL FRAMEWORK FOR ENERGY EFFICIENCY In line with the Europe 2020 strategy, Romania adopted national targets2 of increasing energy efficiency aimed at achieving a decrease of 19 per cent in national energy consumption by 2020. In this regard, Romania is obliged to introduce measures for increased energy supply security (through the diversification of resources and expansion of transportation routes) and the development of the internal energy market (in respect of energy efficiency improvement, 1

2

Sebastian Radocea has wide-ranging experience in energy law (with a focus on the power and energy-efficiency sectors), M&A and corporate/commercial law. He is currently advising on the first-ever implementation in Romania of energy efficiency projects in the public sector, while having previously acted on some of the country’s highest-profile deals, such as the first unbundling of the power distribution and supply activities of a former State-owned utility, the acquisition by the largest utility company in Central and Eastern Europe of a minority stake in two power distribution and supply companies, and the development of the largest onshore wind farm project located in Romania. As set out in the National Reform Programmes in April 2014, available at http://ec.europa.eu/ europe2020/pdf/targets_en.pdf

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the extension of the renewable energy sector and the development of new technologies). The National Energy Efficiency Action Plan3 provides for energy efficiency improvement objectives and proposes complementary measures. The Plan recognises the imperative of energy savings actions being oriented towards the sectors with the highest potential to reduce final energy consumption, namely buildings (41.5 per cent, up to 60 per cent in public lighting), transportation (31.5 per cent), industry (13 per cent) and services (14 per cent). In 2014, the domestic legal framework was completed with the entry into force of Law No. 121/2014 on energy efficiency,4 which transposes the Energy Efficiency Directive No. 2012/27/UE into national law. Nonetheless, the legislation seems insufficient, as highlighted by the European Commission in the 2015 Romania Country Report,5 which shows that Romania’s progress on energy efficiency is limited, mainly due to the lack of tangible measures and insufficient work on effective transposition of the Energy Efficiency Directive. The Report indicates that all these drawbacks may eventually preclude Romania from achieving its energy efficiency potential and hinder its economic performance. BARRIERS IN ENERGY PERFORMANCE CONTRACTING FOR PUBLIC BUILDINGS In principle, an energy performance contract (EnPC) is regarded as a services contract under which the energy services company (ESCO) guarantees the beneficiary (the public authority) that, on the basis of certain implemented energy efficiency measures, it will reach a contractually agreed percentage of energy savings over the duration of the contract. In exchange for such an undertaking by the ESCO, the beneficiary agrees to pay periodic service fees representing a percentage of the generated savings (with the consequence that, if the savings are not achieved, the payment shall be reduced correspondingly). In principle, such a contractual structure would help public authorities improve the energy efficiency of their buildings without making expenditures from their budget. Why, then, is the EnPC model still not used in Romania? First, a background check shows that most Romanian public buildings are in need of more substantial improvements than energy efficiency. Usually, these include renovation and refurbishment measures, in the absence of which the energy savings would be much less effective. Hence, as a prerequisite to entering into such contracts, Romanian public authorities have requested that, in addition to the energy efficiency measures, the ESCOs should also carry out renovation and refurbishment works that normally have little energy-saving potential. Since the implementation of such measures makes it impossible for

3

4 5

The National Energy Efficiency Action Plan, approved by Government Decision No. 122/2015, published in the Official Gazette of Romania I (169), 11 March 2015. Published in the Official Gazette of Romania I (574), 1 August 2014. Country Report Romania 2015, COM(2015) 85 final, 77, available at http://ec.europa.eu/ europe2020/pdf/csr2015/cr2015_romania_en.pdf

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the beneficiary to ensure that the value of the investment is repaid within a reasonable contractual term (such as ten to twelve years), the only trade-off remains that the beneficiary (that is, the public authority) co-finances any such investment. Contributions of this sort would be paid to the ESCO in addition to the agreed percentage from savings, throughout the contractual term. At this point, the legal difficulties commence. As regards the investment paid by the ESCO (that is, the value of the capital expenditure) for the implementation of the energy-efficiency measures, in consideration of Eurostat’s recently released Guidance Note on the impact of energy performance contracts on government accounts,6 this is likely to be considered as having an impact on public debt. The effect of this is that the EnPC would represent an instrument of public debt (even if it is not explicitly listed among public debt instruments by the applicable Romanian public finance legislation), triggering two main consequences, namely the necessity to obtain the approval of the Commission for the Authorisation of Local Loans (in Romanian, Comisia de autorizare a împrumuturilor locale), which is the body authorising the undertaking of public debt-related obligations by local authorities, as well as the obligation for the amounts to be paid under the EnPC to observe a public indebtedness threshold of 30 per cent of the average revenues of the previous three years7 of the respective public authority. Both of the above may prove to be insurmountable barriers for the contracting of energy efficiency services, since the activity of the above Commission is not always consistent or predictable and the level of indebtedness of many authorities has already reached the maximum threshold. Even though the representatives of the Ministry of Finance have informally admitted that an EnPC is not a standard public debt instrument, especially because the payments thereunder are conditioned by the actual performance of the energy efficiency services by the ESCO and the achievement of the guaranteed energy savings (with the corollary that, in case the ESCO fails to perform, no payment shall be made by the public authority), the official position of the Ministry has nonetheless been that the rules of public debt shall be observed by EnPCs in the absence of specific provision for such agreements in the current public finance legislation. The arguments backing such a position have been largely the same as those outlined in Eurostat’s Guidance Note. It is worth mentioning that the Guidance Note specifies a series of tests8 on the basis of 6

7

8

The Guidance Note of Eurostat on the impact of energy performance contracts on government accounts was released on 7 August 2015. This is calculated according to a formula provided under Government Emergency Ordinance No. 64/2007 on public debt, published in the Official Gazette of Romania I (439), 28 June 2007, as further amended. Very briefly, these tests are the following: (1) the so-called ‘50 per cent rule’ (which states that the total value of capital expenditure for improving energy efficiency should reach at least 50 per cent of the value of the respective public building after completion of the renovation works); (2) the proportion of government financing in the total amount of capital expenditure (whereby the capital expenditure would qualify as public debt if the majority of the funds – that is, more than 50 per cent – would come from government resources); and (3) the allocation of the risks (mainly of the so-called ‘availability risk’) between the contracting parties – if these risks (and related rewards) are transferred contractually to the ESCO, then the EnPC would not qualify as public debt.

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which it might be determined whether the capital expenditure incurred with the implementation of the energy-efficiency measures has an impact on public debt or not. However, after listing these tests, the Guidance Note concludes that it might be difficult for the competent public authorities9 to undertake a case-by-case analysis of all individual EnPCs and, therefore, as a practical rule, it considers that all capital expenditure incurred in the context of EnPCs should be treated, by default, as impacting public debt. Such a priori classification of EnPCs as public debt instruments might leave room for abusive interpretations of EnPCs by the competent public bodies. A qualification as public debt instruments of EnPCs in the absence of an individual (and thorough) analysis of their contractual clauses might make it impossible for many municipalities to implement energy efficiency projects due to them already reaching the aforementioned public indebtedness threshold. Another issue is related to the payment mechanism under an EnPC. On one hand, the principle is that the equipment incorporated in the public buildings becomes an integral part thereof by operation of law. Therefore, the transfer of the ownership rights over such assets shall take place at the latest at the acceptance of the implementation works by the beneficiary. From the perspective of the applicable tax legislation, this is the moment when the ESCO should issue an invoice for the price of the implementation works (which, as a matter of local practice, exceeds 50 per cent of the total contract value). On the other hand, the maximum value of the advance payments that public authorities can make under a contract of this kind amounts to no more than 20 per cent of the contract value.10 In an attempt to overcome such a legislative barrier, one may propose that the invoice corresponding to the price of the implementation works shall be partially paid upfront (that is, observing the maximum 20 per cent threshold) and partially rescheduled throughout the contract term in instalments, which shall also be incorporated in the regular (usually monthly) service payment. While such a payment mechanism might be seen as burdensome by the ESCOs and might also limit the volume of the implementation works included in the scope of an EnPC, from a practical standpoint it may even not be validated by the Romanian tax authorities, since representatives of such bodies have informally opined that invoices due for payment by public authorities may be prohibited from rescheduling. This stems from a rather conservative interpretation of the Romanian legislation combating late payment in commercial transactions between private partners and public authorities.11 We are still waiting for a solution from the Ministry of Finance for the accommodation of the above legal mechanisms. However, in a context in which the 9

The national statistical institutes of EU member states are the authorities having power to analyse EnPC and assess whether such contracts impact public debt or not. 10 Government Decision 264/2003 regarding advance payments from public funds, republished in the Official Gazette of Romania I (109), 5 February 2004, as further amended. 11 Law No. 72/2013 on combating late payment in commercial transactions between undertakings or between undertakings and public authorities, published in the Official Gazette of Romania I (182), 2 April 2013. This law implements Directive 2011/7/EU of the European Parliament and of the Council of 16 February 2011 on combating late payment in commercial transactions.

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Romanian authorities are extremely sensitive to any potential public debt increase, they may refrain from issuing a straightforward decision favouring a more EU law-aligned interpretation of the matter at hand. The above examples of legislative barriers and the approach of the relevant authorities lead us to believe that an intervention of policy-makers is urgently needed to establish a more practice-oriented legislative process when it comes to EnPCs. Any delay in this regard will slow the development of the ESCO market in Romania, which would otherwise have enormous growth potential and positive economic implications. Such delay may jeopardise the country’s achievement of the energy efficiency targets for 2020. But does Romanian legislature understand the difficulties in the implementation of an EnPC structure and is it – or will it become – sufficiently knowledgeable of the statutory reforms implemented in other EU member states to overcome such difficulties? We only hope that the European Commission recommendation for Romania ‘to improve and streamline energy efficiency policies’,12 as well as the recently commenced infringement procedure related to the full transposition of the Energy Efficiency Directive,13 will lead the government to focus on the topic in order to promote much needed legislative improvements and avoid the sanctions to which Romania would be exposed in case of failure to reach its energy consumption reduction targets.

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Country Report Romania 2015, COM(2015) 85 final, 75–8, available at http://ec.europa.eu/ europe2020/pdf/csr2015/cr2015_romania_en.pdf 13 The infringement procedure was initiated against a number of EU member states, including Romania, in April 2015. For more information, see http://ec.europa.eu/energy/node/2507

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ENERGY LAW IN THE CZECH REPUBLIC: ‘UNBUNDLING’ ČEZ Michael J. Allen1

INTRODUCTION This chapter will examine the Czech Republic’s implementation of the recent EU Third Energy Package and the resulting legal problems that have arisen. A case study of the dominant Czech energy utility, ČEZ,2 will specify the details of such problems3 and, furthermore, will allow the author to reflect and conclude on the wider European situation concerning this important energy law topic. BACKGROUND ON ENERGY IN THE CZECH REPUBLIC The Czech Republic is in the top five of the largest net electricity exporters in the European Union and, moreover, has a highly integrated wholesale market dynamic with neighbouring Central and Eastern European countries. In general, this close relationship creates high market discipline in the energy sector, especially concerning electricity. A current Organization for Economic Co-operation and Development (OCED) report4 suggests that to avoid cross-subsidisation, the regulators demand strict cost reporting concerning each regulated energy activity. However, despite this ‘tight regulation’, the difference between pre-tax industrial prices for energy (particularly electricity) and post-tax prices reveal that the state purse is making up for lack of competition. 1

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Michael J. Allen LLM is an independent researcher currently based in Prague. His research interests are in energy law, particularly issues concerning nuclear energy and, in particular, nuclear waste. Other areas of interest include renewable energy, energy justice, and environment and business transactions. His legal research focuses on the European and USA energy sectors. Skupina ČEZ České Energetické Závody. Note that it will focus on electricity only. OECD, Economic Surveys: Czech Republic (OECD Publishing, 2014), available at http://dx.doi. org/10.1787/eco_surveys-cze-2014-en

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THIRD ENERGY INITIATIVE OVERVIEW – UNBUNDLING Almost all energy utilities have been vertically integrated at some point in their history. Due to the long communist era in the Czech Republic, this was the case for all current energy utilities. Therefore, all parts of the energy supply industry – production, transmission and distribution – were controlled by the same company, without any competitive features. The legal and economic position during these periods was that production, generation and distribution needed to be closely tied, both legally and economically, in order to achieve the best investment- and production-related decision-making and, furthermore, to negate unwanted transaction costs. In this era, competition was not of importance and, in fact, the electricity market was organised as a monopoly. At the end of the 1980s, electricity production (and energy production in general) shifted from being a somewhat ‘natural monopoly’ into the competitive market, due to alterations in economic rationale. Thus, the legal and economic dynamic between electricity production, transmission and distribution has dramatically changed. Furthermore, this has brought wide-scale change to the legal architecture of the energy market in the EU, leaving countries such as the Czech Republic with serious legal complications. The main EU legal change has been the ‘unbundling’ of energy companies. Unbundling is the key legal tool that the EU has created in order to construct a single market in electricity and gas. Unbundling was created as part of the Third Energy Package (EU Directive 2009/73/EC). The three core forms of unbundling are the following: 1. Ownership unbundling: production and transmission must be owned by separate entities and these entities are not allowed to have shares in both. 2. Legal unbundling: production and transmission must be put into separate legal entities. 3. Accounting unbundling: separate accounts must be used for the production and transmission/distribution activities to negate crosssubsidisation. The main legal issues have arisen due to a lack of understanding of how companies should implement these forms of unbundling and if certain companies should have to adopt the stricter form – ownership unbundling. However, the latest directive has been largely a success throughout the EU and only a few select countries have encountered major problems with enforcement from the EU Commission, including the Czech Republic. CZECH CASE STUDY: UNBUNDLING ČEZ Vertical integration of energy utility companies can hinder competition. The Czech Republic’s monopoly-like ČEZ utility company provides an ideal practical case study to review this key issue.

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Overview of ČEZ ČEZ is the largest energy company in Central and Eastern Europe and has become famously controversial for political, economic and legal reasons. For example, recent vast changes to its supervisory board since Andrej Babis, new finance minister and billionaire founder of a new populist political party, came into position has created many tensions surrounding the 70 per cent state-owned company, which is the biggest cash source for the new coalition government’s spending budget (approximately €546 million).5 Czech analysts have commented that the finance minister’s sweeping takeover of ČEZ’s supervisory board came as a surprise, as he had disregarded the unwritten law that all political parties from the governing coalition must be represented. However, one of the governing coalition parties, the Christian Democrats, are without a board member, whereas Babis’s own party, ANO, has six. In addition, ČEZ has created much controversy domestically with investment plans, especially the dramatic tender for a €10 billion expansion of the Temelin nuclear power plant. ČEZ cancelled the tender to expand the Temelin nuclear plant due to economic and legal problems. The government finally concluded that it would not offer any public support due to both economically viability and European state-aid laws.6 Unbundling ČEZ The main problem in the Czech Republic regarding ČEZ and unbundling, which reflects the major legal issue with vertical integration overall, is that when independent producers enter the electricity market and begin to compete with the incumbent they cannot deliver their electricity to end-consumers (both industrial and private) without the services from the transmission and distribution parts. Therefore, when the incumbent controls the transmission and distribution networks (as ČEZ does), new entrants to the energy market can be denied full access to the necessary network services. Thus, the incumbent still contains the characteristics of a monopoly due to its ability to control the network side of the market in order to better control the unregulated production side. For example, ČEZ’s domination of final electricity consumption in the Czech Republic is 95 per cent. Whereas many countries opted for the stricter ownership unbundling, the Czech Republic instead selected the weaker legal unbundling in order to abide by the new EU Energy Directive. This weaker unbundling choice means that ČEZ is able to continue to influence the energy market (especially electricity) in

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D. Binar and N. Watson, ‘CEZ board changes reflect rise of finance minister’, The Financial Times (30 June 2014), available at http://blogs.ft.com/beyond-brics/2014/06/30/cez-board-changes-reflect -rise-of-finance-minister T. Gosling, ‘Czech Republic’s CEZ finally pulls plug on nuclear tender, The Financial Times (10 April 2014), available at http://blogs.ft.com/beyond-brics/2014/04/10/czech-republics-cez-finallypulls-plug-on-nuclear-tender

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a non-competitive manner.7 As stated, ČEZ continues to dominate production, which has allowed major influence on prices in certain supply-and-demand situations, particularly concerning capacity. The European Commission began investigating ČEZ due to these dominance-related anti-competitive issues, that is, blocking new entrants and controlling production levels. In 2012, ČEZ agreed to stop the legal complication escalating into court action by agreeing to specific commitments set by the EU Commission, which included the forced sale of generation assets.8 ČEZ continues to battle complaints from European and international institutions, including the World Bank, concerning its current competition standing. Such repetitive external legal scrutiny regarding the Czech implementation of the Third Energy Package and construction of a single energy market reflects poorly on the domestic competition regulators due to their weak oversight. However, as with many states, energy problems are plentiful and many of the reasons behind ČEZ’s structure and competition standing are due to complex historical legal problems relating to restriction on privatisation post-communism in the early 1990s, environmental laws and decrees also dating from the 1990s, energy mix and security problems and so on. CONCLUSIONS The Czech Republic’s issues with the new EU Energy Directive illustrate for the rest of Europe that the European Commission is making every effort to back the EU’s push towards a single energy market for the good of EU business and citizens.9 EU institutions will continue to back ownership bundling and, moreover, will be happy to balance this against ‘fundamental freedoms’, that is free movement of capital. Ultimately, this chapter shows that the EU is making an effort to create laws and initiatives to construct a transparent and competitive energy market as well as investment in better infrastructure, especially for electricity and gas (which are heavily attached to the vertical past).

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The World Bank, SE4ALL Global Tracking Framework Report (2013), available at5 www.worldbank.org/en/topic/energy/publication/Global-Tracking-Framework-Report European Commission, ‘Antitrust: Commission accepts commitments from CEZ concerning the Czech electricity market and makes them legally binding’ (2013), available at http://europa.eu/ rapid/press-release_IP-13-320_en.htm See also the ECJ Dutch case, available at www.energypost.eu/eu-court-upholds-primary-importanceinternal-energy-market

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DELIVERING ENERGY POLICY REFORM IN UKRAINE: LEGAL ISSUES IN THE LIGHT OF EUROPEAN INTEGRATION Yuliya Vashchenko1

Energy policy is one of the key aspects of the national policy of Ukraine in relation to European integration. Ukraine, as a fully fledged member of the Energy Community, is obliged to implement core EU energy legislation. The obligations regarding the implementation of the main requirements of EU energy legislation are stipulated by the EU-Ukraine Association Agreement. The successful transposition and implementation of EU energy legislation depends on the efficiency of the competent public authorities in Ukraine. However, the system of public administration in Ukraine (including the system of competent authorities in the energy sphere) needs to be reformed taking into consideration European principles of good administration and this is an area in need of legal scholarship. This paper aims to analyse the legal issues involved in the Ukrainian system of public administration in the energy sphere with regard to European integration and to provide recommendations regarding its enhancement. Different state bodies have competences regarding the development and implementation of energy policy in Ukraine. The general framework of energy policy is defined by the Parliament of Ukraine (Verkhovna Rada of Ukraine; hereafter ‘the VRU’). The President of Ukraine also has competences in the 1

Yuliya Vashchenko received her LLM in 1999 and her PhD in 2003 from Taras Shevchenko National University of Kyiv, Ukraine. Since 2003, she has been an Associate Professor of the Administrative Law Chair of the Faculty of Law at Taras Shevchenko National University of Kyiv. Her fields of expertise include administrative and regulatory law, energy law and human rights law. She is author of over seventy scientific publications and actively participates in drafting energy legislation in Ukraine.

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energy sphere. In particular, he or she signs energy laws approved by the VRU, has a right of veto regarding such laws, approves decrees in energy issues and encourages energy security. The President has significant competences regarding energy regulation since he or she establishes and may close down the National Commission for State Energy and Public Utilities Regulation (hereafter referred to as ‘the energy regulator’). The President also appoints and dismisses the chairpersons and members of the energy regulator, as well as approving the regulations governing its activities. Moreover, the energy regulator is subordinate to the President of Ukraine. However, the constitutionality of the competences of the President of Ukraine regarding the energy regulator has been discussed by scholars.2 The development and realisation of the energy policy of Ukraine is conducted by the Government of Ukraine (hereafter GOU), sectoral ministries and other state bodies of executive power according to their competences. However, the system of national authorities in the energy sector is not stable due to the frequent changes in the system of public administration in Ukraine and it needs to be reformed in order to be able to operate efficiently. This problem can be illustrated by the situation relating to the implementation of EU energy legislation. For instance, Directive 2010/31/EU of the European Parliament and the Council of 19 May 2010 on the energy performance of buildings (hereafter referred to as ‘the Directive’) comprises a significant part of the EU energy legislation to be implemented in Ukraine. Considering the experiences of EU member states, there are different ways of transposing the Directive. First, special provisions can be included in the general laws on construction (for instance, the Estonian Law on Construction) or energy efficiency and energy saving (for instance, the Croatian Act on Efficient End-use of Energy). Second, special separate law on the energy performance of buildings can be approved (for instance, the Slovakian Act on the Energy Performance of Buildings). The second model has been chosen in Ukraine. Ukraine started the preparation of a draft law on the energy performance of buildings since 2009. Different versions of this draft law were considered by the VRU. The last version (developed by the Ministry of Regional Development, Construction and Housing and Communal Economy of Ukraine (hereafter Minregion)) was considered by the VRU on 13 January 2015 and it was decided that it should be returned to the GOU for improvement. All these attempts were unsuccessful for different reasons. However, the lack of understanding of the requirements of the Directive among officials together with the lack of concrete mechanisms for the improvement of the energy performance of buildings are common features. These weaknesses of the system of public administration are one of the main reasons for the lack of progress. In accordance with the Regulations on the Ministry of Economic Development and Trade of Ukraine, as approved by GOU Regulation N459 of 20 August 2014, this Ministry is the main state body responsible for the development of 2

Yuliya Vashchenko, ‘Energy regulator in Ukraine: legal aspects of the independence in the light of the EU requirements’, Jurisprudence 21(1) (2014), 185–203.

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policy on the efficient use of fuel and energy resources, energy saving, renewables and alternative fuel types. However, the same tasks can be found within the competences of the Minregion according to the Regulations approved by the GOU Regulation N197 of 20 April 2014. The Minregion has recently obtained these competences in accordance with the amendments to the Regulations approved by GOU Regulation N690 of 26 November 2014. Thus there is a conflict of competences regarding the development of state policy. This conflict can also be detected in the implementation of state policy. There is a special authority responsible for this activity – the State Agency on Energy Efficiency and Energy Saving of Ukraine (hereafter referred to as ‘Agency’). This Agency is empowered to implement the state policy that has been developed by the competent ministry and its activity is determined and coordinated by the GOU through the competent minister. In accordance with the Regulations on the Agency approved by the GOU, the activity of the Agency is determined and coordinated by the GOU through the Deputy Prime Minister of Ukraine – the Minister of Regional Development, Construction and Housing and Communal Economy of Ukraine. However, there is another set of Regulations on the Agency approved by Decree of the President of Ukraine N462/2011 of 13 April 2011 that prescribes that the activity of the Agency is determined and coordinated by the GOU through the Minister of Economic Development and Trade of Ukraine. The President of Ukraine may annul his Decrees on Regulations on the Ministry of Economic Development and Trade and the Agency mentioned above in order to end this conflict of competences since the responsibilities to establish and close down central bodies of executive power have been transferred from the President of Ukraine to the GOU according to Law of Ukraine ‘On Revival of Some Provisions of the Constitution of Ukraine’ N742-VII of 21 February 2014. However, it should be stressed that there is a special ministry for the fuel and energy complex of Ukraine – the Ministry of Energy and Coal Industry of Ukraine (hereafter Minenergo). According to the Regulations approved by Decree of the President of Ukraine N382/2011 of 6 April 2011, Minenergo is the main authorised body in relation to policy development and implementation for the fuel and energy complex. It is obvious that the energy efficiency, energy saving and renewables policy is part of the general energy policy. The Energy Strategy of Ukraine for the period up to 2030 approved by Regulation of the GOU N1071-p of 24 July 2013 includes provisions regarding the development of the state policy in the sphere of energy efficiency and Minenergo is the main body responsible for the implementation of this strategy. Energy efficiency, energy saving and renewables policy issues are considered within the general energy policy by the VRU since the Committee of the VRU in the matter of fuel and energy complex, nuclear policy and nuclear safety includes the Subcommittee in the matter of energy saving and energy efficiency, as well as the Subcommittee in the matter of nonconventional and renewable energy sources. In conclusion, it is recommended that Minenergo should become the main state body for energy policy (including energy efficiency, energy saving and

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renewables policy) development and implementation. Therefore, the activity of the Agency should be determined and coordinated by the GOU though the Minister of Energy and Coal. In addition, there is no separate legal act on the legal framework for the energy policy in Ukraine. The principles of state policy as well as the main competences of authorised state bodies are stipulated by the laws that regulate relations in concrete energy sectors and are specified by the regulations. In order to define the general legal and organisational principles of the government in the energy sphere, it is recommended that a separate special law – the Law of Ukraine ‘On Framework for Energy Policy of Ukraine’ – should be developed.

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A SYSTEMIC APPROACH TO RENEWABLE ELECTRICITY TECHNOLOGY DEPLOYMENT: THE ‘MISSING LINK’ IN OPTIMISING POLICY DELIVERY IN THE UK? Geoffrey Wood1

INTRODUCTION By early 2014, most countries had renewable energy targets and support policies in place, with policy support and investment in renewable energy continuing to focus primarily on the electricity sector.2 The United Kingdom is no exception, with the government committed to challenging renewable energy and climate change targets for 2020 and beyond.3 Resulting in the need to expand renewable electricity technology (RET) capacity, policy, legislative and regulatory activity ‘has increased almost breathlessly’ with an unprecedented increase in the pace and breadth of government involvement and action since privatisation in the early 1990s.4 This has led to a renewed urgency to analyse and understand the policy and legal interventions in terms of policy delivery.5 1

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Dr Geoffrey Wood is a Teaching Fellow in International Energy Law and Policy at the School of Law, University of Stirling and a contributing lecturer at the University of Dundee. His work focuses on legal and governance frameworks for renewable, low-carbon and transition energy (such as shale gas) technology deployment, with emphasis on interdisciplinary research. Renewable Energy Policy Network for the 21st Century, ‘Renewables 2014: global status report’, available at www.ren21.net/portals/0/documents/resources/gsr/2014/gsr2014_full%20 report_low%20res.pdf Department for Energy and Climate Change, Renewable Energy Strategy 2009, Cm 7686 (2009), 8. P. Pearson and J. Watson, ‘UK energy policy 1980–2010: a history and lessons to be learnt – a review to mark 30 years of the Parliamentary Group for Energy Studies’, 2, available at http://sro. sussex.ac.uk/38852/1/uk-energy-policy.pdf R. Heffron, A. Johnston, D. McCauley and K. Jenkins, ‘Policy delivery for low carbon energy infrastructure in the UK, April 5th 2013: Conference overview’, Energy Policy 61 (2013), 1367–9.

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A key debate with regard to government intervention focuses on the approach adopted by governments to overcoming barriers to RET deployment. This chapter seeks to contribute to the debate by questioning the underlying rationale of the conventional approach adopted by the UK government to addressing deployment barriers. Further, by arguing that a re-evaluation of the way in which barriers are resolved is crucial in order to optimise the effectiveness of policy delivery, this chapter proposes an alternative approach. AN IMPERFECT WORLD Despite over two decades of government support for renewable electricity and some of the best resources in Europe, the UK has consistently under-performed against targets and other policy objectives.6 UK efforts continue to lag behind other nations and the Renewables Obligation (RO) is being replaced by the new Contracts for Difference feed-in tariff (CfD FIT) as the primary mechanism to support RETs. There are a number of well-documented constraints that act as barriers to RET deployment. These are categorised here as either internal or external failures, in the sense that barriers hinder RET deployment by preventing, limiting or delaying capacity coming online and increasing the cost of deployment.7 Internal failures are barriers due to the design of the financial subsidy mechanism used to promote renewable deployment. This category includes the type of promotional mechanism and how it operates, for example, what impact does the mechanism have on revenue and investment (lender) risk, mechanism operational longevity (subsidy programme and/or subsidy duration), subsidy levels and mechanism complexity. External failures are those barriers outwith the direct control of the mechanism, including planning, electricity grid, public participation and engagement and policy risk. While there are multiple potential solutions to addressing barriers, the typical government response to such constraints operates on the implicit assumption that each failure, once determined, can be effectively addressed with its own elegant solution in isolation.8 Resulting in incremental ‘bolt-on’ adjustments or reforms aimed at a particular failure, this approach fails to understand that constraints interact with each other to exacerbate the impact of the constraint(s) systemically. Baker and others point out the major concern with this approach: In a perfect, first-best world, it should be possible to address and optimise individual elements of energy policy in isolation, with confidence that the overall policy outcome would also be optimised. However, the 6

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G. Wood and S. Dow, ‘What lessons have been learned in reforming the Renewables Obligation? An analysis of internal and external failures in UK renewable energy policy’, Energy Policy 39 (2011), 2228–44. Ibid. G. Wood, ‘Connecting the dots: A systemic approach to evaluating potential constraints to renewable electricity technology deployment to 2020 and beyond in the United Kingdom’ (PhD thesis, University of Dundee, 2013), 202, 258.

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world is not perfect and measures designed to deliver desired outcomes in particular policy areas may lead to distortions in other areas, with a consequent need for compensating action’.9 This is illustrated in the UK context by the following examples of key problems arising from the UK government’s approach to addressing the failures.10 Reforms to the planning system appear to offer such an elegant solution to increasing capacity. However, increasingly centralising decision-making at the ministerial level and limiting public opportunities to engage in the process runs the risk of the inappropriate siting of developments and aggravating planning issues and public opposition by disenfranchising communities through reducing public participation and engagement. In addition, by not taking into account the different requirements and characteristics of community and meso-scale projects, the planning system also militates against such developments despite evidence that they can alleviate such concerns, change public behaviours and attitudes towards energy and facilitate RET deployment.11 Reforms to the subsidy mechanism face similar problems. If appropriately designed, replacing the RO with the CfD FIT mechanism should address the main internal failure of revenue risk by offering guaranteed revenue in contrast to the uncertainty of leaving the key revenue streams dependent on supply and demand (renewable electricity and electricity sales). However, with the potential exception of investment risk (by alleviating revenue uncertainty), this will not address the remaining internal failures and ignores the external failures. The current UK approach is also closely linked to the idea of the primacy of market solutions to addressing the barriers to RET deployment. It is based on a de facto dominance of economics, with deployment incentivised through an emphasis on the economic efficiency of the subsidy mechanism. However, blanket reductions in subsidy on gross technology bands irrespective of the scale of deployment or developer type favours large companies and developments that can gain from economies of scale and are better placed to manage and absorb risks and associated costs. An additional consequence is that by leaving technology choice to the market, it promotes less expensive, commercial or near-commercial RETs (those receiving higher subsidy rates that can deploy at scale) whilst virtually excluding more expensive, less market-ready options that can bring additional systemic benefits including technologies that are less contentious to the planning system and/or could be located closer to existing 9

Philip Baker, Catherine Mitchell and Bridget Woodman, ‘Project TransmiT: academic review of transmission charging arrangements: final report, April 2011’, 5, available at http://geography. exeter.ac.uk/catherinemitchell/FINAL_PDF_Baker_et_al_to_Ofgem.pdf5 (emphasis added). 10 Wood, ‘Connecting the dots’, 202, 258. 11 C. Warren and M. McFadyen, ‘Does community ownership affect public attitudes to wind energy? A case study from south-west Scotland’, Land Use Policy 27 (2010), 204–13; C. Haggett, E. Creamer, J. Harnmeijer, M. Parsons and E. Bomberg, ‘Community energy in Scotland: the social factors for success’, ClimateXChange (2013), available at www.climatexchange.org.uk/ files/4413/8315/2952/CXC_Report_-_Success_Factors_for_Community_Energy.pdf

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grid infrastructure, with implications for planning, grid and public participation issues. Another example is that both the RO and the CfD FIT are complex mechanisms in terms of design, administration and the level of knowledge and expertise required to operate within the mechanism, with the latter arguably more so. This favours large companies over independent generators and community projects through their ability to manage the complexity with in-house expertise or the ability to pay for it. These examples are broad snapshots of the systemic interactions of the barriers; systemic interactions occur at many levels, from broad to narrow interactions. The main point is that efforts to address a particular constraint without taking into account systemic interactions could lead to aggravating other barriers to the extent that they result in sub-optimal deployment levels than would otherwise be achieved. The implications of the current approach is that there are significant systemic interactions between the internal and external failures (internal > internal; external > external; and internal > external and vice versa). There are also a number of feedbacks, specifically between grid > planning and public participation and engagement > planning. This creates systemic imbalances and unresolved tensions between the constraints. Importantly, decisions will be made on a separate ad hoc basis leading to further and continual reform and adjustment with less clarity of where the risks lie. By not addressing the failures from a systemic perspective, the UK approach has discriminated in favour of a system highly dependent on large-scale developments, of a few select RETs (primarily wind power and biomass) by a limited number of developers of a particular type (typically ex-utility, large-scale). This limits the focus on social and behavioural issues, particularly in terms of participation and engagement in ownership, decision-making and reducing the role of small-scale, independent and community participation. Increasing deployment year by year in order to meet the targets will only accumulate and intensify the systemic failures with limited options to address this. Effectively, government can only buy or control its way out of the constraints. CONNECTING THE DOTS The systemic approach offers an alternative method to addressing barriers to RET deployment that counters the deficiencies of the current approach. Derived from systems theory,12 and later with the development of systems thinking,13 it incorporates the key tenets of the interdependence of objects and their attributes and holism, providing the ability to reveal emergent properties not possible to detect by other types of analysis.14 By acknowledging that fully understanding why a problem occurs and persists can only be realised by understanding the parts in relation to the whole, the strength of the systemic 12

L. von Bertalanffy, General Systems Theory: Foundations, Development, Applications, 2nd edn (George Braziller Inc., 2003). 13 B. H. Banathy, Guided Evolution of Society: A Systems View (Kluwer Academic/Pleneum Press, 2000). 14 Ibid.

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approach is that it unifies and concentrates on the interaction between the failures and the government’s initiatives to address them. By studying the effects of interactions, it avoids the typical response to such constraints embodied by the current approach and permits both the teasing out of the systemic interactions of the individual internal and external failures and the evaluation of the current method to addressing them. Importantly, the systemic approach understands problems in a contextual framework. In order to provide a valid evaluation of the barriers there are two criteria that must be met. This is critical to ensure that any analysis is rigorous, credible and transparent. Firstly, the set of constraints included in the internal and external failures approach needs to be comprehensive.15 The internal and external failures have to at least capture the significant constraints that affect such deployment. Secondly, the constraints should be examined in sufficient and equal depth of analysis; it is not enough to mention potential constraints without proper investigation and analysis. These two criteria permit the capture of the systemic interactions between the barriers. There are a number of distinct advantages to the systemic approach. By providing an overview of the system and identification of systemic interactions in an early and novel way, it provides policy makers with the ability to make decisions at the systemic or system-wide level and take into account the systemic interactions of the potential constraints on different RETs. Leading to more predictable routes to solving problems, this should result in the need for fewer interventions in comparison to the current government approach, thus mitigating risks to a greater extent. Further, the systemic approach offers the opportunity for deliberate and pragmatic decision-making at the systemic level that helps to redefine the system in a more optimal and resilient way by relieving inherent tensions between the barriers. In other words, it allows government to connect the dots in addressing barriers to deployment. This chapter offers a novel systemic approach to policy-makers based on a comprehensive and detailed analysis of the barriers to RET deployment in the UK. By determining the complex web of interactions between the constraints in order to provide systemic solutions this approach permits a reassessment of the effectiveness of policy delivery at the systemic level allowing a more accurate understanding of the approach that government will need to adopt in order to enhance policy delivery to increase deployment to meet renewable, climate change and other policy goals and successfully meet the 2020 target.

15

Although there are other barriers not included in the internal and external failures, including intermittency and resource availability, the critical distinction is that these barriers affect the operability of RETs within the wider electricity system and not the actual deployment of the technologies.

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DELIVERING ENERGY POLICY: IS THERE NEED FOR KEY CHANGES IN THE NEXT UK PARLIAMENTARY PERIOD? Chris Eaglen1

The aim of this short chapter is to question whether Parliament should change the UK electricity generation project requirements to provide for the greater replacement of the ageing fleets of UK power stations. This will reduce deliver risks and provide at more affordable cost, with a shorter programme and more dependable performance certainties for the construction of multiple coal power stations and multiple gas power stations at coastal sites, in preference to the currently planned nuclear projects. The focus will be on the new-build fossilfuelled generation within the current Parliament, with reappraisal and reduction of the nuclear new-build reactor option for the next decade. The UK can then decide from the actual performance and issues with the EPR reactors in France and Finland and from other reactor designs, including the South Korean APR-1400. Using a Central Electricity Generating Board (CEGB) structure as with Crossrail, a new organisation can be established to form, manage and deliver the replacement electricity generation mega-projects needed now. Accountable for the UK government’s capital allocations from 2015, this structure will deliver jobs and a vital programme. Table 98.1 lists the projects within the scope of the Planning Inspectorate considerations in December 2014 and the list provides evidence of the range of ownership and the scale and diversity of 1

Chris Eaglen is an engineer engaged in nuclear and infrastructure projects and their procurement. Chris’s research interests are in energy, environmental, contract law and policy, and in particular electricity generation and distribution infrastructure, nuclear and fossil fuel power engineering, as well as organising manufacturing, fabrication and construction capability contract arrangements.

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Table 98.1 Planning inspectorate projects, December 2014 Project

Developer

Abergelli Power

Abergelli Power Limited

Able Marine Energy Park

Able Humber Ports Ltd

Alexandra Dock Biomass Project

RES UK & Ireland

Avon Power Station 950 MW output

Scottish Power

Bramford to Twinstead Overhead Line

National Grid

Brechfa Forest Electricity Connection

Western Power Distribution (South Wales) plc

East Northants Resource Management Facility

Augean PLC

Ferrybridge Multifuel 2 (FM2) Power Station

Multifuel Energy Ltd

Hinkley Point C Connection

National Grid

Hinkley Point C New Nuclear Power Station

NNB Generation Company Limited

Hirwaun Power Station

Hirwaun Power Limited

Internal Power Generation Enhancement for Port Talbot Steelworks

Tata Steel UK limited

Keuper Gas Storage Project

Keuper Gas Storage Limited

Killingholme Energy Centre

Killingholme Energy Limited

King’s Lynn B Connection Project

National Grid

Knottingley Power Project

Knottingley Power Limited

Meaford Energy Centre

Meaford Energy Limited

Mid Wales Electricity Connection (N Grid)

National Grid

Millbrook Power

Millbrook Power Limited

North Killingholme Power Project

C.GEN Killingholme Ltd

North London (Electricity Line) Reinforcement

National Grid

North London Heat and Power Project

North London Waste Authority

North Wales Connection

National Grid Electricity Transmission Plc

North West Coast Connections Project – N Grid

National Grid

NuGen’s Moorside Project in West Cumbria

NuGeneration Limited (‘NuGen’)

Oldbury New Nuclear Power Station

Horizon Nuclear Power

Palm Paper 3 CCGT Power station King’s Lynn

Palm Paper Ltd

Port Blyth New Biomass Plant

North Blyth Energy Ltd

Port of Southampton Biomass Energy Plant

Helius Energy

Preesall Saltfield Underground Gas Storage

Halite Energy Group Ltd

Progress Power Station

Progress Power Limited

Richborough Connection Project

National Grid

River Humber Pipeline Replacement Project

National Grid Gas plc

Rookery South Energy from Waste Generating Station

Covanta Rookery South Limited [Continued

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Table 98.1 Planning inspectorate projects, December 2014 (continued) Project

Developer

Seabank 3 CCGT

SSE plc

Sizewell C New Nuclear Power Station

EdF Energy

South Hook Combined Heat & Power Station

QPI Global Ventures Ltd

SP Mid Wales (Electricity) Connections Project (SP Manweb)

SP Manweb

Thorpe Marsh Gas Pipeline

Thorpe Marsh Power Limited

Tidal Lagoon Swansea Bay

Tidal Lagoon (Swansea Bay) PLC

Tilbury Gas Fired Power Station

RWE npower

White Rose Carbon Capture and Storage Project

Capture Power Limited

Whitemoss Landfill Western Extension

Whitemoss Landfill Limited

Willington C Gas Pipeline

RWE npower

Wrexham Energy Centre

Wrexham Power Limited

Wylfa Newydd Nuclear Power Station

Horizon Nuclear Power

Yorkshire and Humber CCS Cross Country Pipeline

National Grid Carbon Limited

energy sources of current projects including gas, combined cycle gas turbines (CCGT), nuclear, biomass and tidal-powered. Some of the listed schemes still require significant expenditure and investment, resolution of engineering matters and long construction periods possibly leading to policy changes in the current Parliament. There are a further thirty wind power projects also registered with the Planning Inspectorate in December 2014. UK ENERGY (ELECTRICITY) POLICY CURRENT SHORTFALLS There is not an affordable, sustainable plant renewals energy/electricity policy or plan that can depend on the private-sector markets for the UK need. Power generation is a fundamental national need and new-build is not possible with the low wholesale prices, as the 1990s gas plant build curtailment demonstrated. With populations increasing towards 70 million in the UK and France and all people requiring comparable living standards and equal ability to have affordable electricity in all seasons and weather conditions the current plans to replace ageing plants and add more generation capacities are insufficient and too expensive. Templar UK data illustrates how the National Grid daily/ hourly delivery is now a constant juggle and far too often for long periods has inadequate base load contribution from nuclear. The ageing fleet replacement programmes have taken too long to form and become commitments. The UK coalition government became further entangled in international obligations and anti-carbon, leaving little time available and too little capital/debt borrowing for the UK to replace the ageing coal and

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nuclear power stations. The EPR reactor preference selection has added to the nuclear costs and time for delivery, without proof of in-service performance. The current nuclear plan does not include the South Korean APR-1400 reactor, which may be a feasible reactor selection for the initial nuclear units. The French will have their own replacement and expansion programmes to undertake in the next decade and this will create plant delivery issues. The Templar French data illustrates that France has electricity demand margin issues and an aversion to use of coal and gas. The new French EPRs are not yet contributing to the daily French nuclear output and the UK reliance on an unproven design, at this vital time, to replace fleets of nuclear and coal power stations may be too risky for the UK to consider building four of the EPR reactors. Considering two APR-1400s or Westinghouse equivalents for the Sizewell new-build may be less costly with lower performance risk. As the UK hourly/daily demands will not always align with the UK actual wind, sunshine and tidal patterns, reliance on natural forces for electricity is not practical. In the UK there are too little hydro and pre-pumped scheme capacities to deliver sustained multiple gigawatt (GW) generation or to be able to support plant losses/failures, or periods with insufficient wind and sunlight. These complexities with the added costs of carbon capture, wide fleet ageing, unrealistic carbon reduction targets, short delivery timescales and the lost time of the last three UK governments leaves the UK insufficient time and a capital/debt borrowing requirement of £50 billion for fossil fuel generation and over £100 billion to be able to deliver more nuclear. Misplaced expectation of the private market solutions and dogmatic stands against subsidies have exacerbated the possible underdelivery of the multiple GW electricity generation programme requirement and focus on too many smaller schemes with connection additions. The legislative base to reduce carbon outputs, enable the carbon trading margin and overcome the climate change obligations result in the UK not having created the carbon generation option still capable of preventing supply failures. UK desires to lead China, India and USA to these aims have been helpful but now a proportionate fossil fuel carbon generation option is required for the UK to catch up. CHRISTMAS 2014 SUPPLY CONTRIBUTIONS IN THE UK AND FRANCE On Christmas Day 2014 the UK electrical demand management requirements were eased by mild temperatures and wind power of over 4.5 GW on Christmas Eve. The wind-generated power reduced to 1.6 GW by the evening of Christmas Day. The UK hydro output was 1 GW and the pre-pumped hydro peaked at 1.4 GW at lunchtime, to help meet a three-hour period of increasing demand. The interconnectors from France and the Netherlands provided 3 GW, mainly from French nuclear, hydro and wind generation. The UK gas-, coal- and wood-burning ovens and home fires enabled the UK

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to demand only 32 GW of UK-based electricity generation compared to the 55 GW the French required, excluding the exports and imports of the UK and French connectors, for similar populations of over 64 million people. On 29 December noon peaks reached 41 GW in UK and 79 GW in France. The UK coal power stations increased generation from 5 GW early on Christmas Day morning to 14 GW by 10 a.m. and contributed a larger proportion of electricity generated throughout the Christmas period. UK gas power provided 3 GW from Christmas Eve to 11 a.m. when it was increased to 6 GW to cover the four-hour period of lunchtime demand and after Boxing Day for two-hour periods to over 13 GW as the temperature dropped. Coal and gas generated close to two-thirds of the electricity in the UK for the Christmas period, with nuclear generating between one-third and one-quarter of supply, but not sustaining the earlier maximum of 8.1 GW output, instead reducing to 7.5 GW and then providing between 7 and 7.38 GW, returning to 7.6 GW over a five-day period. Skilful management, planning and real-time control by the National Grid and the power companies over the Christmas period provided the plans, schedules and switching between the different generation modes required for the Christmas Day lunch period and each other day. Peak coverage was managed for the 1 p.m. lunchtime peak of 37 GW. This was a lower peak than in the preceding weeks when peak period demands rose to between 40 and 50 GW; this peak had returned by 28 December. During late November and early December 2014 UK gas generation peaked at 20 GW for eight days and 15 GW for six days, with nuclear generation from 5 to 8 GW and wind from 2 to 5 GW. UK demand increased to a seventeen-hour peak of over 43 GW on 27 December and coal generation over 14 GW; gas was over 13 GW and biomass 1 GW, with hydro of 1 GW and pre-pumped hydro at 1.5 GW for a onehour period. Wind was 2.65 GW and nuclear 7.34 GW, with 3 GW imported from French and Netherlands interconnectors. These are the current daily UK requirements. French electricity generation throughout the period was over 50 GW, mainly from nuclear, with 5 GW of hydro, 2 GW of wind and 2 GW of gaspowered generation on Christmas Day. On Boxing Day by mid-morning France was generating 58.5 GW nuclear (out of a 60 GW maximum) for a total electricity demand of 65 GW. This included exports of 6.5 GW of which the UK required 2.16 GW. There was 7 GW of hydro, 0.8 GW of wind and 0.7 GW of solar, no coal and no pumped hydro, 2.3 GW of gas and import from Germany of 2.5 GW of generated electricity. On 27 December at 1800 hrs GMT, French demand was 68.78 GW with over 59.38 GW of nuclear, 7.87 GW of hydro and 4.69 GW of wind, 2.24 GW of gas and 0.66 GW of biomass. Wind had provided up to 6.8 GW and over 6 GW for fourteen hours from midnight through to the afternoon of 26 December. On 29 December French noon demand was 79 GW with nuclear at almost 60 GW and importing 3 GW from Germany.

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ESTABLISHING A CEGB MARK 2 UK DELIVERY ORGANISATION FOR NEW-BUILD POWER GENERATION PROGRAMME The UK government accepts that the electricity-generating markets can operate when there are power plants to inherit, but that planning and construction of new-build does not function economically without guaranteed off-takes and guaranteed prices. There is a need for changes to achieve both the power plant replacement and additional programme commitments economically. A CEGB Mark 2 could be created that would report to the Prime Minister. Such a new organisation could, with the involvement of the National Grid for both the electricity and gas grid changes and the larger power companies, reduce costs and time for project delivery within the energy sector. Other features could include: • The UK consultancy, engineering, Engineering Procurement and Construction (EPC) and construction capabilities can be mobilised by a new government-led ‘CEGB Mark 2’ structured organisation to deliver the programme with the involvement of UK, South Korean, Japanese, US and European fabricators and manufacturers of large power plant equipment. The world’s large EPCs have UK operations for coal, gas and nuclear. • The UK does not manufacture the generators, turbines and reactors of the sizes required for the 1 GW to 6 GW multiple power plant configurations that are now being constructed internationally. • This new delivery organisation will be able to deliver coal, gas, nuclear and tidal with pumping projects through the next thirty-year period, but with the first phase focused on fossil fuels. • The UK programme will require parallel project delivery to ensure the ageing fleets are replaced ahead of their in-operation failure. The UK nuclear fleet is already producing below its designed outputs, as evident over the Christmas 2014 period, and some reactors and boilers are now derated. For too long after the demise of the 1990s gas plant builds, UK governments delayed recognising the benefits of fossil fuel plants when time and cost are important and global capital/ debt is restricted. POLICY CHANGE FOR LARGER COAL AND GAS POWER STATIONS WITHIN THE UK Power stations can be constructed on sites from 1 GW to 6 GW capacity. It is proposed that the UK energy policy is changed to establish the CEGB Mark 2 organisation to build over 28 GW of electricity generation capacity on megasites including a new generation of fossil fuel (coal and gas) and where economical some nuclear-powered stations. Within this initial capacity 14 GW should be coal-fuelled, 7 GW gas-fuelled and 7 GW nuclear-fuelled if economical. This change in the sequencing of fossil and nuclear power stations is to ensure more reliable coal and gas plants are constructed within the next five years to cover some Advanced Gas-cooled Reactor (AGR) phase-out, to reduce cost and time

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and generation risks with a maximum contribution for the UK construction workforce and the UK manufacturing sectors. There are a number of port areas where the importation of coal and liquefied natural gas can be close to new multiple power station sites in the northeast and north-west of England, in the west of Scotland and along the south Wales coasts. Utilisation of UK-produced natural gas from shale may be an option for the period after 2025 and this may extend the period of locally produced gas for power. The National Grid and the larger power companies with port operators can collaborate with a publicly funded CEGB Mark 2 organisation to ensure integrated planning that is linked to grid and distribution network reinforcement for gas and electricity. CONCLUSIONS A review of the most appropriate reactor designs and credible delivery planning for the UK generation baseload programme must be undertaken early in the current Parliament. This is to ensure that contingencies are addressed so that supply will be achieved for the period from 2020 when more power stations are retired. The UK must take account of in-service proving experiences with the EPR elsewhere and act if the French, Finnish and Chinese EPRs demonstrate reduced in-service performances and if construction and operating issues still have to be resolved. If the current UK plan will not be delivered an alternative plan to deliver GW is required early in this Parliament. Fossil fuel has less risk and requires less investment and time to generation than nuclear power will require. A reduction in dependency on uranium fuel, improved nuclear waste storage arrangements and the AGR legacy decommissioning costs can be better managed by a CEGB Mark 2 authority with the Nuclear Decommissioning Authority (NDA) and existing site operators. The past decade has demonstrated that these are costly, significant, persistent matters and are not yet resolved. Nuclear electricity reactor and fuel selection must be reconsidered by a CEGB Mark 2 to enable the nuclear new-build to be justified and relaunched. Nuclear new-build is currently too expensive and requires a longer programme period than fossil fuel electricity generation new-build to reduce the UK base load risks and capital replacement costs. Fossil fuel ultra-supercritical electrical generation with realistic UK carbon targets requires less investment than nuclear power and will reduce the financing debt. After new-build plants are constructed and operated through a two-year performance proving period CEGB Mark 2 can be tasked by the UK government to negotiate the sale or auction of these power stations and sites. This overcomes the significant cost issues some nations are experiencing from the expense of the private funding of independent power plants (IPPs) and power take-off agreements. A CEGB Mark 2 will reduce the new-build charge to cover private finance and private-sector delivery risks.

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ENERGY AND THE STATE IN THE MIDDLE EAST Jim Krane1

When it comes to energy, the Middle East is best known as a supplier of commodities to the importing world. Collectively, the region harbours around half of the world’s conventional reserves of oil and natural gas.2 But recently the countries of the Middle East and North Africa (MENA) have become recognised as important centres of energy demand.3 The region has maintained nearly 6 per cent yearly growth in consumption over the four decades since 1973, a much faster rate of growth than the 2 per cent average for the world as a whole. This chapter examines drivers behind the MENA region’s growing consumption of oil and gas, in particular the government policies that have contributed to the energy intensity of the region. I argue that hydrocarbon demand is an outgrowth of the pervasive and structural role of oil and gas in the formation of many of these states, which has imposed deep influences on their institutional design and outcomes. Among some of the larger oil exporters, the effect of hydrocarbons dates to their origins as sovereign independent states. Oil helped finance their emergence from colonial rule4 and, at times, guided the placement of national 1

2

3

4

Jim Krane is the Wallace S. Wilson Fellow for Energy Studies at the James A. Baker III Institute for Public Policy, based at Rice University in Houston, Texas. He researches political and geopolitical aspects of energy, with a focus on exporting states, particularly those in the Middle East. He is the author of the 2009 book Dubai: The Story of the World’s Fastest City. He holds a PhD and an MPhil from Cambridge University’s Judge Business School, and a Masters in International Affairs from Columbia University. In 2014, the Middle East and North Africa held 52 per cent of proven oil reserves and 47 per cent of proven gas reserves. BP Statistical Review of World Energy 2014 (BP, 2014). International Energy Agency, Betwixt Petro-Dollars and Subsidies: Surging Energy Consumption in the Mideast and North Africa States (IEA, 2008). Saudi Arabia, which was never colonised, is a major exception.

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borders to encompass known oilfields. The business of exporting hydrocarbons has also contributed to the character of governance in the Middle East, helping to maintain autocratic regimes in most of these otherwise diverse states. Finally, in many MENA countries, government policies that made available low-priced fuel and electricity contributed to an ‘entitlement mentality’ among citizens towards cheap energy. In turn, these attitudes have encouraged energy-intense habits, influencing the design of the built environment and guiding patterns of human settlement. In short, the presence of oil and gas has commanded a huge role in sustaining and organising Middle Eastern states and societies and promoting their integration into the global economy. These generalisations are strongest in the region’s energy-exporting countries, but remain apparent in most of the Arab Middle East, including among net importers. ENERGY’S DUAL ROLE Energy assumes a dual role in the autocratic Middle East. Beyond its wellknown function as an export commodity that underpins national incomes and development, energy is also leveraged as a tool of state control. As such, governments maintain tight control of energy prices. In most of the Middle East, energy products are distributed at heavily subsidised prices; in some cases – such as electricity for Qatari citizens – it is given away for free. Energy prices in the Middle East remain among the lowest in the world, far below prices on global markets. A number of motivations lie behind these state-mandated discounts. One arises from government anti-poverty measures aimed at augmenting household income and access to energy. Another is linked to industrial policy targeted towards economic diversification and employment. Energy provision is also an outcome of traditional paternalist patterns of governance in the region in which subsidised energy is exchanged for public support for autocratic regimes. In this last case, government distribution of energy acts a replacement for political participation. The preponderance of similar social contract terms in many energy-producing states can be seen in Figure 99.1, which ranks countries by gasoline price and illustrates the tendency for gasoline prices to correlate with political participation. Lowest gasoline prices are concentrated in exporting countries and tend to correlate with low levels of political participation, while high prices tend to correlate with democratic systems. These are the overarching concerns guiding energy policy in Middle Eastern countries, with the exception of democratic Turkey and Israel, where energy is unsubsidised; in Tunisia, where subsidies have been cut as participation has increased; and among the poorest North African states such as Mauritania, Sudan, Morocco and Djibouti, where hydrocarbon-based energy is unsubsidised or inaccessible.5 5

Sdralevich, R. Sab, Y. Zouhar and G. Albertin, Subsidy Reform in the Middle East and North Africa: Recent Progress and Challenges Ahead (International Monetary Fund, 2014).

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Figure 99.1 Gasoline prices and political participation Sources: Gasoline prices: GIZ 2012; Political participation: Economist Intelligence Unit, 2012. Note that EIU scores range from 0 to 12, with 12 being highest.

DEMAND GROWTH Hydrocarbon demand in the Middle East originates with discoveries of oil and gas in the early and mid-twentieth century. Demand was stimulated by the enormous rent windfalls that accrued after Middle Eastern governments nationalised their oil and gas sectors, wresting control from private, mainly Western, oil companies. Although the takeovers began with Iran in 1951, many occurred during the price spikes of the 1970s, thus enhancing both the level and proportion of rents captured by the state. Increased state income in MENA coincided with high rates of population growth, both of which contributed to energy demand. In the exporting states, demand was exacerbated by industrial policy that favoured energy-intense sectors such as petrochemicals, fertiliser, aluminium and steel production. However, a persistent and crucial demand variable in the region is the low price at which energy products are sold. Since prices in nearly all Middle Eastern countries are set by governments, a large portion of demand growth can be attributed to energy policy. The region’s low prevailing prices relative to income offer little incentive for conservation or investment into more efficient technology. When prices are as low as those in the MENA exporting

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countries, it can be economically rational for people to maintain high rates of consumption using inefficient technology, rather than investing in more efficient replacement technology. The effects can be seen in energy intensity of some Middle Eastern economies, which – especially in exporting states – tends to be high and rising, in comparison with industrial economies where it has trended lower. Figure 99.2 compares energy intensity of gross domestic product (GDP) in Saudi Arabia with that of the United States and the Organization for Economic Co-operation and Development (OECD). It shows the upward trend in Saudi Arabia compared to the US and the OECD, where economies have grown more efficient in energy terms. One outcome of rising demand is that oil and gas production has increasingly been diverted from export sales into domestic markets. In some cases, imports have been required to meet surging domestic needs. Natural gas exporters United Arab Emirates and Egypt have become net importers of natural gas, and Kuwait – not previously an exporter – has become a gas importer. Iran, which holds the world’s largest gas reserves, is a net importer of both natural gas and refined products. Growing amounts of Omani gas once destined for export are being consumed domestically, as are refined products in Saudi Arabia and Kuwait. As a response, governments have been focused on keeping pace with rising demand by diversifying beyond the oil and gas sector, which supplies 98 per cent of the region’s primary energy, and turning towards nuclear and renewable power. Since raising prices is seen as politically risky, less effort has been expended on managing demand.6 STRUCTURAL ROLE OF HYDROCARBONS The structural role that hydrocarbons have assumed within the Middle East has been consistently underplayed in scholarly literature. Most scholarship follows the rentier thesis which conceptualises energy as an economic asset that produces export rents. Authors argue that oil’s importance within the Middle East comes from its value outside the region, as an export commodity that provides regimes with rents. Export rents, in turn, are used to ‘purchase consent’ of the governed through distribution of government jobs and subsidised goods and services.7 6

7

However, in early 2015 incremental price reforms were being implemented or discussed, encouraged by the effects of low oil prices on government revenues. Egypt, Tunisia, Jordan, Yemen, Morocco, Dubai and Iran had managed to raise electricity and/or fuel prices. Kuwait, Oman and Abu Dhabi were discussing similar reforms in the hope that higher prices would reduce demand and encourage efficiency. See Sdralevich et al., Subsidy Reform in the Middle East and North Africa. Early works in rentier theory include the following: H. Beblawi, ‘The rentier state in the Arab world’, in H. Beblawi and G. Luciani, The Rentier State (Croom Helm, 1987, pp. 47–62); G. Luciani, ‘Allocation vs. production states: a theoretical framework’, in H. Beblawi and G. Luciani, The Rentier State (Croom Helm, 1987), pp. 85–98. J. Crystal, Oil and Politics in the Gulf: Rulers and Merchants in Kuwait and Qatar (Cambridge University Press, 1990); F. G. Gause III, Oil Monarchies: Domestic and Security Challenges in the Arab Gulf States (Council on Foreign Relations, 1994).

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Figure 99.2 Energy intensity per unit of GDP Source: US Energy Information Administration 2013.

Unrecognised in the literature is the process by which MENA regimes also buy political support through in-kind distribution of energy. This takes the form of cheap feedstock and fuel, as well as subsidised electricity and water, much of which is desalinated in an energy-intense process. These energy distribution and pricing practices have imposed deep influence on institutional outcomes and design. In countries where low fixed prices occur alongside high personal incomes, energy policy’s influence goes beyond consumption habits to affect the design of homes and workplaces, and even the physical layout of cities and the level of dependence on personal vehicles. One outgrowth that is especially apparent in Iran, Libya and the Gulf monarchies is the sprawl of energy-intense residential and commercial structures, many of which lack efficient design or components. Thus, regime-initiated pricing and supply arrangements helped establish inefficient techniques and ‘locked in’ a pattern of energy-intensive development that has become difficult to change. Dependence on hydrocarbon exports has long been linked by scholars to the robustness and longevity of autocratic systems and the deterrence of democratic institutions.8 Ali and Elbadawi have taken this rentier thesis a step further to demonstrate that the size of the resource base relative to population influences the per capita distribution of rent and public wages, which, in turn, determines the level of state repression required to maintain order.9 Thus the 8

9

See, for example, M. L. Ross, ‘Does oil hinder democracy?’, World Politics 53(3) (2001), 325–61; and B. Smith, ‘Oil wealth and regime survival in the developing world, 1960–1999’, American Journal of Political Science 48(2) (2004), 232–46. O. Ali and E. Ibrahim, ‘The political economy of public sector employment in resource dependent countries’, Academic paper 673 (2012), ERF Working Paper.

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pan-Arab uprisings that started in 2010 tended to inflict countries with smaller per capita resource production and higher levels of state repression. The uprisings bypassed most of the large MENA producer states, with Libya a major exception. Although these findings closely follow the rentier thesis, the analysis is distinct to the extent that it links resources to institutional design. CONCLUSION Energy has assumed an elevated importance within the Middle East since the 1970s oil boom, with government energy policy shaping these societies far more deeply than the political economy literature allows. Middle Eastern states have exhibited increasing demand for energy commodities that comprise the region’s chief export. High rates of growth have been encouraged by government policy, a strategy that has undermined the main source of revenue for government budgets and damaged the competitiveness of these economies on the basis of energy intensity of GDP. The availability of inexpensive energy has shaped the preferences and habits of these societies, their systems of governance and their positions in the global trade and power structure. The structural role of energy in the Middle Eastern state has not been widely acknowledged by academics, but is emerging as a concern among policy-makers in the region and the international organisations which monitor MENA economies and their increasing share of global energy demand.

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DELIVERING ENERGY POLICY IN ARGENTINA Tomás Lanardonne1

INTRODUCING ARGENTINE ENERGY POLICY ‘EXPERIMENTS’ Argentina is a very complicated country to analyse from many perspectives, including its energy policy. While the international crude oil price was plummeting to levels around $50/Bbl during December 2014, the domestic crude oil price (referred to as the criollo barrel) was at $84/Bbl (65 per cent more), due to a combination of government de facto price subsidies and the existence of a state-run oil-integrated company (YPF) that needs cash to invest in its upstream projects (the ‘Vaca Muerta’shale play). In addition, while in July 2008 the international price of crude oil price was around $130/Bbl, the domestic crude oil price was fixed at $42/Bbl due to the effect of export taxes. Also, while Argentina imported natural gas from Bolivia at US$12/MMBtu,2 local producers sold their gas in the domestic market at a mere $2/MMBtu or even less. AN ERRATIC ENERGY POLICY These extreme examples are evidence that energy policies in Argentina have been erratic – at least since the 2001 peso crisis. Since then, the government has converted a free market into a regulated market with high state intervention on prices, decoupling them from international prices. It has introduced independent 1

2

Tomás Lanardonne holds a law degree cum laude from Universidad de Buenos Aires and a Masters in Administrative Economic Law cum laude from Universidad Católica Argentina. He obtained a Masters in Energy Law and Policy from the University of Dundee (CEPMLP), as a British Chevening Scholar. He is Special Counsel at the energy team of Perez Alati, Grondona, Benites, Arntsen & Martinez de Hoz (Jr) in Buenos Aires. MMBTu means 1 million British Thermal Units: BTU is a measure of fuel energy content.

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regulators (a model copied from the US agencies) and appointed politicians as regulators. It has established export taxes, although it had promised fiscal stability to investors. It has prohibited gas exports, although it had approved firm gas export contracts with Brazil, Chile and Uruguay. It has eliminated the ‘term market’ by prohibiting power purchase agreements between generators and distributors or large users, and forced both parties to sell or purchase power only from the Wholesale Electricity Market Administration Company (Compañía Administradora del Mercado Mayorista Eléctrico S.A., or CAMMESA, an independent private company that is now controlled by the government). These are but a few of the energy policies implemented since 2001.3 WHERE DOES ARGENTINA’S ENERGY COME FROM? To understand Argentina’s energy needs, we must understand its energy mix: 86.7 per cent of its primary energy mix is composed of hydrocarbons (crude oil accounts for 32.6 per cent and natural gas for 54.1 per cent). The remaining 13.3 per cent is composed of hydro (3.9 per cent), uranium (2.3 per cent), coal (0.9 per cent) and renewables (6.2 per cent). Remarkably, Argentina has a mature natural gas domestic market, which has evolved over more than sixty years, with a well-developed network. In average terms (2013), Argentina’s gas demand is 48 billion cubic metres (bcm) (33 per cent power, 32 per cent industry and 24 per cent residential), indigenous production is 35.5 bcm (83 per cent of gas needs) and pipeline imports are 8 bcm (Bolivia) and liquefied natural gas (LNG) of 5 bcm.4 SO WHAT IS THE PROBLEM? Natural gas production has been declining for the past years from 46.1 bcm in 2006 to 35.5 bcm in 2013, and crude oil production from 900,000 barrels daily in 2003 to 656,000 barrels daily in 2013. In essence, Argentina is extremely dependent on hydrocarbons, and indigenous production is constantly declining. ENERGY POLICY MUST DELIVER In the short and medium term, an increase of oil and gas reserves and production is required. First shale oil and gas resources have to be converted into proven reserves. Then, larger volumes of crude oil and natural gas need to be extracted. In the long run, energy policy must deliver a larger share of renewables in Argentina’s energy mix, mainly hydro and wind power. IS THERE ANY GOOD NEWS? Yes, according to the US Energy Information Administration (EIA). Argentina stands second and fourth in terms of shale gas and oil endowment respectively.5 3

4

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These measures prompted multiple international arbitrations against Argentina by oil, gas and power companies. See a list of the cases at www.icsid.worldbank.org. See BP Statistical Review of World Energy (June 2014), at www.bp.com/content/dam/bp/pdf/Energyeconomics/statistical-review-2014/BP-statistical-review-of-world-energy-2014-full-report.pdf See US Energy Information Administration, ‘Technically recoverable shale oil and shale gas resources: an assessment of 137 shale formations in 41 countries outside the United States’, available at www. eia.gov/analysis/studies/worldshalegas

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Also, according to the Global Wind Energy Council, Argentina has one of the largest wind resources in the world (mainly in Patagonia) that could be sufficient both to supply the domestic market and to export to neighbouring countries Chile and Uruguay.6 The bottom line is that Argentina has the potential to deliver its energy needs. WHO IS IN CHARGE OF SOLVING THESE PROBLEMS? The federal government: Argentina is a federal country. Like Australia or Canada, oil and gas resources belong to the provinces where the hydrocarbon resources are located (except offshore deposits extending beyond 12 nautical miles, which belong to the federal state). In Argentina, unlike Australia or Canada, the federal government has the exclusive authority to regulate the oil and gas general framework. In the electricity and renewables sectors, the situation is similar. The federal government creates the legal frameworks and enforces them.7 WHAT ARE THE PROSPECTS FOR ENERGY POLICY DELIVERY? The energy policies necessary to deliver an increase of oil and gas reserves and production in the short and medium term, and a larger share of renewables in the energy mix in the long term, may include the following: Respect for the rule of law and predictability Lack of access to finance and incentives for renewable energy development are the major barriers to wind development in Argentina. The main reason for this is policy uncertainty discouraging financial institutions from getting on board. It is for this reason that the Vaca Muerta shale play will not develop at a rapid pace. For almost a century, Argentina has been subject to significant government interference in its economy, particularly in the energy sector, often in the form of aggressive shifts of macroeconomic policies, creating recurrent openings and closings of markets that result in severe regulatory volatility. Periods of heavy regulation have periodically been succeeded by the establishment of deregulated frameworks and vice versa. The latest deregulated period took place in the 1990s, and today it has almost vanished through the strong government interference that began with the Argentine peso crisis of late 2001. The energy industry sector has been experiencing increased government intervention during the last decade. In this context, not only federal but also provincial regulations have significantly altered the legal framework. The shale and renewable industries require large-scale investments which will be less likely if Argentina does not improve significantly its respect for the rule of law and the predictability of its energy policies. 6

7

See Global Wind Energy Council, ‘Global wind 2013 report’, available at www.gwec.net/wpcontent/uploads/2014/04/GWEC-Global-Wind-Report_9-April-2014.pdf See InfoLEG, Hydrocarbons Law N° 17,319, Electricity Law N° 24,065, Renewables Energy Law N° 26,190 and Biofuels Law N° 26,093, available at www.infoleg.gob.ar

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Non-interference over energy prices The development of shale plays and renewables are entirely price-dependent. Since 2002, the Argentine government has been interfering with energy prices and fixing them at depressed levels, uncoupling them from their real cost. The government now seems to be realising that the current scenario of strong government intervention and depressed energy prices is incompatible with the need for abundant energy supply and attracting foreign capital. That is why it is offering subsidy schemes to certain oil and gas producers that increase their production.8 Nevertheless, delivering the above-mentioned energy goals seems to require more than attractive price conditions such as the ability of producers to perform long-term and spot sales of energy products (oil, natural gas, natural gas liquids, power, etc.) at freely agreed prices, without the risk of contract interference. Institutional independence Using the US model as a basis, Ente Nacional Regulador del Gas, an agency in charge of regulating and supervising natural gas utilities and major consumers, was created in order to be independent from the federal government. Since 2007, however, this agency has been interfered with by the federal government which appointed a politician as director and not an independent person, as the rules require. Such interventions must cease to give investors a sense of institutional independence. Elimination or easing of foreign exchange restrictions There is currently a large variety of foreign exchange restrictions that affect the free inflow and outflow of foreign currency, including remittances of profits and dividends. These restrictions discourage investment as they create uncertainty regarding the ability of investors to repatriate their investment and profits and pay for goods, as well as limiting flexibility in financing their operations in the country. These restrictions must be eliminated or relaxed. CONCLUSION Argentina is blessed with world-class natural resources. But this is not enough. It needs to recreate a friendly investment environment which requires clear and precise rules in the context of respect for the rule of law so as to establish a predictable and reliable framework that will trigger the massive investments and logistics that are required to deliver its energy needs.

8

See V. de Gyarfas and T. Lanardonne, ‘Argentina: a step-by-step walk in the road toward the shale miracle?’, available at www.kslaw.com/library/newsletters/EnergyNewsletter/2014/January/ article1.html

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THE ARCTIC: SOURCE OF ENERGY? SOURCE OF CONFLICT? SOURCE OF POLICY INNOVATION Joseph F. C. DiMento1

The Arctic is a very special place. The United Nations Environmental Programme (UNEP) describes the region as follows: Its terrain varies from high mountains to flat plain, wide tundra and great expanses of sea, snow and ice. The plants and animals of the Arctic have adapted to these conditions, but this has rendered them in some cases more sensitive to increased human activities.2 People are also sensitive to increased human activity. The Arctic is populated, sparsely, but much more so than its polar counterpart, Antarctica. Depending on one’s boundary choices for what defines the region the total population reaches almost four million. It has had a significant population of indigenous people for more than 4,000 years.3 SOURCE OF ENERGY Among the human activities of concern is the quest to develop the Arctic’s energy resources. According to estimates, one-fifth of the world’s oil and gas resources are in the Arctic. In 2008, the United States Geological Survey (USGS) estimated 1

2 3

Joseph DiMento, JD, PhD, is Professor of Law, Planning, and Criminology, Law and Society. He specialises in domestic and international law with a focus on environmental and land use. Among his most recent works are (co-authored with Alexis Jaclyn Hickman) Environmental Governance of the Great Seas: Law and Effect (Edward Elgar Publishing, 2012) and (co-edited with Pamela Doughman) Climate Change: What it Means for Us, Our Children, and Our Grandchildren, 2nd edn (MIT Press, 2014). See UNEP website at www.unep.org/regionalseas/programmes/independent/arctic/ Avataq Cultural Institute, ‘The region of Nunavik’ (2011), available at www.avataq.qc.ca/en/ Nunavimmiuts/The-land/The-Region-of-Nunavik

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that areas north of the Arctic Circle may have 13 per cent of the undiscovered oil in the world, 30 per cent of the undiscovered natural gas and 20 per cent of the undiscovered natural gas liquids. Eighty-seven per cent of Arctic oil and natural gas, around 360 billion barrels of oil equivalent, is located in seven Arctic basin provinces. Most is poorly explored.4 Whether and how the region will be explored and its energy resources exploited are functions of human decisions, but they are also influenced by the natural conditions of the region and by forecasted and actual changes in the Arctic. Among the most salient to energy policy and production are the following: TEMPERATURES ‘Arctic average temperature has risen at almost twice the rate as the rest of the world in the past few decades. Widespread melting of glaciers and sea ice and rising permafrost temperatures present additional evidence of strong arctic warming’.5 Future temperature increases in the region show some variability. Projections of air temperatures for the region from 60°N to the pole from each of the five Arctic Climate Impact Assessment (ACIA) global climate models using two different emissions scenarios remain similar through to about 2040; they show approximately a 2°C temperature rise, but then diverge, showing increases from around 4° to over 7°C by 2100.6 In a region as large and diverse as the Arctic, there are significant subregional variations in climate. Parts of Canada and Greenland surrounding the Labrador Sea have experienced cooling in recent years. In the Canadian Arctic average summer temperatures over the last century ‘are the highest in the last 44,000 years, and perhaps the highest in 120,000 years’.7 CLIMATE CHANGE Most expert observers consider climate change to be the greatest threat to and most serious challenge for the Arctic. As Michael Byers has summarised, the Arctic is ‘on the front line’ of the climate change fight.8 ‘[I]t has been estimated that . . . the change there will be twice as intense as the change in other regions of the world’.9 To be sure, changes in climate will provide opportunities for development in the region – with associated benefits. Reduced sea ice is likely to increase marine 4

5 6

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United States Geological Survey 2008, Geology.com, available at www.usgs.gov/newsroom/article. asp?ID=1980#.VV6ic9pViko R. W. Corell, ‘Challenges of climate change: an Arctic perspective, Ambio 35(4) (June 2006),148–52. ‘The full range of models and scenarios reviewed by the Intergovernmental Panel on Climate Change (IPCC) covers a wider range of possible futures’. Arctic Council and the International Arctic Science Committee, ‘Arctic climate impact assessment, impacts of a warming Arctic’ (2004), available at www.acia.uaf.edu G. H. Miller, S. J. Lehman, K. A. Refsnider, J. R. Southon and Y. Zhong, ‘Unprecedented recent summer warmth in Arctic Canada’, Geophysical Research Letters 40(21) (2013), 5745–51. M. Byers, Newkirk Center for Science and Society video presentation, 2010. T. Koivurova, ‘The dialectic of understanding progress in Arctic governance’, Michigan State International Law Review 22(1) (2013), 1–21, at 5.

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access to the region’s resources, expanding opportunities for shipping and possibly for offshore oil extraction (although operations could be hampered initially by increasing movement of ice in some areas). Further complicating the issue, possible increases in environmental damage that often accompanies shipping and resource extraction could harm the marine habitat and negatively affect the health and traditional lifestyles of indigenous people. The probability of accidents and spills of diesel and other fuels increases as the number of ships going through the more easily navigated passages increases by many times (and oil does not degrade in water at −0.5°C). Threats arise not only from the usual dumping and leaks from ships but also from one of the devices that is allowing the opening of the region itself: the immensely powerful nuclear ice-breaking submarine. Nuclear-powered vessels can have important effects on the area. They can open up the Arctic to new activities and to increased commerce; when safe and controlled they can be a relatively clean form of energy for some uses in the region. However if there are problems they can be serious and difficult to solve and accidents can be immensely challenging. SOURCES OF CONFLICT In delivering energy policy to the region and beyond the non-expert often expects the Arctic to be an area of considerable conflict and competition. One sees headlines and titles such as: Who owns the Arctic?10 Denmark stakes its claim in the war for the North Pole11 Russia’s Navy Armed and Ready in North Pole12 Even some experts in the region or on international relations generally see the Arctic in game theory terms. This is a zero sum situation. Others, however, myself among them, are more sanguine. In fact, in the Arctic there have been surprisingly few disputes. CONFLICT AVOIDANCE A large inventory of international law directly addresses or implicates energy development in the region. In brief, rather than listing comprehensively the law, relevant are many treaties, such as the comprehensive Law of the Sea Treaty, 10

Baden Copeland and Derek Watkins, ‘Who owns the Arctic’, The New York Times (7 December 2013), available at www.nytimes.com/interactive/2013/12/07/sunday-review/who-owns-thearctic.html?_r=0 11 R. Noack, ‘Denmark stakes its claim in the war for the North Pole’, The Washington Post (17 December 2014), available at www.washingtonpost.com/blogs/worldviews/wp/2014/12/17/ denmark-stakes-its-claim-in-the-war-for-the-north-pole 12 Reissa Su, ‘Russia’s Navy armed and ready in North Pole, Black Sea; Gorbachev warns world can’t survive another war’, International Business Times (11 December 2014), available at www. ibtimes.com.au/russias-navy-armed-ready-north-pole-black-sea-gorbachev-warns-world-cantsurvive-another-war-1396808

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and bilateral and regional treaties; soft law; and national law. The Regional Seas part of the inventory (UNEP or independent) provides a template for coordination and cooperation in delivering energy policy. SOURCE OF POLICY INNOVATION The international community has a rare and extraordinarily important opportunity in the region. Although the pace of change is no longer glacial, we do have time to employ our vast and increasing understanding of techniques that can move towards a higher level of cooperative decision-making on questions of energy. Among the tools are those created to measure the existence of consensus; those oriented to establishing consensus; and those that assist in moving toward implementation of agreed-upon policies. For example, regarding the first: consensus seeking and related organised collaborative social processes can assist in helping to answer first-principle questions: What are the views on activities linked either directly or indirectly to the exploration for and exploitation of energy sources? These might include the following: • Should major areas of the Arctic be made marine-protected areas and therefore be off limits to exploitation of oil and natural gas resources? • Should exploitation of energy resources in various Law of the Sea zones, the exclusive economic zones, the continental shelves, the areas beyond national jurisdiction, be subject to additional new protections? Or are existing international standards sufficient? • Should nuclear technologies continue to be used to gain access to remote parts of the Arctic? • Are the costs associated with exploration and exploitation too great for any single multinational corporation or nation state? As a preliminary step, the international community needs to address the question of who decides? Who should be involved in seeking these consensus answers? Are existing international government organisations (IGOs) capable of choreographing these inquiries? Is there a need for new ad hoc assemblies? If so, who should be allowed to participate: only nation states? IGOs? Non-governmental organisations? Independent non Arctic state experts? The choice of the procedures used to assess or tap consensus is also critical. Innovative means exist to identify the present degree of consensus and the existing gaps in agreement (identifying areas, points, issues or questions over which participants and stakeholders differ).13 Innovative processes also are available to move towards consensus.

13

See, for example, ‘Stakeholder Assessment, Devising Seminar on Arctic Fisheries’, Program on Negotiation, Harvard Law School, 18–19 September 2013.

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Consensus over energy policy is only one step in protecting the Arctic while meeting agreed-upon energy goals. Many a slip twixt cup and lip is a general condition of policy. So application of the learning from the study of implementation is valuable. There are several basic principles of effective implementation. Among those are identifying control points for a ‘lead agency’ to move towards desired goals; setting specific deadlines for meeting sub goals; and requiring ongoing monitoring and reporting of movement towards goals and sub goals. In the Arctic context a policy example is ecosystem-based management. Many agencies and initiatives call for this approach to addressing environmental challenges in changing external environments, both natural and social. How to go forward requires a focus on detail that is the basis of implementation. The US government has articulated fairly detailed operational activities for a related goal: the development of integrated ecosystem research in areas of the Arctic.14 Such programmes start to get to the level of implementation guidance necessary to convert Arctic policy to Arctic environmental protection. The US plan calls for the creation of a team to ‘develop hypotheses about responses to long-term trends, build scenarios for future subsistence and commercial use of living marine resources, and undertake process studies to inform models to project future ecosystem status’ via the development of a foundation for new scientific research activities through syntheses and assessments of existing data and information and delineating and initiating three- to five-year research and exploration activities, including mechanisms to integrate inter-agency and international efforts. The plan also identifies lead agencies for actions and completion of reporting deadlines.15 CONCLUSION The Arctic is a potential source of vast energy resources. Because of geopolitical and global environmental change it is also a place of potential conflict over use of those resources. The Arctic, in parts, remains a last frontier; here the international community has the opportunity to use innovative policy-making tools to promote – where and if considered necessary – energy production in ways that protect this vulnerable and magnificent place.

14

Implementation Plan for the National Strategy for the Arctic Region, January 2014, available at www.whitehouse.gov/sites/default/files/docs/implementation_plan_for_the_national_strategy_ for_the_arctic_region_-_fi....pdf 15 Another example of this level of detail is the convening of a science integration conference to demonstrate new and updated cyber infrastructure tools to enhance data integration and application, and to identify opportunities for sharing of technology and tools among inter-agency partners by the end of 2016. The programme’s responsible actors are as follows: lead agency: National Science Foundation; supporting agencies: Department of Commerce (National Oceanic and Atmospheric Administration), Department of the Interior, National Aeronautics and Space Administration.

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DELIVERING ENERGY (OFTEN) REQUIRES PUBLIC CONSENT Heather E. Hodges,1 Colin P. Kuehl,2 Eric R. A. N. Smith3 and Aaron C. Sparks4

A common misconception about energy production is that if you have an energy source, a technology for extracting the energy and sufficient finances, you can develop it and start producing energy. Newspapers routinely run stories about new, exciting potential energy developments ranging from conventional fossil fuels to renewable energy. New oil fields are discovered. Advances in hydraulic fracturing technology open up vast possibilities in shale oil. Engineers design safer ways to build nuclear power plants. Bigger, taller wind turbines generate more electricity at lower prices. New technological developments cut the prices of solar cells. The next steps to energy production all seem so easy. As a long history of delayed and blocked energy development projects shows, the next steps are anything but easy. Many energy production projects do, indeed, move smoothly from concept to plans to production without disruptions.

1

2

3

4

Heather E. Hodges is a PhD candidate at the University of California, Santa Barbara. Her research is primarily focused on how political behaviour and political communication shape environmental policy outcomes, particularly in the context of wildfire and energy. Colin P. Kuehl is a PhD candidate studying global environmental politics at the University of California, Santa Barbara. His research focuses on how norms and identities shape environmental behaviour. Eric R. A. N. Smith is a Professor in the Department of Political Science and affiliated with the Bren School of Environmental Science and Management and the Environmental Studies Program at the University of California, Santa Barbara. His research focuses on environmental politics, public opinion and elections. Aaron C. Sparks is a PhD student at the University of California, Santa Barbara. He studies environmental politics and policy within the American system. He is interested in better understanding the individual level motivations for political participation connect to policy-making, especially in regards to energy and environmental issues.

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However, a significant number run into public opposition. Public resistance has slowed or stopped many energy projects. Moreover, the types of projects that have been attacked run the gamut from conventional to renewable energy. Serious public opposition is a challenge that all promoters of energy projects must consider when they plan to deliver energy to the public. Local opposition is typically labelled a NIMBY, or not-in-my-backyard, response. Scholars disagree about the causes of NIMBY behaviour and even whether it is a useful concept, but they agree that local resistance is a powerful political force that can kill projects.5 In addition, research shows that even though national polls show strong support, local opposition may also be strong and may successfully block a project.6 Three examples demonstrate this point. Cape Wind is one of the most prominent cases of an organised and determined local opposition delaying, and likely completely blocking, a seemingly ideally situated energy project.7 When initially proposed in 2001, Cape Wind was celebrated as the largest renewable energy project in American history. Due to the consistency of wind, relatively shallow water and a local public broadly supportive of environmental initiatives, the wind farm project initially appeared destined to be a symbol of an American commitment to invest in renewable sources of energy. However, a NIMBY movement countering the project soon formed and optimistic expectations slowly gave way to predictions of the project’s eventual demise. Opponents argued that Cape Wind allowed private developers to profit from industrialising a pristine view-shed necessary to the local economy, posed dangers to wildlife and would lead to higher electricity rates. Opposition has taken many forms. Popular perceptions of the Kennedy family and their powerful political allies pulling strings to preserve views from their mansions do not tell the full story.8 Opponents organised an information campaign persuading local residents to resist the project. Simultaneously, they sought to block the numerous state and federal permits necessary for the project by working within the regulatory system and filed lawsuits and briefs whenever regulators ruled against them. These efforts delayed the project for years. In early 2015 two major purchasers of Cape Wind electricity withdrew purchasing commitments, signifying a likely end to the once highly touted renewable energy project.9

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K. Burningham, ‘Using the language of NIMBY: a topic for research, not an activity for researchers’, Local Environment 5(1) (2000), 55–67; K. Michaud, J. E. Carlisle and E. R. A. N. Smith, ‘Nimbyism vs. environmentalism in attitudes toward energy development’, Environmental Politics 17(1) (2008), 20–39; C. Rootes, ‘Acting globally, thinking locally? Prospects for a global environmental movement’, Environmental Politics 8(1) (1999), 290–310; I. Welsh, ‘The NIMBY syndrome: its significance in the history of the nuclear debate in Britain’, British Journal for the History of Science 26(1) (1993), 15–32. P. Devine-Wright (ed.), Renewable Energy and the Public: From NIMBY to Participation (Routledge, 2014). For a narrative of the Cape Wind case see J. A. Layzer, ‘Cape Wind: if not here, where? if not now, when?’ in J. A. Layzer, The Environmental Case: Translating Values into Policy, 3rd edn (CQ Press, 2012). W. Williams and R. Whitcomb, Cape Wind: Money, Celebrity, Class, Politics, and the Battle for our Energy Future (Public Affairs, 2007). J. O’Sullivan, ‘Two utilities opt out of Cape Wind’, Boston Globe (7 January 2015).

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The effects of local opposition to energy development are also clearly evident in the debate over the proposed Keystone XL oil pipeline, which would bring shale oil from Canada to American refineries and ports in Texas. Despite the projected local and national benefits from Keystone XL, individuals, governments and politicians along the route continue to question the safety and necessity of the pipeline. What might otherwise be an uncontroversial energy project stretching across the lands of predominantly Republican states has turned into a multi-year, multi-document process, fraught with protest, debate, congressional conflict and eventually a presidential veto. Concerns about Keystone XL include risk to the Ogallala aquifer, disturbing the ecologically sensitive Sandhills in northern and western Nebraska, the threat that the development of the Canadian tar sands and continued reliance on fossil fuels poses for climate change and potential private property losses due to construction. The latter point is made by former Tea Party candidate for Texas governor, Debra Medina: ‘I have a real strong objection to a private business coming in and rolling over property owners in Texas.’10 Because of the NIMBY response to Keystone XL, environmentalists have found unlikely partnerships with individuals traditionally in favour of fossil fuel development. For example, in April, the Cowboy Indian Alliance, a group of farmers and tribal communities from states along the proposed route, protested outside the White House with thousands of others to encourage President Obama to reject the pipeline proposal.11 The Keystone XL example reveals local opposition to energy development, which does not stem from a pro-Democrat or pro-environmental ideology. Opponents include card-carrying Republicans, forming unlikely coalitions with environmentalists to block the energy project. A third example of the potential of public resistance comes from hydraulic fracturing, or fracking, a relatively new technology that allows energy producers to tap into oil and gas resources that were previously thought to be unrecoverable.12 Energy companies are investing billions of dollars in operations to extract the gas, but in many cases public opinion is slowing down or blocking their efforts. This is especially true in California. Due to the system of ballot initiatives, which allows voters to decide directly on policy issues as long as the initiatives have garnered enough signatures to place them on the ballot, public opinion can have a direct impact on the development of energy resources. In other words, if enough of the public were to oppose fracking, a majority vote could block the controversial technique. In 2014, three California counties had ballot measures that were written to ban local fracking.13 Located on the Central Coast, north of Los Angeles, Santa

10

B. Schulte, ‘Keystone XL pipeline path marks new battle line in Oklahoma’, National Geographic (8 March 2013). 11 K. Moe, ‘Cowboys and Indians stand together against Keystone XL’, National Geographic (14 May 2014). 12 A. Prud’homme, Hydrofracking: What Everyone Needs to Know (Oxford University Press, 2014). 13 A. Covarrubias, ‘Results mixed on California soda taxes, fracking, marijuana measures’, The Los Angeles Times (6 November 2014).

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Barbara Country residents turned down Measure P, which would have banned fracking and threatened other existing oil extraction techniques. However, two of the state’s small, rural, agrarian counties, Mendocino and San Benito, successfully passed measures to ban fracking, despite the fact that proponents were greatly outspent by oil companies.14 Supporters of the bans were successfully able to frame fracking as a threat to the traditional agricultural way of life, as well as a significant strain on limited water resources. The lesson to be drawn from these brief case studies is that supportive public opinion is critical for the success of new energy production projects. These cases are not exceptional. Public opinion has also stalled the development of solar projects, nuclear plants, high power transmission lines, coal mines, geothermal power plants, hydroelectric dams and, more recently, the transportation of oil industry machinery through rural communities. The message for energy policy-makers and entrepreneurs is clear. To deliver energy, they need an energy source, a technology for extracting the energy, sufficient finances and an understanding of how to win public consent.

14

J. Cart, ‘Frack attack’, The Los Angeles Times (29 November 2014).

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PUBLIC ENGAGEMENT AND LOW CARBON ENERGY TRANSITIONS: RATIONALES AND CHALLENGES Paul Upham1

For over a decade, focusing on developed country and particularly European contexts, I have argued for energy policy derived and implemented with Habermasian ideals of open and informed debate, while at the same time remaining mindful of the role of differing levels of power among actors, not only in land use planning systems2 but also in the various domains with which energy policy intersects. There are a number of theoretical rationales for why societal engagement in policy design and implementation may facilitate, even if in a limited way, public support for the changes that low-carbon energy supply implies. Yet despite this, the politics of societal (including public) engagement are fraught with political and practical difficulties, while the risk of policy capture by influential actors remains ever present,3 with the potential for mixed consequences.

1

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Paul Upham is Senior University Research Fellow at the Centre for Integrated Energy Research and Sustainability Research Institute, University of Leeds. Paul works on energy technology governance, particularly on public engagement in socio-technical transitions. He has been Visiting Professor in Governance of Energy Systems and Climate Change at the Finnish Environment Institute (SYKE), Helsinki, and Senior Research Fellow at the Tyndall Centre for Climate Change Research (University of Manchester) and Manchester Business School. T. Richardson, ‘Foucauldian discourse: power and truth in urban and regional policy making’, European Planning Studies 4 (1996), 279–92. F. Kern and A. Smith, ‘Restructuring energy systems for sustainability? Energy transition policy in the Netherlands’, Energy Policy 36 (11) (2008), 4093–103, doi:http://dx.doi.org/10.1016/j. enpol.2008.06.018.

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CLIMATE RATIONALE It is worth reminding oneself of the context. The changes that low carbon energy supply imply are substantial and follow in part from the likelihood of a more widely dispersed generation and fuel supply, leading to environmental changes such as new generation and storage infrastructure in landscapes, seascapes, neighbourhoods and homes. Mackay4 provides a sense of the physical scale of the infrastructure required to replace the energy density of fossil fuels for a single country (the UK). While the details of global energy scenario assumptions vary hugely,5 ‘cost-effective’ energy-emissions scenarios aiming for 450 ppmv CO2-eq by 2100 tend to presume a mix of fossil supply with carbon capture and storage (CCS), nuclear and renewables, including large scale bioenergy.6 Those scenarios that stand at least a 50:50 chance of reaching 450 ppmv CO2-eq by 2100 also assume major energy-efficiency gains. These gains imply not just new and upgraded technologies but behavioural changes resulting in reduced energy demand.7 Whether one takes the view that practices shape attitudes, vice versa, or both, the behavioural changes required will involve a range of attitudinal changes, particularly in terms of what publics expect and view as both desirable and normal in terms of lifestyles and levels of consumption. PUBLIC ENGAGEMENT There is a presumption among advocates of societal engagement in energy and related policy-making, myself included, that a greater degree of public engagement in energy policy development and deployment may well be necessary if public support is to be forthcoming for the above changes. Yet informed public debate of energy policy and public engagement in energy decision-making raises many questions and is as likely to catalyse as much debate as it settles – just at a time when what is also required is some degree of closure on alternative low-carbon pathways, to provide the sustained investment signals that will help increase the pace of change. Challenges to involving the public include the need to deal with trade-offs and multiple scales of energy supply and use reduction; the need to provide balanced information and sensitive message framing; and the need to deal with a wide range of societal values.8 To this one might add that there are still few decision tools capable of supporting deliberation with

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D. Mackay, Sustainable Energy – Without the Hot Air (UIT Ltd, 2008). IPCC, ‘Summary for policymakers’, in C. B. Field, V. R. Barros, D. J. Dokken, K. J. Mach, M. D. Mastrandrea, T. E. Bilir, M. Chatterjee, K. L. Ebi, Y. O. Estrada, R. C. Genova, B. Girma, E. S. Kissel, A. N. Levy, S. MacCracken, P. R. Mastrandrea and L. L. White, Climate Change 2014: Impacts, Adaptation, and Vulnerability. Part A: Global and Sectoral Aspects. Contribution of Working Group II to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (Cambridge University Press, 2014). Ibid. Ibid. N. Pidgeon, C. Demski, C. Butler, K. Parkhill and A. Spence, ‘Creating a national citizen engagement process for energy policy’, Proceedings of the National Academy of Sciences 111 (Supplement 4) (2014), 13606–13, doi:10.1073/pnas.1317512111.

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the public at a regional or city level.9 There are also real problems of public trust in government, in associated institutions and in the energy firms that neoliberal market ideology has empowered. Distrust in governments and commercial actors recurs as a theme in energy research with publics. When we ask about new energy technologies, publics talk to us about the contexts in which they experience these technologies, including, implicitly, the unequal power relationships that we refer to above.10 The rationales for broad stakeholder (including public) engagement in science and technology policy-making all have governance implications. They include the concept of transition management, understood as involving socially participative ‘problem structuring, long-term goals and learning about system innovation’.11 While offering analytic concepts and descriptive characterisation, transition management is also prescriptive, offering and discussing designs for sustainability governance.12 Similarly, science and technology studies (STS) theorists have long argued for more authentic public participation in technology innovation research.13 This participation has been discussed in all senses of the public, from individuals through to civil society and in a variety of settings, from technology design through to technology use, always with a keen eye on the power and politics involved.14 Calls for more deliberative inclusion and value plurality in science-related policy-making are also found in post-normal science.15 A key premise of the latter is that epistemological inclusivity is likely to lead to decisions that are inherently ‘better’, with wider political support and legitimacy, particularly in contexts considered ‘wicked’16 in the sense of involving complex interactions and feedbacks. REALPOLITIK Despite these rationales for public engagement, the reality of national and European energy policy-making has typically been very different. Perhaps the most notable recent example of the marginalisation of dissenting voices in

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P. Upham, S. Carney and R. Klapper, ‘Scaffolding, software and scenarios: applying Bruner’s learning theory to energy scenario development with the public’, Technological Forecasting and Social Change 81(1) (2014), 131–42. 10 C. Oltra, P. Upham, H. Riesch, À. Boso, S. Brunsting, E. Dütschke and A. Lis, ‘Public responses to CO2 storage sites: lessons from five European cases’, Energy & Environment 23(2) (2012), 227–48. 11 R. Kemp, D. Loorbach and J. Rotmans, ‘Transition management as a model for managing processes of co-evolution towards sustainable development’, International Journal of Sustainable Development & World Ecology 14(1) (2007), 78–91, doi:10.1080/13504500709469709. 12 D. Loorbach and J. Rotmans, ‘The practice of transition management: examples and lessons from four distinct cases’, Futures 42(3) (2010), 237–246, doi:10.1016/j.futures.2009.11.009. 13 R. E. Sclove, Democracy and Technology (The Guilford Press, 1995). 14 R. Nahuis and H. van Lente, ‘Where are the politics? Perspectives on democracy and technology’, Science, Technology & Human Values 33(5) (2008), 559–81. 15 S. O. Funtowicz and J. R. Ravetz, ‘The worth of a songbird: ecological economics as a postnormal science’, Ecological Economics 10(3) (1994), 197–207. 16 H. W. J. Rittel and M. M. Webber, ‘Dilemmas in a general theory of planning’, Policy Sciences 4(2) (1973), 155–69, http://dx.doi.org/10.1007/BF01405730

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European environmental policy has been in relation to biofuels. While nominally operationalising the objective of increasing renewable energy supply, priority has been given to supply scale per se and developing a competitive European biofuel industry. Concerns that this supply may not achieve net emissions reductions, or worse, were ignored for nearly a decade.17 It was in 2003 that the European Parliament and the Council approved the promotion of the use of biofuels or other renewable fuels for transport in EC Directive 2003/30/EC. Only in October 2012 did the Commission openly acknowledge that there have been serious problems with its biofuels policy, responding with COM(2012) 595. Premised on the promise of technological advance,18 biofuels have been favoured for their capacity to function as a substitutional (dropin) technology. Yet the development and support of single technologies or even technology suites can only ever be one component of what is required for transforming the way that energy needs – in this case in relation to mobility – are met. Transport is a partly induced demand with strongly inter-related path dependencies of urban form and mobility, where climate emissions mitigation is best addressed through mutually reinforcing policy bundling.19 Acknowledging this does not preclude the need or potential benefits of biofuels, but it does have implications for policy priorities, resource allocation and visions of transport (or mobility) futures. The International Institute for Sustainable Development (IISD)20 estimates that the EU biofuel subsidy in 2011 of at least €5.5 billion stimulated US biofuel imports ten to twenty times the EU export volume, with greenhouse gas savings under an central indirect land use change (ILUC) factor of only 0.5 per cent of total EU27 road transport emissions in 2020. One has to ask whether that was the best way to achieve that emissions reduction, in any sense. TRANSITION MANAGEMENT Would broader societal engagement have helped to shape or redirect European biofuel policy? To believe so is to believe that European policy-making can be more responsive to a range of opinion outside of the current lobby system, perhaps through institutionalised forms such as standing citizens’ panels. The (voluntary) European Parliament Transparency register of lobbyists lists, as of December 2014, some 7,000 organisations, of which about 50 per cent are in-house lobbyists and trade/professional associations and about 25 per cent NGOs. Given this, it would not be difficult to make a case for standing citizens’

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P. Upham, J. Tomei and L. Dendler, ‘Governance and legitimacy aspects of the UK biofuel carbon and sustainability reporting system’, Energy Policy 39 (2011), 2669–78. doi:10.1016/j. enpol.2011.02.036. 18 L. Levidow and T. Papaioannou, ‘State imaginaries of the public good: shaping UK innovation priorities for bioenergy’, Environmental Science & Policy 30 (2013), 36–49. 19 IPCC, ‘Summary for policymakers’. 20 IISD, ‘Biofuels – at what cost? A review of costs and benefits of EU biofuel policies’ (2013), available at www.iisd.org/gsi/sites/default/files/biofuels_subsidies_eu_review.pdf

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panels as a complement, perhaps consulted online, while being mindful of the potential for deliberative techniques to reinforce existing power structures.21 In general, approaches such as transitions management have to date sought to support social learning via specially designed fora,22 while publics themselves, particularly in the context of energy policy, have largely had to selforganise and campaign on the margins of political institutions. Dealing with highly interconnected problems arguably requires broad societal consent, with policy-making that is reflexive, socially inclusive and understood as intervention in socio-technical systems with feedbacks and interactions that require anticipation.23 Calling for energy policy-making in this mode may appear hopelessly idealistic, but as IPCC observes,24 the changes required – assuming we want to avoid the worst impacts of climate change – will not be achieved if individual agents advance their own interests independently. Energy policymaking in this spirit requires harnessing powerful commercial and state interests in ways that take account of the needs and views of a broad range of social interests as well as the systemic consequences of intervention. This is a truly challenging but nonetheless worthwhile ideal.

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J. Chilvers, ‘Deliberating competence: theoretical and practitioner perspectives on effective participatory appraisal practice’, Science, Technology & Human Values 33(2) (2007), 155–85, doi:10.1177/0162243907307594. 22 F. Nevens, N. Frantzeskaki, L. Gorissen and D. Loorbach, ‘Urban transition labs: co-creating transformative action for sustainable cities’, Journal of Cleaner Production 50 (2013), 111–122, doi:10.1016/j.jclepro.2012.12.001. 23 Kemp et al., ‘Transition management’. 24 Ibid.

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DELIVERING ENERGY POLICY IN IRELAND: PROTEST, DISSENT AND THE RULE OF LAW Áine Ryall1

SETTING THE SCENE The most striking feature of the contemporary energy policy landscape in Ireland is the extent to which local communities are turning to the courts to challenge development consents for energy infrastructure projects. Throughout the country, there is widespread, highly organised opposition to the development of onshore wind farms and electricity pylons, as well as plans to deploy hydraulic fracturing (‘fracking’).2 Community opposition to controversial infrastructure projects is, of course, nothing new in Ireland; but the scale of this sustained opposition, and the increasingly significant role played by the courts in energy infrastructure disputes, raises important questions about energy policy, citizen engagement in decisionmaking and access to justice in environmental matters. This brief contribution focuses sharply on three areas: first, it explains how the Aarhus Convention3 and European Union law have led to legislative change

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Áine Ryall is based at the School of Law, University College Cork, Ireland. This contribution draws on a research project, ‘Mapping the Future of Environmental Justice in Ireland’ funded by an Irish Research Council New Foundations grant. See, for example, ‘Wind turbines would destroy hen harrier habitat, court hears’, Irish Times (11 September 2014); ‘Judge quashes permission for Cork wind farm’, Irish Examiner (13 December 2014); ‘West Cork locals plan action to halt building of giant wind turbines’, Irish Examiner (26 January 2015); and ‘Officials handed 150 objections to Cork wind farm’, Irish Examiner (3 February 2015). United Nations Economic Commission for Europe (UN ECE), Convention on Access to Information, Public Participation in Decision-Making and Access to Justice in Environmental Matters (1998), available at www.unece.org/env/pp/treatytext.html

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in Ireland that has improved access to the courts in recent years, with a consequent rise in the volume of environmental litigation; second, it highlights an emergent enthusiasm on the part of the judiciary to enforce EU environmental law; and third, it takes a step back and considers a range of wider problems around environmental governance and energy policy that require urgent government attention. ENVIRONMENTAL DECISION-MAKING AND THE RULE OF LAW The Aarhus Convention is a dynamic international treaty that guarantees three procedural rights embracing access to information, participation in decisionmaking and mechanisms to enforce environmental law. The EU and all of the member states, including Ireland, are among the parties to the Convention. Taken together, the Aarhus Convention, EU law and national law impose a range of obligations on the authorities charged with environmental decisionmaking. These include providing the public with access to relevant information and the opportunity to participate effectively in the decision-making process, and carrying out an environmental impact assessment (EIA) and/or an appropriate assessment under the Habitats directive, in the cases where such assessments are required by law.4 Compliance with the law is not optional. The Aarhus Convention and EU law guarantee the right to an effective review procedure to ensure environmental law is enforced. The obligation to provide for access to justice that is not ‘prohibitively expensive’ has led to dramatic changes in the rules governing costs in environmental litigation in Ireland. The general position is that liability for costs usually follows the event – in other words, ‘the loser pays’ principle applies. However, with a view to delivering affordable access to justice, Ireland legislated for a special costs rule in certain categories of environmental litigation where the default position is that each party to the proceedings now pays its own costs, subject to certain exceptions.5 This approach is designed to eliminate the potential ‘chilling effect’ of the traditional ‘loser pays principle’. Fear of liability for substantial legal costs in the event of an unsuccessful court challenge was a major deterrent for individuals, non-governmental organisations (NGOs) and communities contemplating environmental litigation before

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Directive 2011/92/EU on the assessment of the effects of certain public and private projects on the environment (codification) (2012) OJ L 26/1 (as amended by Directive 2014/52/EU (2014) OJ L 124/1) and Directive 92/43/EEC on the conservation of natural habitats and of wild flora and fauna (1992) OJ L 206/7. The special costs rule is found in the Planning and Development Act 2000, as amended, Sec. 50B and the Environment (Miscellaneous Provisions) Act 2011, Part II. The special costs rule applies in judicial review proceedings that challenge, or seek to challenge, a decision, act or failure to act under any provision of Irish law that gives effect to the EIA directive, the Integrated Pollution Prevention and Control directive or the Strategic Environmental Assessment directive. It also applies in certain categories of proceedings aimed at enforcement of planning and environmental law, as well as proceedings concerning the right of access to environmental information. See generally Áine Ryall, ‘Beyond Aarhus ratification: what lies ahead for Irish environmental law?’ Irish Planning and Environmental Law Journal 20(1) (2013), 19–28.

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the enactment of the special costs rule. There is no doubt that the new rule is a significant improvement on the previous position and that it has made the courts more accessible to environmental litigants. However, serious problems remain to be addressed. First, the special costs rule is severely limited in scope and does not extend to all environmental litigation. Second, poor legislative drafting means that the rule is difficult to apply with any certainty, resulting in further ‘satellite’ proceedings to determine who should pay the costs in a particular case.6 Third, the cost of legal services is high in Ireland7 and the special costs rule fails to address how individuals and groups of limited means can afford the cost of their own legal representation in the absence of civil legal aid or other financial assistance mechanisms. Persistent criticism of Ireland’s failure to deliver affordable access to justice in environmental matters (primarily from the European Commission and NGOs) led the Department of Environment, Community and Local Government (DECLG) to undertake a public consultation on implementation of the Aarhus Convention access to justice obligations in autumn 2014.8 Predictably, one of the key issues raised in submissions was the high cost of engaging in litigation and a range of practical problems with the special costs rule. These issues must be resolved if Ireland is to comply with its Aarhus and EU law obligations. But a fundamental review of the overarching system of environmental governance, including how best to deliver access to justice, is necessary to underpin a coherent policy for essential infrastructure development into the future. EU ENVIRONMENTAL LAW IN THE IRISH COURTS Traditionally, Ireland had a poor track record for implementing EU environmental law.9 This situation has improved of late, at least when measured in terms of the number of open infringements being pursued by the Commission.10 The Irish courts were initially reluctant to enforce EU environmental law, preferring to rely 6

For a flavour of the difficulties of interpretation and application that arise in practice in relation to the special costs rule, see, for example, Waterville Fisheries Development Ltd v. Aquaculture Licences Appeal Board (2014) IEHC 522; McCoy and South Dublin County Council v. Shilleagh Quarries Ltd (2014) IEHC 511 and McCoy and South Dublin County Council v. Shilleagh Quarries Ltd (2014) IEHC 512. 7 ‘EU/IMF programme of financial support for Ireland’ (December 2010), 24, available at www. finance.gov.ie/sites/default/files/euimfrevised.pdf 8 DECLG, ‘Public consultation: access to justice and implementation of Article 9 of the Aarhus Convention’, (21 July to 26 September 2014), available at http://environ.ie/en/Environment/ AarhusConvention/PublicConsultation. See further Áine Ryall, ‘Planning for access to justice in environmental matters’, Irish Planning and Environmental Law Journal 21(4) (2014), 131–7. 9 See generally L. Cashman, ‘Commission enforcement of EU environmental legislation in Ireland: a 20-year retrospective’, in S. Kingston (ed.), European Perspectives on Environmental Law and Governance (Routledge, 2012). 10 At the end of 2014, there were seven open infringements in the environmental sector involving Ireland and a further three cases involving proceedings under Article 260 Treaty on the Functioning of the European Union. The figures for open environmental infringements against Ireland in the previous years are as follows: 2013 (8); 2012 (11); 2011 (17); 2010 (25); 2009 (34); 2008 (35); 2007 (34); and 2006 (38). See European Commission, ‘Statistics on environmental infringements (2014), available at http://ec.europa.eu/environment/legal/law/statistics.htm

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instead on the familiar principles of national law.11 The judiciary also tended to adopt a highly deferential approach to decisions involving environmental impact assessment (EIA) taken by expert public authorities.12 There are encouraging signs that the courts are becoming more demanding in their attitudes towards EU environmental law. Two recent High Court rulings are significant here. In Kelly v. An Bord Pleanála (the Planning Appeals Board) [2014] IEHC 400, the High Court quashed two decisions to grant planning permission for wind turbine developments at Dysart and Tobermacloughlin in County Roscommon. The court concluded that the Board had not lawfully carried out appropriate assessments in accordance with Article 6(3) of the Habitats directive that were capable of supporting its decisions. Subsequently, in Ó Grianna v. An Bord Pleanála [2014] IEHC 632, the High Court quashed a decision to grant planning permission for wind turbine development at Réidh na nDoirí, Ballingeary, County Cork on the basis that the Board had failed to carry out a proper EIA in relation to the overall project. The Kelly and Ó Grianna rulings are important precedents for subsequent cases. More significantly, these rulings send a clear message to public authorities charged with environmental decision-making that there are serious consequences for failure to comply with assessment obligations. A substantial number of judicial review proceedings challenging decisions of An Bord Pleanála to grant planning permission for wind farms are currently before the High Court. Many of these cases raise arguments based on alleged failure to carry out proper assessments under the EIA and Habitats directives. Beyond challenges to specific development projects, the High Court has been called on to review the legality of Ireland’s ‘National Renewable Energy Action Plan’ (NREAP)13 on the basis of alleged failure to comply with the Aarhus Convention and EU law (in particular the Strategic Environmental Assessment directive and public participation obligations).14 Embarking on High Court litigation against public authorities and the state, with a view to enforcing the Aarhus Convention and EU environmental law, is an arduous, expensive and unpredictable process. Rural communities across the country are engaged in major fundraising efforts to finance litigation with a view to preventing what they regard as unwelcome energy infrastructure projects in their local area. Uncertainty over the scope of the special costs rule is a cause of serious concern for these litigants who need clarity at the outset as to their potential exposure to any liability for costs. The current volume of litigation raises important questions over the quality of environmental decisionmaking at first instance, including the opportunities for public engagement at the earliest stages of the policy-making process, and about the suitability of 11

Á. Ryall, Effective Judicial Protection and the Environmental Impact Assessment Directive in Ireland (Hart Publishing, 2009), pp. 214–16 and 217–20. 12 Ibid., pp. 221–4. 13 ‘National Renewable Energy Action Plan: Ireland’ (July 2010), available at www.dcenr.gov.ie/ NR/rdonlyres/C71495BB-DB3C-4FE9-A725-0C094FE19BCA/0/2010NREAP.pdf 14 Swords v. Minister for Communication, Energy and Natural Resources, Ireland and the Attorney General, High Court Record No. 2013/4122P. At the time of writing, judgment in this case has been reserved and is expected to be delivered in December 2015.

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judicial review as a mechanism for resolving disputes over the development of energy infrastructure. ENVIRONMENTAL GOVERNANCE: PROBLEMS AND PROSPECTS A thorough review of the system of environmental governance in Ireland, as recommended by the Environmental Protection Agency (EPA) Review Group, which reported to the Minister for the Environment in May 2011, is long overdue.15 Such a review should include consideration of whether a specialist environmental court or tribunal ought to be established to deal with planning and environmental disputes. Given the increasingly technical and specialist nature of decision-making in this field, there is certainly an argument to be made for equipping the courts with appropriate expertise when dealing with such matters. Specialist environmental courts and tribunals operate successfully in other jurisdictions and tend to underpin greater public trust in the competence of the courts to review complex planning and environmental decisions. The EPA Review Group also highlighted the interconnected nature of environmental issues (including climate change, the protection of biodiversity, water resources, law enforcement and so on) and the vital need for a coordinated approach across all relevant government departments and public authorities. The current fragmented approach to environmental governance in Ireland undermines integrated decision-making and makes it more difficult to embed Aarhus Convention and EU law obligations in the national legal and administrative culture. A coherent, forward-looking energy and climate policy is needed urgently. The Green Paper on Energy Policy in Ireland, published by the Department of Communications, Energy and Natural Resources in May 2014, came very late in the day and is disappointingly short on detail, particularly in relation to two of its ‘priority’ policy themes: ‘Empowering Energy Citizens’ and ‘Planning and Implementing Essential Energy Infrastructure’.16 The key challenges here include public and local community acceptance of energy infrastructure projects; informed citizen engagement in debates on energy policy, including the national response to the climate challenge; and a development consent system with sufficient expertise and resources to deliver efficient decision-making that takes full account of Aarhus Convention and EU law obligations. Meanwhile, improving the quality of environmental decision-making at first instance must be a priority. This approach would serve to increase public faith in the regulatory process and should, in turn, help to reduce demand for judicial review down the line. It is hoped that the White Paper on Energy Policy in Ireland, due in late 2015, will demonstrate that the government is serious about addressing these cross-cutting challenges in a proactive and strategic manner. 15

Environmental Protection Agency Review Group, ‘A review of the Environmental Protection Agency’, Department of Environment, Community and Local Government (May 2011), available at http://environ.ie/en/Publications/Environment/Miscellaneous/FileDownLoad,26491,en. pdf. The author was a member of the Review Group. 16 ‘Green Paper on Energy Policy in Ireland’, Department of Communications, Energy and Natural Resources (May 2014), available at www.dcenr.gov.ie/NR/rdonlyres/DD9FFC79-E1A0-41ABBB6D-27FAEEB4D643/0/DCENRGreenPaperonEnergyPolicyinIreland.pdf

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NATIONAL ENERGY POLICY, LOCALLY DELIVERED: THE ROLE OF CITIES Catherine S. E. Bale1

UK local authorities, particularly those in cities, are expected to play an important role in achieving national and international energy policy goals. By facilitating demand reduction and increasing distributed energy generation, they can help address the ‘energy trilemma’, the challenge of providing energy that is affordable, secure and low-carbon. Globally, two-thirds of our energy is consumed in cities,2 making city authorities a key part of the solution. In this role, local authorities (local government or municipal authorities, LAs) can take a number of actions, as both owners of large estates and energy users themselves and through their role in influencing behaviours of other local stakeholders. However, there are significant barriers to LAs engaging in energy provision. The UK energy system is both liberalised and centralised, meaning that central government is responsible for strategic policy decisions and much of the infrastructure is owned by the private sector. As LAs have had no need to develop strategic energy planning functions they currently lack the capacity and resources to deliver energy projects,3 and many are still in the starting blocks.4

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Dr Catherine Bale is a University Academic Fellow at the Energy Research Institute and Sustainability Research Institute at the University of Leeds. She has a background in physical science, and obtained her Masters degree and DPhil from the University of Oxford. She has previously worked in the public sector developing strategic support programmes for the environmental and energy sectors in Yorkshire and the Humber. Her current research focuses on strategic energy planning in cities and the application of complexity science to energy challenges. She holds a Fellowship from the Engineering and Physical Sciences Research Council. Global Commission on the Economy and Climate, ‘Better growth, better climate: the new climate economy report’ (2014), available at http://newclimateeconomy.report C. Bale, T. Foxon, M. Hannon and W. Gale, ‘Strategic energy planning within local authorities in the UK: a study of the city of Leeds’, Energy Policy 48 (2012), 242–51. D. Hawkey, M. Tingey and J. Webb, ‘Local engagement in energy system development: present practice, future need and pathways to 2050’, Loughborough: UK Energy Technologies Institute (2014).

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Yet the opportunity and scope for LA engagement in energy provision is broad, and could include the generation, distribution and/or supply of energy as well as demand management and reduction.5 It is also clear that a number of LAs certainly have the motivation (both political and otherwise) to become ‘energy leaders’; they see that there are many benefits for LAs that take a strategic approach to energy. These benefits can be economic (energy cost savings, job creation and economic competitiveness), environmental (reduced carbon emissions and better air quality) and social (reduction in fuel poverty, urban regeneration and increased health and wellbeing for citizens). National energy strategies are shaped to meet the needs of a nation; however, energy infrastructure, by its nature, must be delivered locally. If national policy fails to incorporate the drivers and incentives that are likely to mobilise local authorities into action, we are unlikely to see the transition to a lowcarbon economy delivered on the ground. THE ROLE FOR LOCAL AUTHORITIES IN DELIVERING ENERGY INFRASTRUCTURE Take, for example, a decentralised energy infrastructure such as a heat network. Heat networks consist of highly insulated pipes that transport heat to multiple buildings using hot water or steam; they are particularly well suited to urban environments, where heat sources and heat demand are dense and in close proximity. The flexibility of the network means that low-carbon heat sources can be brought online when available, and waste-heat sources can also be incorporated. As we are unlikely to be able to meet our full heating demand through electric heating technologies alone, heat networks are key in the transition to low-carbon heating (and are identified as such in the UK Heat Strategy).6 There are a variety of roles that an LA can play in bringing forward new heat-network schemes. These range from fully owning and operating a heat network, as in the case of the Bunhill scheme in Islington7 to facilitating private-sector investment in schemes that offer a commercially viable opportunity. At present, most schemes are small and developed ad hoc to meet the requirements of specific funding schemes. But larger, mixed-use schemes that, for example, link commercial and domestic heat loads across an area in a city, may be more able to exploit different heat sources and balance demand loads.

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K. Roelich and C. Bale, ‘Municipal energy companies in the UK: motivations and barriers’, International Symposium For Next Generation Infrastructure (ISNGI), 30 September – 1 October 2014, Vienna, Austria. DECC, The Future of Heating: Meeting the Challenge (Department of Energy and Climate Change, 2013). Islington Council, ‘Bunhill Heat and Power’, available at www.islington.gov.uk/services/parksenvironment/sustainability/energy-services/Pages/bunhill-heat-power.aspx

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Such schemes can therefore deliver greater economic efficiencies, and, as a result, significant social and environmental benefits.8 The delivery of such schemes requires a phased approach to development and a strategic approach to city-scale planning – which requires supportive, far-sighted national-level policy. PRACTICAL ACTION In developing strategic energy programmes such as heat networks, LAs are seeking to deliver complex value to the city, aiming for multiple benefits across social, environmental and economic areas. The key issue, however, is the extent to which these benefits can be realised under existing systemic constraints. In order to support a strategic city-level approach, there are several practical measures that could be implemented at the national level. First, national energy policy must align with the objectives of local actors. For example, social and environmental criteria should be included alongside economic criteria in funding decision and policy guidelines. National policymakers must adopt a more integrated approach; national policy must recognise the broad range of values, priorities and capabilities of local authorities. Second, the assessment tools used by LAs in developing business cases for local energy projects must include criteria other than those that are technoeconomic. Decision-support tools should enable local authorities to integrate social and environmental value into decision-making processes, and provide valuation assessment that includes non-economic factors.9 Future-proofing through real-options valuation is also important in this respect. Third, national support must enable local actors to build internal capacity for the delivery of future strategic energy programmes. At present, the nationallevel focus is on external know-how in the form of private-sector consultancy. Technical knowledge, as well as understanding of procurement and contracting issues, must be developed by LAs in-house if future schemes are to succeed. Policy developments beyond the field of energy – such as the devolution of power to cities, and peer learning from cities working together10 – are also likely to further strengthen strategic energy planning. It is clear that city authorities have the potential to play a hugely significant role in the delivery of energy infrastructure. However, the right national policies must be put in place if this potential is to be unlocked.

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DECC, ‘Research into barriers to deployment of district heating networks’, Research study by BRE, University of Edinburgh and the Centre for Sustainable Energy for the Department of Energy & Climate Change (2013); P. Woods, O. Riley, J. Overgaard, E. Vrins and K. Siplia, ‘A comparison of distributed CHP/DH with large scale CHP/DH’, IEA District Heating and Cooling Report 8DHC-05.0 International Energy Agency (2005). 9 A. Brown and M. Robertson (eds), ‘Economic evaluation of systems of infrastructure provision: concepts, approaches, methods’, iBUILD/Leeds Report (October 2014) 10 Core Cities, ‘Step 6 power up the cities’, available at www.corecities.com/.../Step%206%20 Power%20Up%20the%20Cities.pdf

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COMMUNITY ENERGY IN THE UK Sandra Bell1

community energy projects in the UK are extremely diverse in nature, scale and geographical distribution. Their activities can be roughly divided into those that raise awareness of domestic energy consumption and promote energy efficiency and those dedicated to electricity generation through renewable sources. Prior to 2014, when the UK government introduced a Community Energy Strategy, programmes and networks to promote community energy projects of both types received piecemeal support, although some support mechanisms and funding led by government, charities and the private sector began to emerge around the turn of the new millennium. The ideological underpinning of community energy projects in the UK can be traced further back to grass roots activism associated with the alternative technology movement of the 1960s and 70s. Research in north-west England showed 90 per cent of questionnaire respondents to be in favour of a community renewable energy project. Just 65 per cent agreed that they would participate in small ways, but no respondents wanted to be involved in project leadership.2 The government’s 2014 strategy identifies four main types of activities that ‘communities can get involved with’3 including generation of heat or electricity; energy saving; energy management by balancing supply and demand; and collective purchasing or switching to new suppliers.

1

2

3

Sandra Bell is an environmental anthropologist who has researched and published on energy issues including community energy projects, electricity consumption, and the evolution of smart grid technologies. J. C. Rogers, E. Simmons, I. Convery and Andrew Weatherall, ‘Public perceptions of and opportunities for community-based renewable energy projects’, Energy Policy 36(11) (2008), 4217–26. DECC, ‘Community Energy in the UK: Part 2’ (2014), available at www.gov.uk/government/ publications/community-energy-in-the-uk-part-2

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Collective switching of gas and electricity to contracts whereby suppliers provide special bulk pricing mechanisms to domestic customers is mediated through a third party, usually operates online and is often initiated by municipal authorities rather than a neighbourhood group or other smallscale communities of place. Cooperatives established for buying heating oil in locations that are not connected to the gas grid are more likely to be proximately managed. Energy management of supply and demand remains in its infancy, because of reliance on the incomplete roll-out of smart grid technologies. However, community groups are expected to play an important role in future pilot schemes.4 Energy-saving projects are growing in the UK but are hampered by the difficulty of obtaining funding. There are no direct funding schemes available, despite the government strategy document’s declared encouragement of such projects and acceptance that people are likely to be more receptive to energy advice when it is delivered by friends and neighbours. Community groups intent on energy efficiency projects are generally required to create partnerships with local government authorities or seek funding from the few non-governmental organisations that promote the spread of sustainable energy practices, such as the UK’s Ashden Trust.5 Distributed micro- and small-scale low-carbon renewable electricity generation has an important role in the future energy mix of the UK. It can contribute to the low-carbon transition as envisaged by the UK government by reducing the estimated 17 per cent of UK carbon dioxide emissions attributed to the domestic sector.6 The current centralised electricity system creates geographical and psychological distance between energy generation and consumption. The use of micro and small scale distributed energy generation systems, with outputs ranging from 1 W to 5 kW and 5 kW to 5 MW respectively, shifts energy generation from central plants and embeds it within villages, towns and cities. Environmental benefits of micro- and small-scale energy-generation systems are recognised by the UK Energy Saving Trust who estimate that microgeneration could supply 30 to 40 per cent of the UK’s electricity requirements by 2050.7 The carbon savings realised from the installation of small-scale energy-generation projects can be greater than those directly associated with the kW produced by a centralised generator due to the double dividend effect, whereby consumers place a higher value on energy produced by their proximate installed system and alter energy practices to reduce consumption. Social benefits of generation projects include the creation of community cohesion

4 5 6

7

Ibid. Ashden Trust, ‘What we do’ (2015), available at www.ashden.org/what-we-do DECC, ‘UK climate change sustainable development indicator: 2010 greenhouse gas emissions, provisional figures and 2009 greenhouse gas emissions, final figures by fuel type and end-user’ (2011). Energy Saving Trust, Econnect, Element Energy, ‘Potential for micro-generation: study and analysis full report’, Energy Saving Trust (2005), available at http://webarchive.nationalarchives.gov. uk/tna/+/http:/www.dti.gov.uk/energy/consultations/pdfs/microgeneration-est-summary.pdf

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through joint endeavour as well as financial benefits through the creation of collective funds to spend on social and environmental projects that benefit the wider community. Though there are many rewards associated with community energy projects, the path from conception to implementation is not always straightforward. There can be many barriers to success.8 Community energy groups require a high degree of tenacity with individuals prepared to invest considerable time and effort in navigating potential pitfalls in their plans. The kinds of people responsible for driving projects involving generation from renewable sources tend to be drawn from managerial, administrative and professional occupations, especially retired professionals who have the time, education and confidence to become informed about and to negotiate complex issues relating to licensing, feed-in tariffs (FITs), grid connection and planning applications. Obstacles include local opposition, planning constraints, ecological concerns (such as conservation of protected species) and technical difficulties associated with retrofit or connection of electrical generators to the distribution network. Shaw and Mazzucchelli 9 cite disparities between the level of community capacities and the capacities required to develop local generation projects as one reason why their adoption is less common than the adoption of energy-efficiency initiatives. Mixed messages and lack of clear impartial advice relating to technology choice and use, embodied energy and lifespan of micro-generation technology are also cited as threats to successful deployment. 10 An estimated 49 MW of community renewable energy generation capacity exists in the UK, although this is thought to be an underestimate.11 Other schemes are in the pipeline, anticipated to be prompted by new or revised sources of government funding in England, Scotland and Wales. Wind turbines appear to be the most popular generating technologies followed by solar panels and micro-hydro. The popularity of wind turbines may be due to the predominance of renewable community generation projects in Scotland and south-west England. Both areas include upland regions as well as access to institutional support. Since 2007 Scotland has been served by the independent charity and umbrella organisation, Community Energy Scotland (CES).

8

G. Walker, ‘What are the barriers and incentives for community-owned means of energy production and use?’, Energy Policy 36(12) (2008), 4401–5. 9 S. Shaw and P. Mazzucchelli, ‘Evaluating the perspectives for hydrogen energy uptake in communities: success criteria and their application’, Energy Policy 38(10) (2010), 5359–71. 10 P. Devine-Wright, G. Walker, S. Hunter, H. High and B. Evans, ‘An empirical study of public beliefs about community renewable energy projects in England and Wales’, Working Paper 2: Community Energy Initiatives Project, Lancaster University (2007); N. Bergman and N. Eyre, ‘What role for micro-generation in a shift to a low carbon domestic energy sector in the UK?’, Energy Efficiency 4(3) (2011), 335–53. 11 DECC, ‘Community energy strategy: full report’ (2014), available at www.gov.uk/government/ publications/community-energy-strategy

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CES has 400 member organisations more than 100 of which joined during the year 2014.12 The steep rise in membership reflects a surge of interest in community energy activity, particularly generation capacity, which took place across the UK during the same period when an English equivalent organisation, Community Energy England,13 was also founded. CES is pioneering new technologies and business models for community energy constructed around the concept of local energy economies. This model simultaneously addresses and integrates electricity generation technologies, models for financing and governance, grid connections, electricity storage and infrastructural issues as applied to community managed projects. Community Energy Wales is a temporary initiative by the Welsh government’s independent policy body, Cynnal Cymru (Sustainable Development Forum for Wales) that is intended to provide a focus point to involve Welsh communities in renewable energy production and energy-efficiency programmes.14 If successful it is likely to become a permanent facilitating organisation for the development of community energy in Wales. While community energy in the UK has not yet reached levels comparable to those in Germany15 or Denmark16 there are strong indications that recent institutional developments and support mechanisms, together with accompanying publicity featuring successful examples, may enable it to prosper in the immediate future. Much will depend on people’s willingness and ability to participate, particularly in positions of greatest responsibility.

12

CES, ‘Annual review 2013–14’ (2014), available at www.communityenergyscotland.org.uk/ annual-review-2013-2014.asp 13 CEE, ‘Who we are’ (2014), available at http://communityenergyengland.org/about 14 Community Energy Wales (CEW), available at www.cynnalcymru.com/Community_Energy_ Wales 15 D. Buchan, The Energiewende – Germany’s Gamble (Oxford Institute for Energy Studies, 2012). 16 A. Schreuer and D. Weismeier-Sammer, ‘Energy cooperatives and local ownership in the field of renewable energy technologies: A literature review’ (2010), available at http://epub.wu.ac. at/2897/1/Literature_Overview_energy_cooperatives_final_(2).pdf

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DISTRIBUTED ENERGY RESOURCES: BACK TO THE FUTURE AND MORE James E. Hickey, Jr1

INTRODUCTION The purpose of this chapter is to lay out some of the policy issues that are beginning to be addressed in earnest in some countries and that will have to be addressed in other countries around the world in the coming decades surrounding the evolving restructuring of electric systems, from production to end use, towards the development and use of distributed energy resources (DER). When Thomas Alva Edison opened the first commercial electric power plant at Pearl Street in lower Manhattan, New York on 4 September 1882, and for some years after, the production of electricity was a local affair conducted by small companies located close to electricity consumers. For example, in 1892, Chicago, Illinois had some thirty small electric companies serving a total of about 5,000 local customers who used electric lights out of a Chicago population of around 1,000,000.2 Some electricity users also had self-contained, inhouse electric generation and some businesses used combined heat and power facilities (CHP or cogeneration) to produce the electricity they used. Within a

1

2

Professor James E. Hickey Jr teaches courses on Energy and International Law at Hofstra University School of Law. He is a past Chair of the American Bar Association (ABA) Special Committee on electric industry restructuring and has been a consultant to the Energy Charter Secretariat and a Special Assistant to the National Petroleum Council. He has over seventy publications to his name, including five books, two of which deal with energy law and policy. Professor Hickey holds a JD from the University of Georgia Law School and a PhD in International Law from Cambridge University. He thanks his Research Assistant, Katherine Moran, for her valuable help on this chapter. J. E. Hickey, Jr, ‘Regulation of electric rates in the US: federal or state competence’, Journal of Energy and Natural Resources Law (8) (1990), 105–19, at 107–8.

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few decades, advances in technology (especially for transmission of electricity over longer distances), economies of scale in having large central service power plants, falling electric prices and policy decisions by government regulators all combined to evolve a dominant model for the electric industry. That model, which has endured for over a century, is characterised by natural monopoly utilities of one sort or another, building and operating large power plants with associated high-voltage transmission lines and low-voltage distribution lines to deliver electricity to large numbers of residential, commercial and industrial consumers over a wide geographic territory. Under this model, electricity flows only one way from the large central station to the end-user. Today, there is a substantial movement under way in many places around the world (like China, Denmark, Germany and the United States) towards a potentially new model for the production and use of electricity in which, once again, an emphasis is being placed on small, local electric power production facilities operated more often than not by consumers themselves with any excess sold or provided to others. Instead of reliance solely on large central station service, electricity under this model comes from many small generators. Here, the considerations are similar to those in Edison’s day but also go further to involve a complex set of policy considerations for the electricity business in the decades ahead. The shift back to the future is due to many factors. In part, it is due to advances in technology, to concerns about climate change, to falling costs of renewable and clean energy, and to a movement towards competition that all make DER more attractive than it has been in the past. DISTRIBUTED ENERGY RESOURCES DEFINED DER is defined as follows:3 a range of smaller-scale and modular devices designed to provide electricity, and sometimes also thermal energy, in locations close to [electric]consumers. They include fossil and renewable energy technologies (e.g., photovoltaic arrays, wind turbines, microturbines, reciprocating engines, fuel cells, combustion turbines, and steam turbines); energy storage devices (e.g., batteries and flywheels); and combined heat and power systems [cogeneration]. This definition does not restrict the scope of DER generation to renewable sources only but rather includes fossil fuel DER too. Viewed expansively, the definition also includes energy-efficiency measures, conservation and demandresponse behaviour.4 DER encompasses an array of electricity technologies 3 4

http://energy.gov/oe/technolgy-development /smart-grid/distributed-energy See, for example, DNV-GL, ‘A review of distributed energy resources’, a 2014 study commissioned by the New York Independent Service Operator, available at www.nyiso.com/public/ webdocs/media_room/publications_presentations/Other_Reports/Other_Reports/A_Review_of_ Distributed_Energy_Resources_September_2014.pdf

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associated with electric generation or with savings realised near the point of use or ‘behind the meter’ of the customer. DER may include rooftop solar panels, micro-wind turbines, small diesel or natural gas generators and even electricity stored in electricity-powered vehicles. Electricity that is generated but not used may flow back into the electric grid to be used by others. Thus, a DER model requires accommodating electricity that flows both ways and not just one way as in the large central station model. THREE POLICY ISSUES AND CONSIDERATIONS. A host of public and private interests – some complementary, some competitive and some conflicting – are vying to one degree or another to influence, shape, advance or deter DER energy evolution. These interests are represented variously by local and national governments, lobbyists, consultants, corporations, NGOs, academics, think tanks, communities, taxpayers and consumers. DER, of course, is implicated in pursuing broad energy-policy philosophies beyond the scope of this chapter such as growth, no growth and transition growth energy policies. In addition, DER also implicates several specific intertwined difficult policy issues and considerations which ought to be addressed in the short and long term as DER evolves and advances. Three of those issues involve stranded costs, net metering and climate change. Stranded costs The shift to a DER model of electric service inevitably will result in stranded costs. Central station system facilities (power plants, transmission lines, substations, distribution lines and so on) are typically financed, built and maintained on the predicate that costs will be recovered over several decades from electric consumers in the form of rates. The development of DER may result in less central station demand for electricity and fewer consumers to pay for overbuilt and underused facilities. Those costs now become ‘stranded’. Depending on one’s policy stance (fairness, equity, efficiency and so on) and energy political viewpoint (growth, no growth, transition growth and so on), those stranded costs will be borne by some or all involved. Taxpayers could pay using a variety of methods. Shareholders could pay through lower dividends and stock prices. Remaining central station system customers could pay through higher electric rates. In addition, DER consumers could pay a fee or premium of some sort to defray stranded costs. Net metering Net metering takes into account that under the DER model electricity flows two ways and not one way as under the central station electricity model. That is, DER consumers not only purchase electricity which is registered by the traditional one-way meter but also they may generate electricity at other times that offsets their use ‘behind the meter’. Net metering allows DER consumers/generators in some way to net the electricity that comes to them and the electricity they generate that flows back to the electric grid by measuring the electricity flow both ways with two-way meters.

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Several issues arise here that are controversial from a policy perspective. One issue involves a ‘free rider’ perception held by some that a DER generator may be able to pay nothing for the electricity they take from a central station provider if, during a billing period, they also generate the same amount of electricity and send it into the grid, thereby having a zero net use of electricity. The free rider perception is that by netting zero the DER generator/consumer does not pay for the value of the grid for which other non-DER consumers pay. DER supporters stress that the electric grid benefits by having less need for central station generation and purchased power to meet system demands, by reducing demand for transmission line space and by other savings and benefits. A different – although related – issue from net metering is the price to be paid to the DER generator if there is an overall net excess of electricity generated beyond the DER generator’s own electric use that is sent into the central station system.5 Should those DER generators receive payment from the central station provider for that excess? If so, should payment be at the same rate that the central station provider charges to its customers; that is, a price that bundles all generation, transmission and distribution costs together? Or should they get a lower price that reflects the value of the DER generation only? In any event, how is that value to be calculated? Climate change and DER6 One of the biggest incentives to embrace the DER electricity model is its substantial reliance on renewable energy sources and clean energy policy – rooftop solar panels, wind turbines, conservation, efficiency and so on. It also has less electricity line loss than central station power experiences through transmission and distribution. To the extent DER relies on renewable sources and clean energy policies, it displaces fossil fuel sources like coal and natural gas that fuel most large central station power plants. Fossil fuel use to make electricity, of course, is a major source of greenhouse gases (GHG) which contribute to climate change. DER is not a pure GHG-free undertaking. Some DER uses diesel fuel and natural gas in small generators and DER also still relies on central station service when renewables are not available – when the sun does not shine or the wind does not blow.

5

6

See, in a US regulatory context, David B. Raskin, ‘The regulatory challenge of distributed generation’, Harvard Business Law Review Online 38 (2013), 4. See, generally, Sonia Aggarwal and Hal Harvey, ‘Rethinking policy to deliver a clean energy future’, The Electricity Journal 26(8), 7–22; Robin Kundis Craig, ‘Energy system impacts’, in M. B. Gerard and K. F. Kuh (eds), The Law of Adaptation to Climate Change (ABA, 2012), pp. 133, 140–2.

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PROMOTING COST-EFFECTIVE DISTRIBUTED GENERATION: LESSONS FROM THE UNITED STATES Karim L. Anaya1

INTRODUCTION The integration of distributed generation (DG) in the electricity grid is challenging for Distribution System Operators (DSOs – called DNOs in the UK) searching for competitive ways to connect them in a cost-efficient manner. DSOs play an important role in this integration and are required to look for different procurement mechanisms in line with their regulatory environment. In Europe, the EU Third Package (Directive 2009/72/EC) governs the unbundling rules and requires the separation of the vertically integrated energy firms from those activities not related to distribution (such as generation, transmission and supply). DSOs with fewer than 100,000 customers may be excluded from the Directive. Due to the expansion of DG, DSOs are also facing a significant increase in the number of connection applications and a low rate of acceptance. In the UK, the distribution licences require DNOs to connect generators on a first-come-first-served basis. Based on the current regulatory framework, DNOs are not encouraged to lead specific competitive processes for the connection of more DG. 1

Karim L. Anaya holds a PhD in Energy Economics and a Masters degree in Technology Policy from the University of Cambridge. She has extensive experience in the public utility regulatory arena. Karim has been a consultant for different organisations (United Nations, World Bank, public utilities regulators). Her research topics are focused on regulation, economics and smart commercial arrangements of distributed generation; business models and economics of energy storage; and renewable energy and technical efficiency in electricity distribution and transmission system operation markets.

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This chapter explores different experiences of decentralised competitive mechanisms to promote the connection of renewable capacity with a focus on DG. Four case studies from the United States have been analysed. This involves the evaluation of the procurement methods used by different electric utilities that operate in California, Colorado, Oregon and New York. A proposal of auction design is described, taking into account the EU Third Package mandate. PROCUREMENT STRATEGIES FOR DISTRIBUTED GENERATION RESOURCES IN THE UNITED STATES The United States has a strong reputation in the procurement of renewable and non-renewable energy sources. There are different methods for doing this. Some of them refer to competitive methods and some others to bilateral contracts and to feed-in tariff (FIT) payments. Bilateral contracts are private agreements between the electric utility (buyer) and the generator (seller) under specific and mutually agreed contract terms and conditions. FIT payments are estimated administratively, are technology-specific and their estimation depends on the method selected (that is, levelised RE project costs, avoided costs). Both approaches save administrative time and, importantly, reduce transaction costs. However, prices do not necessarily reflect the most costefficient generation projects.2 This chapter focuses on competitive mechanisms such as Request for Proposals (RFP) and Renewable Auction Mechanisms (RAM) which promote the connection of cost-effective energy projects by electricity utilities. Four case studies have been selected which refer to the wholesale implementation of decentralised mechanisms for connecting DG. These are solicitations conducted by electricity utilities (three private and one municipal electricity utility) that operate in California, Colorado, Oregon and New York respectively. Solicitations from different jurisdictions are explored because of the diversity of initiatives that energy regulators (represented by Public Utilities Commissions) mandate in order to increase production of energy from renewable energy sources. The four states are among those with the highest rates for their RPS (Renewable Portfolio Standard). Some figures regarding these electricity utilities are shown in Table 108.1. Across the four case studies, it is observed that the solicitations allow competition between technologies within the same category (wind v. solar PV) and between different technologies (non-renewable v. renewable). RAM is a simplified market-based procurement mechanism, while the other three relate to the well-known RFP approach which involves a more complex evaluation process. In the RFP, the proposals are evaluated based on qualitative and quantitative criteria and may require the use of computer modelling in order to select the most cost-efficient portfolio. RFP is also associated with

2

For further details about these two kinds of methods see: NREL, National Laboratory of the US Department of Energy, ‘Procurement options for new renewable electricity supply’, Technical Report: NREL/TP-6A20-52983 (2011), available at www.nrel.gov/docs/fy12osti/52983.pdf

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Table 108.1 Electricity utility data from California, Colorado, Oregon and New York Company name

State

Southern California Edison

California

4.9

50,000

103,000 (distribution lines) 12,000 (transmission lines)

Public Service Company of Colorado

Colorado

1.4 (electricity) 1.3 (natural gas)

32,000

10,000 (distribution lines) 4,000 (transmission lines)

Portland General Electric Company

Oregon

0.8

4,000

25,000 (distribution and transmission lines)

1.1

1,230

8,950 (overhead) 4,661 (underground)

Long Island Power Authority New York

Customers (millions)

Service Lines (miles) territory (square miles)

Source: company websites.

the procurement of renewable generation for large-scale generators. RAM is mainly focused on small- and medium-scale generators (up to 20 MW) and the selection of bids is driven by price alone. In both cases the bid price (non-negotiable)3 includes not only the product price (all inclusive) but also any additional costs such as transmission upgrade costs (if required), operations and maintenance (O&M) and ancillary services. In contrast with RFP, RAM is a programme with specific products (with fixed-capacity quotas per type of technology) and number of auctions (four auctions, one every six months). The solicitations also indicate the type of technology (standardised and commercial), the maximum installed capacity to be allocated (per programme and per project depending on technology) and the option of ownership4 (option to acquire the DG unit by the electricity utility during or at the end of contract term). In addition, the solicitations require the appointment of an independent evaluator by the electricity utility (for managing the bid solicitation), deposits (development security and performance assurance)5 and bid evaluation fees (variable depending on installed capacity or a fixed amount per proposal submitted). In terms of valuable information for potential DG customers, all solicitations require the publication of the Power Purchase Agreement (which helps to accelerate the evaluation of the different 3

4 5

A sealed non-negotiable bid is the method selected in the majority of cases with the option of negotiation in only one case. For further details about the different methods see P. Klemperer, ‘Auction Theory: A guide to the literature’, Journal of Economic Survey 13(3) (1999), 229–86. Applied only to vertically integrated electric utilities. Deposits increase the chance of selecting the DG customers that can meet their obligations to generate as set out in the connection agreement. The absence of penalties was one of the major problems of the Non Fossil Fuel Obligations scheme in the UK, which was based on a bidding mechanism. M. G. Pollitt, ‘UK renewable energy policy since privatisation’, EPRG Working Paper 1002, Cambridge Working Paper in Economics 1007, University of Cambridge (2010), available at www.eprg.group.cam.ac.uk/wp-content/uploads/2010/01/PollittCombined2EPRG1002.pdf

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G, T, D

Renewable and nonrenewable. Renewable: wind, solar (with/without storage or fuel backup), hydro, biomass, recycled energy

Colorado Public Service Company of Colorado (IOU)3

2013 All-source Solicitation Up to 250 MW (period 2012–18) but for All-source solicitation (up to 719 MW)

Greater Yes than or equal to 10 MW

1,330 Between No option MW (full 3 and 20 programme). MW 529.3 MW (procured by SCE across all RAMs)

Capacity Ownership cap per project

Product

Utility Utility Technologies/ Total name/type activities type of capacity products Renewable. Products: (1) baseload; (2) non-peaking as available, (3) peaking as available

State

General

Renewable California Southern G, T, D Auction California Mechanism1 Edison (IOU)2

Auction/ RFP name

Bid evaluation fee

[Continued

(1) No Development security – $60/kW for as-available and $ 90/kW for baseload and (2) performance assurance – 5 per cent of expected total project revenues Variable: Prior to 1 One per N/A $ 10,000 from 1 to May 2018 type of (per 25 years (shorttechnology proposal term submitted) bids), 1 June 2018 (long-term bids)

Fixed: 5, Within One for all 10, 20 two years products years from the date of CPUC approval

Deposits

Contractual terms Length of Operation PPA Procontract date forma

Table 108.2 Comparison of the different mechanisms applied by the four electric utilities

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Oregon

State

General

5

4

3

2

1

G,T, D

Long T, D Island Power Authority (Municipal Utility5

Portland General Electric Company (IOU)4

Renewable: wind, solar PV, biomass, fuel cells

Renewable: wind, solar, hydro, geothermal, biomass, biogas Up to 280 MW

Up to 101 Mwa

Utility Utility Technologies/ Total name/type activities type of capacity products

From 2 MW to 280 MW (up to 40 MW to biomass and fuelcells)

Performance assurance. Amounts and methodology vary across the different stages One for all N/A products

Variable: Between One for all from 10 2013 and products to 20+ 2017 years

Deposits

Contractual terms Length of Operation PPA Procontract date forma

No option Fixed: 20 By 2018 (LIPA is a years transmission and distribution utility only)

Greater Yes. than or equal to 10 MW

Capacity Ownership cap per project

Product

$5,000 (below 20 MW); $ 20,000 (20 MW or more)

$100/MW Maximum $ 10,000

Bid evaluation fee

California Public Utilities Commission. ‘Decision adopting the Renewable Auction Mechanism’. Decision 10-12-048 (2010), available at: http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/128432.pdf Southern California Edison, ‘Southern California Edison Company’s (U 338-E) first compliance report on the Renewable Auction Mechanism program, public version’ (2014), available at www.pge.com/regulation/ RenewablePortfolioStdsOIR-IV/Pleadings/SCE/2014/RenewablePortfolioStdsOIR-IV_Plea_SCE_20140117_294615.pdf Public Service Company of Colorado, Xcel Energy, ‘All-source solicitation. Renewable resources Request for Proposals’ (2013), available at www.xcelenergy.com/staticfiles/xe/Corporate/Corporate%20PDFs/ PSCo2013_RenewableRFP_updated.pdf Portland General Electric Company, ‘PGE Request for Proposals for renewable energy resources’, (2012), available at www.portlandgeneral.com/our_company/energy_strategy/resource_planning/docs/2012_ renewable_rfp.pdf Long Island Power Authority, ‘Request for Proposals for 280 MW of new, on-island, renewable capacity and energy’ (2013), available at www.lipower.org/proposals/docs/280MW.pdf

Request for New York Proposals for 280 MW of renewable capacity and energy

2012 Renewable Energy Resources Request for Proposal

Auction/ RFP name

Table 108.2 Comparison of the different mechanisms applied by the four electric utilities (continued)

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575

offers). In addition, and only under the RAM approach, interactive maps with relevant information about the status of the distribution network are also available online. A comparison of the different mechanisms applied by the four electric utilities is made in Table 108.2. DG PROCUREMENT AUCTION IN EUROPE: A PROPOSAL RFP and RAM are examples of two different well-developed competitive mechanisms that allow the selection of the most cost-efficient energy projects. For instance, in RAM it has been shown that the average bid price from consecutive auctions has decreased over time.6 Both schemes also represent well-documented decentralised competitive mechanisms carried out by electric utilities. A similar auction design can be implemented by the DSOs from Europe taking into consideration the EC third rules. The proposal consists in implementing an auction mechanism that allows the allocation of DG capacity at a specific point of connection (POC) to be defined by the DSO. From those DSOs with fewer than 100,000 customers, a similar mechanism such the RAM would be applied, where the bid price includes not only the energy price but also the connection costs. This represents the more straightforward approach. For those DSOs with more than 100,000 customers, which number around 253,7 a similar approach is applicable but the bid would only include the connection costs. In this case, each DG bids a maximum willingness to pay per MW of connected capacity, subject to a minimum value which covers the cost of connection. Scarce connection capacity can be allocated on the basis of the highest firm bids for connection at each POC. However, the option of including in the bid price the cost of energy is also possible if the competitive mechanism is conducting in association with a third party (such as a local supplier or national government energy procurement authority). Thus, the difference between the two options is the nature of the counterparty to the contract (three instead of two). The implementation of competitive mechanisms is also in line with the aim of the EC Third Package, especially in keeping prices as low as possible. Table 108.3 gives an example of the competitive mechanism design elements applicable to the UK context (only DG connections). The proposal includes auction design elements similar to those from RFP and RAM. However, there are some specific differences in this proposal. First, the product is based only on DG connections (DNOs in the UK are not allowed to purchase electricity from generators). Second, in terms of counterparties, the DNO refers only to the distribution business, in contrast with those vertically

6

7

Southern California Edison, ‘Southern California Edison Company’s (U 338-E) first compliance report on the Renewable Auction Mechanism program, public version’ (2014), available at www. pge.com/regulation/RenewablePortfolioStdsOIR-IV/Pleadings/SCE/2014/RenewablePortfolioStdsOIR-IV_Plea_SCE_20140117_294615.pdf Council of European Energy Regulators, ‘Status review on the transposition of unbundling requirements for DSOs and closed Distribution System Operators’ (2013), Available at www. ceer.eu/portal/page/portal/EER_HOME/EER_PUBLICATIONS/CEER_PAPERS/Cross-Sectoral/ Tab/C12-UR-47-03_DSO-Unbundling_Status%20Review_Public.pdf

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Table 108.3 Competitive mechanism design elements applicable to the UK context

1

Concept

Competitive mechanism

Product

Only DG connections All technologies (renewable and non-renewable) Generator size: subject to the capacity estimated at each POC

Counterparties

DG and DNO

Evaluation/selection criteria

Based on pre-qualification criteria and connection cost (£/MW) Highest offers (connect now) or bids are the ones selected first (subject to available capacity at POC) Operational date: no more than 2–3 years

Curtailment1

Methods: LIFO/pro rata (FPP), no compensation In case of market-based compensation schemes/incentives, if generators are part of the balancing mechanism they may be compensated in case of curtailment

No. of auctions/year

2

Independent evaluator

Yes

Evaluation fee

Yes (£/MW) with option to refund those that bid at least once (but do not win) Online payment

Deposits

Yes (development security, performance assurance)

Submission

Proposal to be submitted online

Online material/requirement

Excel sheet as reference for estimation of potential revenues Pro-forma connection agreement Interactive network connection map with potential POCs Documentation: specifications of minimum documentation to be provided by the respondents to the DNO

There are different methods for reducing generation output: last-in-first-out (LIFO) – the last on the list is the first to be curtailed, market-based – generators compete to be curtailed by offering a price based on the market to be curtailed), pro rata – curtailment is equally allocated among all generators.

integrated electric utilities from the United States. Third, regarding the evaluation criteria, the price includes only the connection costs and only those with the highest bids may be selected. Fourth, in the existence of network constraints, generators may be subject to the reduction of their generation output (curtailment). Three methods (called Principle of Access) have been identified: lastin-first-out (LIFO), pro-rata and market-based.8 If a market-based approach is selected, compensation or any incentive to generators should be defined in the connection agreement. Even though the example given is in relation to the UK electricity market, a similar approach can be replicated by other DSOs from Europe, taking into consideration the Third Package rules. 8

K. Anaya and M. G. Pollitt, ‘Experience with smarter commercial arrangements for distributed wind generation’, Energy Policy 71 (2014), 52–62.

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CONCLUSIONS A similar behaviour is observed in both RFP and RAM schemes in the way in which competitive mechanisms are managed by the electricity utilities. The bid prices should reflect the total cost/benefits in order to make proper comparisons among competitors and select the most cost-efficient generation projects (allowing lower socialisation costs). The proposal can be applied by DSOs taking into consideration the EU Third Package. Competitive mechanisms may also help DSOs to manage the increase in the number of DG connection enquiries and related issues.

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ENERGY AND CLIMATE POLICY: SYNERGIES, CONFLICTS AND CO-BENEFITS Hannes R. Stephan1

Energy and climate policy have been closely linked ever since the 1970s when scientists stepped up efforts to model the warming effect of greenhouse gases (GHGs) on the earth’s climate.2 Carbon dioxide (CO2) from fossil fuel combustion represents the largest source of GHG emissions, accounting for well over 60 per cent of global emissions and around three-quarters of GHG emissions in industrialised economies such as the United States and the European Union.3 At current trends, the world is not on track to meet the target of keeping global warming below a 2°C average temperature rise. Instead, twice this

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Hannes R. Stephan is a Lecturer in Environmental Politics and Policy at the University of Stirling. He conducts research on various aspects of environmental politics, covering global, European and national levels of analysis. He is particularly interested in energy justice/security, climate change, the governance of sustainability and agricultural biotechnology. His recently published monograph – a comparative study of the politics of GM food and crops in the USA and the EU – is entitled Cultural Politics and the Transatlantic Divide over GMOs (Palgrave, 2015) and his current research explores the politics of unconventional gas in Scotland. Hannes Stephan is a co-convenor of the Environmental Politics Standing Group of the European Consortium for Political Research (ECPR). The author gratefully acknowledges permission by Edward Elgar Publishing and by his co-author to reuse material which appeared in an earlier book chapter: John Vogler and Hannes R. Stephan, ‘Governance dimensions of climate and energy security’, in Hugh Dyer and Maria J Trombetta (eds), International Handbook of Energy Security (Edward Elgar Publishing, 2013). S. R. Weart, ‘The idea of anthropogenic global climate change in the 20th century’, Wiley Interdisciplinary Reviews: Climate Change 1 (2010), 67–81. International Energy Agency (IEA), CO2 Emissions from Fuel Combustion: Highlights (OECD/ IEA, 2013). The US accounts for around 16 per cent of total global GHG emissions and the EU for 11 per cent. Source: PBL Netherlands Environmental Assessment Agency, Trends in Global CO2 Emissions (2014), available at http://edgar.jrc.ec.europa.eu/news_docs/jrc-2014-trends-inglobal-co2-emissions-2014-report-93171.pdf

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amount of warming appears likely.4 In the context of rapidly growing global energy consumption, the use of fossil fuels is projected to increase despite an unprecedented expansion of renewable energy generation.5 For a range of scenarios which assume average temperature rises higher than 2°C, the Intergovernmental Panel on Climate Change not only assumes a reduction in energy demand and greatly improved energy efficiency, but also estimates that lowcarbon energy sources will grow 185–275 per cent by 2050.6 However, globally there is currently a large gap between targets for climate mitigation and sobering trends in energy generation/consumption – with renewables only accounting for 5 per cent of global energy generation in 2013.7 While the EU has set relatively ambitious energy and climate targets,8 the global situation reflects the fact that energy and climate typically remain two distinct spheres of policy-making. ENERGY POLICY In the realm of energy policy, the concept of energy security has long been dominant. It can be defined as ‘access to secure, adequate, reliable, and affordable energy supplies’.9 Less state-centric and more ‘society-centred’ perspectives have equally risen to the fore. The notion of energy justice embodies the quest for a fair distribution of benefits/harms from energy generation as well as inclusive and respectful procedures for public participation in decision-making.10 Energy security, however, is prioritised in this chapter because it encapsulates governments’ striving for security of supply (diversified supplies and reliable energy infrastructure) and affordability (concerning economic competitiveness and social welfare). Energy needs and endowments differ greatly across the world. National energy policies are context-specific, as shown historically by the contrast between energy-exporting countries (which typically have low domestic energy prices) and energy-importing countries (with stronger interest in energy efficiency and

4

World Bank, ‘Turn down the heat: confronting the new climate normal’ (2014), available at http://documents.worldbank.org/curated/en/2014/11/20404287/turn-down-heat-confrontingnew-climate-normal-vol-2-2-main-report 5 MIT Joint Programme on the Science and Policy of Global Change, 2014 Energy and Climate Outlook (2014), available at http://globalchange.mit.edu/research/publications/other/ special/2014Outlook 6 Intergovernmental Panel on Climate Change (IPCC), Climate Change 2014 Synthesis Report: Summary for Policymakers (2014), available at www.ipcc.ch/pdf/assessment-report/ar5/syr/ SYR_AR5_SPMcorr1.pdf 7 BP, Statistical Review of World Energy (2014), available at www.bp.com/en/global/corporate/ about-bp/energy-economics/statistical-review-of-world-energy.html 8 The 2030 Framework for Climate and Energy Policies aims to reduce the EU’s GHG emissions by 40 per cent (compared to 1990 levels) and increase both the share of renewable energy and energy efficiency by 27 per cent. 9 J. Bordoff, M. Deshpande and P. Noel, ‘Understanding the interaction between energy security and climate change policy’, in Carlos Pascual and Jonathan Elkind (eds), Energy Security: Economics, Politics, Strategies, and Implications (Brookings Institution Press, 2009). 10 D. McCauley, R. J. Heffron, H. R. Stephan and K. Jenkins, ‘Advancing energy justice: the triumvirate of tenets’, International Environmental Law Reports 32(3) (2013), 107–12.

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technological innovation).11 Only a few countries, such as Denmark or Japan, have responded to a relative lack of domestic fossil fuel reserves by developing long-term strategies based on stringent energy efficiency standards, alternative electricity generation (renewables, nuclear power) and higher overall energy prices. By contrast, countries with considerable fossil fuel reserves – including (at least historically) the US – have typically used their relative abundance to export energy resources. They have also kept domestic prices low for socioeconomic reasons and to increase the economic competitiveness of domestic companies. CLIMATE CHANGE MITIGATION Meeting ambitious or even moderately demanding climate mitigation targets would require a far-reaching decarbonisation of national economies. Given its carbon footprint and long investment cycles, the energy sector is justifiably at the top of the climate policy agenda. A truly radical low-carbon energy strategy would include all of the following components: • a significant increase in funding for energy research and development which remains at low levels in most countries (for example, only 0.03 per cent of GDP in the US)12 • dramatic improvements in energy efficiency across all sectors, but especially for fast-growing emissions in transport and residential sectors • concerted management of energy consumption through technological solutions and behavioural change • providing a credible and effective economic framework for decarbonisation by putting a price on CO2 (through carbon taxes and/or cap-and-trade schemes) • phasing out all subsidies for the production of fossil fuels and exploration of new reserves • giving generous economic incentives to emerging industries in the low-carbon energy sector, such as wave and tidal power as well as carbon capture and storage. Such a profound transformation of energy systems around the world and the construction of genuinely low-carbon economies are not utopian in a technical sense. The necessary policies have frequently been devised, many low-carbon technologies are already being deployed and some of the more advanced technologies, such as affordable, large-scale batteries for storing electricity, are nearly within reach. However, the political economy of the low-carbon energy transition poses a tremendous challenge. Concentrated industrial interests that rely on fossil fuels have often fought against such an energy transformation – most successfully in countries (including the US) which are wedded to forms of export- and

11 12

M. Bradshaw, Global Energy Dilemmas (Polity, 2013). J. DiPeso, ‘Advanced energy R&D: hitting the climate policy reset button?’, Environmental Quality Management 20(3) (2011), 95–102.

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growth-driven ‘carboniferous capitalism’ based on cheap and abundant nonrenewable natural resources.13 By contrast, accustomed to greater resource scarcity, European countries have typically been more open to constructing greener, more resource-efficient economies. SYNERGY, CONFLICT AND CO-BENEFITS In both the US and the EU, strong political and economic coalitions would be needed to counter the influence of incumbent actors defending the status quo. Those in favour of low-carbon transformation can point to important synergies between energy and climate policies that could be pursued in a costeffective way. Many economies are reliant on imports of oil, natural gas and coal. By adding a more diverse range of (largely domestic) low-carbon sources and drastically increasing energy efficiency, countries can enhance the security of supply and reliability of their energy systems. Alongside boosting employment, this was a major motivation for the EU’s 2008 Climate and Energy Package and its 2014 successor.14 Energy security also had a strong – but not decisive – influence on the climate policy debate in the US.15 The potential for synergy with another important aspect of energy security – affordability – is less straightforward. Energy efficiency measures need upfront investment, but often have a relatively short payback time. By contrast, significant investments in relatively novel low-carbon technologies may result in considerably higher energy costs, especially in the short term. The political risks of such strategic energy policy should not be underestimated. For instance, in the UK, where average household energy bills rose by 75 per cent between 2004 and 2014, green levies were responsible for around £100 on top of the average annual household bill. This equalled merely one-fifth of average price increases during this period.16 Nevertheless, rising energy prices stoked serious political controversy over climate policy in 2014, and the long-term cost-benefit ratio of bold climate policies very much depends on future prices of fossil fuels. This kind of political backlash is not inevitable. Concerns over distributive (in)justice regarding the cost of energy/climate policy could, in principle, be addressed by funding low-carbon measures from the general budget rather than adding the cost to household bills directly. And, from a global perspective, even the United Nations’ ambitious agenda to provide sustainable energy for

13

M. Paterson, ‘Post-hegemonic climate politics?’, British Journal of Politics and International Relations 11(1) (2009), 140–58. 14 See http://ec.europa.eu/clima/policies/package/index_en.htm 15 G. Bang, ‘Energy security and climate change concerns: triggers for energy policy change in the United States?’, Energy Policy 38 (2010), 1645–53. 16 UK Committee on Climate Change, Energy Prices And Bills – Impacts Of Meeting Carbon Budgets (2014), available at www.theccc.org.uk/publication/energy-prices-and-bills-impacts-ofmeeting-carbon-budgets-2014

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everyone around the world by 2030 (SE4ALL) strives to do so in a low-carbon fashion by emphasising energy efficiency and renewable energy.17 However, there are also ‘false’ synergies and potential conflicts between energy and climate policy. For example, incentives for biomass and biofuels in the US and the EU modestly enhanced energy security, but also resulted in a variety of unintended consequences and had a negligible (or even negative) effect on GHG emissions.18 In addition, promoting first-generation biofuels (from palm oil, sugar cane or rapeseed oil) often leads to increased deforestation or environmentally harmful agricultural practices. A related controversy is currently playing out with regard to unconventional shale gas and coalbed methane. Although advertised as ‘lower-carbon’ (than coal and oil) and as a potential ‘bridge’ to a radically low-carbon future, studies from the US show that the climate benefits may have been overestimated due to significant methane emissions from shale gas operations. An even more important caveat is the danger of ‘locking in’ a fossil fuel-based energy infrastructure for the coming decades, thus making it harder to move towards a low-carbon energy system in a quick and cost-effective way.19 To overcome formidable barriers to system transformation, low-carbon advocates have increasingly sought additional allies from the broader environmental and public health sectors. For instance, emphasising the ‘co-benefits’ of climate mitigation provides a powerful complementary rationale for upfront investments in low-carbon energy generation and R&D. Effective climate policy would considerably reduce concentrations of ground-level ozone, nitrogen dioxide and particulate matter, thus preventing hundreds of thousands of premature deaths from air pollution each year. Compared to a scenario without climate policy, this would also save significant expenditures on air pollution control. By 2050, the EU could potentially save over €35 billion.20 In global terms, McCollum et al. estimate that concerted decarbonisation of energy systems may, by 2030, reduce global expenditures on public health and the diversification of energy sources/imports by $100–600 billion annually.21

17

J. Rogelj, D. L. McCollum and K. Riahi, ‘The UN’s “Sustainable Energy for All” initiative is compatible with a warming limit of 2°C’, Nature Climate Change 3(6) (2013), 545–51; and see UN SE4ALL website at www.se4all.org 18 R. Lawrence, How Good Politics Results in Bad Policy: The Case of Biofuel Mandates, Environment and Natural Resources Program (Belfer Center, 2010), available at https://research.hks. harvard.edu/publications/getFile.aspx?Id=611; S. Van Renssen, ‘A biofuel conundrum’, Nature Climate Change 1(8) (2011), 389–90. 19 A. C. Lin, ‘A sustainability critique of the Obama “all-of-the-above” energy approach’, George Washington Journal of Energy and Environmental Law 5 (2014), 17–25; C. Shearer, J. Bistline, M. Inman and S. J. Davis, ‘The effect of natural gas supply on US renewable energy and CO2 emissions’, Environmental Research Letters 9 (2014), 1–8. 20 P. Rafaj, W. Schöpp, P. Russ, C. Heyes and M. Amann, ‘Co-benefits of post-2012 global climate mitigation policies’, Mitigation and Adaptation Strategies for Global Change 18(6) (2013), 801–24. 21 D. L. McCollum, V. Krey, K. Riahi, K. Riahi, P. Kolp, A. Grubler, M. Makowski and N. Nakicenovic, ‘Climate policies can help resolve energy security and air pollution challenges’, Climatic Change 119(2) (2013), 479–94

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CONCLUSION Energy policy-makers in the US, the EU and beyond are grappling with the linkages between energy and climate policy. This chapter has argued that there are important reasons – as well as technological and political opportunities – to rebalance energy policy in favour of climate policy. If done intelligently, this could speed up the low-carbon transition and lower its overall costs, while generating significant co-benefits for energy security and public health.

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THE MULTI-LEVEL SYSTEM OF GLOBAL GOVERNANCE: OPPORTUNITIES FOR MORE AMBITIOUS CLIMATE STRATEGIES Martin Jänicke1

For many years, the literature on global climate governance was characterised by a search for an optimal or ‘best’ level of climate policy with a strong focus on the formation of international regimes. More recently, there has been a greater focus on local and regional contributions as well as the role of different actor communities. This more ‘polycentric approach’2 regards the plurality of actors and levels and the complexity of their interactions not as obstacles but as an opportunity for innovation, interactive learning and the diffusion of technologies and supporting policy instruments. MULTI-LEVEL GLOBAL GOVERNANCE: AN INVENTION OF THE RIO SUMMIT (1992) Climate policy occurs in a global system of multi-level and multi-actor governance. The United Nations Conference on Environment and Development (the Earth Summit) held in Rio de Janeiro, Brazil in 1992 codified these concepts in ‘Agenda 21’. The core idea of Agenda 21 was to mobilise the broadest possible spectrum of political, economic and civil society actors across policies, sectors and policy levels of the global system. It was the first global governance model for a transformation towards sustainable development. This

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Professor Dr Martin Jänicke is Founding Director of the Environmental Policy Research Centre, Freie Universität Berlin, and Senior Fellow+ at the Institute for Advanced Sustainability Studies, Potsdam. He was Vice President of the German Advisory Council of the Environment, a member of parliament and a policy advisor in China. Works on state failure, ecological modernisation, capacity building and best practice in environmental policy have been published in several languages. Ostrom, ‘beyond markets and states: polycentric governance of complex economic systems’, American Economic Review, 100(3) (2010), 641–72.

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system was successful in the diffusion of various sustainability programmes, as well as in terms of agenda setting and policy formulation. Ten years after the Rio conference, 6,400 local Agenda-21 processes had been started. However there was a lack of implementation and far too few relevant changes in economic structures and outcomes. As a rule the business sector was not adequately integrated into the sustainability programmes. Climate policy has used a similar model of multi-level and multi-actor governance. Efforts to address climate change have been more successful in various regards than Agenda-21 processes, because they have been able to mobilise relevant economic actors at all levels of the system of global governance. Moreover, climate policy has revealed a remarkable potential of global multi-level governance regarding innovation, diffusion and interactive learning across levels and sectors. Figure 110.1 shows a formalised version of the ‘Rio model’ of global governance. GROWING IMPORTANCE OF THE SUBNATIONAL LEVEL Although there have been many hurdles to developing a strong climate policy globally, there are also signs of progress. Various climate policy measures have moved bottom-up from the subnational to the national, European and

Figure 110.1 The ‘Rio Model’ of multi-level sustainability governance

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global levels, integrating best practices and policy innovations of lower levels. In recent times some stronger top-down influences also can be observed. There is also a growing importance of the subnational level of provinces/states and cities/local communities. One indicator of such activities is the growing membership and the increased influence of international networks of regions and cities (such as ICLEI, C40 or the Network of Regional Governments for Sustainable Development). National networks are playing an increasingly important role too. Examples are the Solar Cities in India, the Low Carbon Eco-Cities in China and the ‘100% Renewable Energy’ network in Germany. States and regions have taken remarkable initiatives. The nine US states that are part of the Regional Greenhouse Gas Emission Trading Initiative (REGGI) have reduced their CO2 cap by 45 per cent. Twelve Chinese provinces plan to reduce their CO2 emissions by 1.3 billion tonnes (2020); Scotland plans to have 100 per cent green power by 2020. The role of cities has been described as follows: Thousands of cities and towns worldwide have policies, plans, and targets to advance renewable energy, often outpacing ambitions of national legislation . . . [C]ities seek to share and scale up best practices . . . Increased coordination among local, state and national government is opening the door for municipalities to further accelerate the uptake of renewable energy and stimulate rapid market transformation.3 This system of multi-level and multi-actor governance provides an opportunity structure for innovation and diffusion of climate-friendly technology as well as policies supporting markets for such technologies. The system and its communication structure enable demonstration effects for pioneer countries, provinces or cities supporting peer-to-peer ‘lesson-drawing’. This opportunity structure can be used for promoting ambitious and effective climate actions. Smart policies can even accelerate change.4 There are not only inherent change dynamics but also inherent elements of stability. When a state or subnational actor that led in the past no longer leads, the baton may be passed onto another state or subnational actor.5 THE CASE OF THE EU The EU system of multi-level climate governance is the most advanced regional subsystem of the global system of climate governance. It is unique compared with multi-level systems in other regions of the world such as 3 4

5

‘REN2: renewable energy’, Global Status Report 2014 (Paris, 2014). M. Jänicke, ‘Accelerators of global energy transition: horizontal and vertical reinforcement in multi-level climate governance’, Institute for Advanced Sustainability Studies (IASS), Working Paper (December 2013). M. Schreurs, ‘Regionalism and environmental governance’, in R. Falkner (ed.), The Handbook of Global Climate and Environmental Policy (Wiley-Blackwell, 2013).

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North American Free Trade Agreement (NAFTA), the African Union, the Association of Southeast Asian Nations (ASEAN) or the Union of South American Nations (UNASUR). The most important difference is the role of the ‘European level’. The EU has the institutional power to formulate and implement ambitious policies. There are institutional mechanisms to upscale and harmonise climate policy innovations of lower levels. The harmonisation of member states’ policy innovations, due to the Common Market, often follows the ‘more stringent protective measure’ clause of the Treaty (Article 193). The British emission trading system, for example, or the German policy approach to supporting renewable energies was later adopted by the European Union. There is also a strong institutional potential at the regional and local level, together with the ‘principle of subsidiarity’. The EU has induced strong horizontal dynamics at lower levels, for example by launching the Covenants of Mayors. As of 2014, this broad network of cities has more than 6,000 members who have introduced more than 4,000 ‘Sustainable Energy Action Plans’ and agreed to reach an average of 28 per cent greenhouse gas reductions on average by 2020. The multi-level dynamics of the EU can be deemed a success story in terms of goal-attainment and governance. There is also a high share of climate-related investment in the budget. There is, however, also a persistent lock-in in unsustainable structures. In addition, there are tendencies not only of acceleration but also of a slowing down. The present economic situation cannot be ignored. Political leadership remains important.6 Due to the lack of political leadership and ambition in its present climate policy the EU has been referred to as a ‘leaderless leader’.7 Weak political leadership in Brussels is being compensated by ‘multi-level reinforcement’ of climate governance in other parts of the system. This is a strong argument for the strength and persistence of multi-level climate governance in Europe. ECONOMIC CO-BENEFITS There are many possible co-benefits for society and the economy which can coincide with a smart climate policy. They offer the opportunity to translate climate-policy objectives into a broad variety of interests. The IPCC has presented seventeen such potential co-benefits.8 Multi-level and multi-stakeholder governance may be the best strategy to address the full variety of positive impacts that can arise together with mitigation activities. Economic co-benefits have been highly important in mobilising business actors at all levels of the multilevel system of global climate policy.

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R. K. W. Wurzel and J. Connelly, The European Union as a Leader in International Climate Change Politics (Routledge, 2011). A. Jordan, H. van Asselt, F. Berkhout, D. Huitema and T. Rayner, ‘Understanding the paradoxes of multi-level governing: climate change in the European Union’, Global Environmental Politics 12(2) (2012), 43–66. IPCC, Fifth Assessment Report III: Climate Change 2014: Mitigation of Climate Change (IPCC, 2014).

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This system of global climate governance seems to have become increasingly irreversible. Indicators are the increasing institutionalisation of climate policies, the dynamics of change enabled by the system itself, and the rise and strength of new interests supporting climate action.9 POLICY CONCLUSIONS The following policy recommendations can be drawn: • Promote climate mitigation and adaptation, translate, where possible, climate policy objectives into the language of co-benefits, particularly those that will mobilise economic interests. • Base policy on existing best practices at different levels and provide channels for lesson-drawing and interactive learning. Apply ambitious but realistic targets and credible implementation programmes. Raise ambitions and targets in cases of unexpected success. Give targeted support to sustainable R&D initiatives; use the lead market mechanism where possible. • Support lower levels of government and stimulate horizontal dynamics through benchmarking, competition, lesson-drawing, cooperation and networking. • National governments – both as single and collective actors – generally have the strongest capacities and therefore should lead with ambitious climate policies. National leadership requires involvement in a broad variety of networks. Competition within and between states can promote climate progress. • Reinstall European political leadership to activate the full potential of the unique opportunities in the EU system of multi-level climate governance. Raising the level of ambition is the necessary condition of clean energy innovation, which is the most important economic co-benefit of climate governance.

9

E. M. Patashnik, Reforms at Risk: What Happens After Major Changes are Enacted (Princeton, NJ, 2008).

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THE WHAT, HOW AND WHERE OF CLIMATE LAW Navraj Singh Ghaleigh1

Law’s attempts to grapple with anthropogenic climate change can be characterised as many things – innovative, complex, tortuous – but not, alas, successful. Rather than add to existing accounts of the climate regime,2 this chapter responds to three sets of inquiries: (1) what, if anything, is climate law?; (2) how has it sought to tackle the climate problematic?; and (3) where is it heading? Behind each of these lies what may be the only important question – can currently constituted law facilitate avoiding climate change? WHAT? Should we speak of ‘climate law’, or ‘the law relating to the climate’? International environmental lawyers will be familiar with the distinction – is our topic a conceptually coherent, autonomous body of law3 or, to paraphrase Birnie and Boyle, nothing more or less than the application of national and international law to climate problems?4 Given the range of legal sub-disciplines potentially implicated by the climate – the law of the sea, World Trade Organization law, European Union law, intellectual property law, general international law, to

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Navraj Singh Ghaleigh is Senior Lecturer in Climate Law at the University of Edinburgh where he teaches at the Law School, Business School and School of Geosciences. His research is both interdisciplinary, focusing especially on economics and PIL, and transnational, with a particular interest in East Asian climate law. He is involved with various learned societies including the Society of Legal Scholars, the Royal Society of Arts and Climate Strategies. For example, H. van Asselt, The Fragmentation of Global Climate Governance: Consequences and Management of Regime Interactions (Edward Elgar Publishing Ltd, 2014), Chapter 2. See P. Sands and I. Millar, ‘Climate, International Protection’, Max Planck Encyclopedia of Public International Law (Oxford University Press, 2014). P. Birnie, A. Boyle and C. Redgwell, International Law and the Environment, 3rd edn (Oxford University Press, 2009), 4.

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name but a few – the preferable approach must be to regard our subject matter as that cluster of law engaged by climate disputes and law-making processes.5 Accordingly, the ‘climate regime’ consists not merely of the UN Framework Convention on Climate Change (UNFCCC), its Protocol, and the decisions and practices that they have spawned, but also the dense web of institutions, arrangements and mechanisms that have proliferated in global, regional, national and subnational settings – consider respectively the World Bank’s Forest Carbon Partnership Facility, the European Union’s Emissions Trading Scheme (ETS), China’s pilot ETS and the C40 Cities Climate Leadership Group of the world’s megacities committed to addressing climate change. Each engages law and legal institutions in shifting constellations that cannot be accurately captured by a notion of ‘climate law’ as a self-contained and self-sufficient body of law. HOW? On any view, at the heart of the climate regime is the UNFCCC, an archetype of the evolutionary style of treaty which establishes objectives and principles as well as relatively modest targets and institutions. Key is the expectation that the regime is a dynamic one, in which regular ‘Conferences of the Parties’ and intersessional meetings ‘facilitate further development through the addition of protocols, annexes or additional agreements’.6 In this manner the UNFCCC (concluded in 1992) added its famous Protocol in Kyoto in 1997 but has since struggled, mostly notable in Copenhagen in 2010, to further deepen the obligations of State Parties. The core goal of the UNFCCC (and all climate mitigation) is to reduce greenhouse gas (GHG) emissions. Without a very steep decline in global emissions, irreversible climate change – in the form of drought, desertification, ocean acidification, disruptions to rainfall, forestry, agriculture and so on7 – will be inevitable. The initial phase of the Kyoto Protocol, for example, required industrialised State Parties to reduce their emissions by about 8 per cent by 2013, against a 1990 emissions baseline. Most debates on the future of the climate regime revolve around the need to deepen such emission reductions (to over 80 per cent for long standing industrialised economies) and extend them to large emerging economies such as China, India and Brazil. As currently constituted, emission reductions count only the quantity of GHG generated on a given territory, not how much is generated by a nation’s consumption. Are we then measuring the wrong thing? The difference of this distinction can be seen clearly with reference to the European Union which claims to lead

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6 7

For a synopsis of cognate debates, see A. Boyle and J. Harrison, ‘Judicial settlement of international environmental disputes: current problems’, Journal of International Dispute Settlement 4 (2013), 245, 247–50. A. Boyle and C. Chinkin, The Making of International Law (Oxford University Press, 2007), p. 241. See, generally, Intergovernmental Panel on Climate Change, Climate Change 2013: The Physical Science Basis. Working Group I Contribution to the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (Cambridge University Press, 2013).

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global climate change policy.8 While EU GHG emissions fell by 17 per cent from 1990 to 2010, such reductions would substantially have occurred in any case because of deindustrialisation and energy efficiency.9 The achievement, such as it is, is somewhat unclear given that the EU’s reductions are more than offset by increased GHG emissions in those developing countries from which the EU now imports manufactured goods (most of all China). Meanwhile EU aggregate consumption emissions have remained roughly constant. While the EU’s conventionally measured emissions have declined significantly since 1990, its consumption has not, just its production.10 The EU lecturing other polities on the urgency of climate action is thus as curious a spectacle as Satan denouncing sin. WHERE? After more than two decades of sincere labour, the existing processes and concepts in climate law have been tried, tested and shown to be deficient. In addition to the shortcomings of the system of measurement used to quantify emissions reductions, reference could equally be made to the principle of differentiation11 which has to date absolved large emitting emerging economies from making emission reductions whilst simultaneously antagonising established economies;12 the choice of market mechanisms (such as the Kyoto Protocol’s flexibility mechanisms, or the EU’s ETS) which have dismally failed to deliver the cost-effective emission reductions that they promised;13 or more generic shortcomings in the corpus of international environmental law such as the lack of compulsory dispute settlement mechanisms.14 The UNFCCC’s recently concluded Paris Agreement15 offers the merest glimmer of hope. Its Article 2 establishes a new commitment for all parties to

8

The EU’s ‘integrated approach’ was completed in June 2009, in the form of the ‘Climate and Energy Package’. See D. Helm, ‘EU climate-change policy – a critique’, in D. Helm and C. Hepburn (eds), The Economics and Politics of Climate Change (Oxford University Press, 2011). 9 EEA, ‘European Union greenhouse gas inventory 1990–2009 and inventory report 2011: Submission to the UNFCCC Secretariat’, EEA Technical Report No 2/2011 (2011). 10 The EU’s consumption emissions in 1990 were 4,947 Mt CO2 and in 2012 4,814 Mt CO2 – a reduction of 2.5 per cent. Compare 1990 territorial emissions of 4,255 Mt CO2 with 3,543 Mt CO2 in 2012 – a reduction of 17 per cent. T. A. Boden, G. Marland and R. J. Andres, ‘Global, regional, and national fossil-fuel CO2 emissions: Carbon Dioxide Information Analysis Center (CDIAC), Oak Ridge National Laboratory’, accessed via the Tyndall Centre’s ‘Global Carbon Atlas’ at www.globalcarbonatlas.org 11 UNFCCC, Article 3(1); see generally L. Rajamani, Differential Treatment in International Environmental Law (Oxford University Press, 2006). 12 A. E. Boyle and N. Singh Ghaleigh, ‘Climate change and international law: beyond the UNFCCC’, in K. R. Gray, C. P. Carlarne and R. Tarasofsky (eds), The Oxford Handbook of International Climate Change Law (Oxford University Press, 2015). 13 N. Singh Ghaleigh, ‘Economics and international climate change law’, in K. R. Gray, C. P. Carlarne and R. Tarasofsky (eds), The Oxford Handbook of International Climate Change Law (Oxford University Press, 2015). 14 F. Francioni, ‘Realism, utopia and the future of international environmental law’, in A. Cassese (ed.), Realizing Utopia: The Future of International Law (Oxford University Press, 2012). 15 FCCC/CP/2015/L.9/Rev.1

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contribute to both mitigation and adaptation, including ‘nationally determined commitments’ detailing how they will do so and regular National Communications to the UNFCCC Secretariat, albeit ‘in the light of different national circumstances’ (Article 2.2). More significant may be the Agreement’s commitment to transparency in a variety of forms – NDCs must be clear and understandable (Article 4.8) and will be submitted to technical expert review (Article 13.11); Article 13 itself commits to an ‘enhanced transparency framework’, including the aforementioned third-party review, to track progress of NDCs and justify support (Article 9.7); and a new compliance mechanism will be ‘transparent, non-adversarial and non-punitive’ (Article 15.2). Indeed transparency may well be the greatest contribution of the Agreement. As such, this volume’s focus on ‘new concepts’ is entirely apt, although novelty alone cannot be a recommendation. Climate engineering remains a distinctly unwelcome, if novel, putative solution to deadlock in the climate regime and catastrophic climate change.16 Efforts could be made to deploy the strengths of other regimes (such as the WTO’s dispute settlement system by way of carbon border-adjustment measures).17 More incremental solutions, such as changing the methodology for ‘what counts’ as an emission reduction would better align the incentives of policy-makers to the demands of science. More ought to be made of less ideologically driven mechanisms than ETS. This would avoid the continued waste of time and money that has characterised all such experiences to date. The Paris Agreement’s bashful Article 6 may even serve this function – a market mechanism that dare not speak its name, it is to the climate regime what homosexuality was to Victorian Britain. In any event, without the introduction of new concepts of climate law, we need not strain our powers of prediction to imagine the future of the world’s climate.

16

N. Markusson, F. Ginn, N. Singh Ghaleigh and V. Scott, ‘“In case of emergency press here”: framing geoengineering as a response to dangerous climate change’, Wiley Interdisciplinary Reviews: Climate Change 5(2) (2014), 281–90. 17 N. Singh Ghaleigh and D. Rossati, ‘The spectre of carbon border-adjustment measures’, Climate Law 2(1) (2011), 63–84.

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ENVIRONMENTAL LAW AND CLIMATE CHANGE John McEldowney1

The UN Framework Convention on Climate Change is set to meet in Paris in 2015. Progress towards an agreement to take forward the 1997 Kyoto Protocol are critical to the success of global attempts to address CO2 emissions. The transitional arrangements for states that are undergoing transformation to a market economy form part of the ongoing discussions2 and are critical for controlling climate change.3 The European Union has a binding target of a 40 per cent reduction in greenhouse gas emissions by 2030 compared to 1990 emissions. There is a target of at least 27 per cent renewable energy consumption and a 27 per cent increase in energy efficiency. The EU emissions trading scheme is a flagship policy for regulating the carbon market but requires careful redesign.4 It is in this context that UK energy policy has to be framed since 2004. The UK, after twenty-five years as a net exporter of energy, has become a net importer. This is having serious repercussions for energy providers as well as government policy for securing energy security and supply5 compatible with reductions in CO2 emissions. The importance of the mix of energy supply6 including oil, gas, nuclear and renewables is evident in attempts to address climate change. 1

2 3

4 5

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John McEldowney is Professor of Law and has written in the field of environment law and public law. He has also considered the role of regulation in the context of the main utilities. House of Commons Library, Lima Climate Change Conference SNSC 7041 (30 November 2014). The recent US-China climate pact is encouraging. ‘US-China make game-changing climate pact’, ENDS Report 478 (December 2014). The US and China account for 42 per cent of global emissions. ENDS Report 475 (September 2014), 32. Houses of Parliament, Measuring Energy Security POSTNOTE Number 399 (January 2012); House of Commons Library, Energy Imports and Exports SN/SG/4046 (4 March 2013). See www.gov.uk/government/news/energy-trends-and-prices-statistical-release-27-march-2014

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UK ENERGY CHALLENGES AND ISSUES Ofgem, the UK industry regulator, has become concerned about the adequacy of electricity generation to meet supply. Central government is engaged in decommissioning older power stations, encouraging the building of new plant for nuclear generation and limiting CO2 emissions. There are delays in building and commissioning new nuclear power stations and this has resulted in having to extend the life of coal-fired power stations as well as a dependence on gasfired power stations. Energy is further complicated with the acceptance of the devolution of energy and climate change matters to local authorities and the nations and regions of Scotland, Wales and Northern Ireland. Devolution of national climate change targets to local and regional levels gives local authorities the potential to engage in strategic energy planning.7 Energy priorities are incorporated into planning policy guidelines aimed at achieving sustainable development with a strong presumption in favour of planning permission in many energy projects. There is also the ‘Merton Rule’8 that ensures that a proportion of energy used in new developments is to be met from onsite renewable energy generation. At the time of writing there is an Energy Bill 2013–14 before Parliament that includes cheaper electricity tariffs, adopting small scale feed-in tariffs to larger community based schemes and for energy efficiency regulations. Energy generation and use in the UK faces a number of pressing challenges – climate change, moving to a low-carbon economy and energy security.9 UK production of natural gas is at its lowest since 1985. UK drilling for shale gas is at a very early exploratory stage but it is hoped that it will have considerable potential.10 Oil prices are fluctuating from a high in July 2008 of $150 per barrel to the current low price of around $65. The International Energy Agency predicts that prices will be around $250 in 2035 but the development of shale gas in many countries is potentially transformative.11 THE PROMOTION, GENERATION AND USE OF RENEWABLE ENERGY RESOURCES The Climate Change Act 2008 set a legally binding target for the reduction of the UK’s carbon emissions by 80 per cent from 1990 levels by 2050. This is in response to national, European and international influences and also Agenda 21, since the United Nations conference held in Rio de Janeiro in 1992. Implementation requires action by both local and central government and their adoption of a strategic approach to energy policy. The Carbon Plan published in March 2011 outlines the Department for Energy and Climate Change (DECC) strategic plan for the UK over the following 7

DCL, National Planning Policy Framework (March 2012). The name is derived from the London Borough of Merton where the policy was first piloted. 9 House of Commons Library, ‘Energy Bill: committee stage report’, Research Paper 13/19 (12 March 2013). 10 House of Commons Library, ‘Shale gas and fracking’, SN/SC/6073 (4 December 2014). 11 House of Commons Library, ‘Oil prices’, SN02016 (29 January 2014). 12 House of Commons Library, Carbon Price Floor SN/SC/5927 (15 March 2013). 8

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five years12 to address climate change and the way electricity is generated, as well as how businesses and homes are heated. The aim is that 15 per cent of electricity should be generated from renewable sources after 2020. The range of measures include feed-in tariffs, renewables’ heat incentives, the Green Energy Fund and various related strategies. There is an EU policy on energy generation13 with a target of 20 per cent of all energy being generated from renewables by 2020.14 The UK government has a UK Biomass Strategy,15 published in 2012, which states that biomass could contribute to 21 per cent of the UK’s target of generating 15 per cent of the country’s energy from renewables by 2020. Biomass is a generic term to cover any organic material used to produce heat, electricity or transport fuel.16 Biomass combustion of electricity is zero CO2 emissions and the use of municipal waste gives local authorities a powerful incentive to participate in achieving renewable energy targets. The Environment Agency has observed that to make biomass sustainable, it must be undertaken in a way that provides reductions in greenhouse gas emissions and avoid negative impacts such as on soils, groundwater, air quality, forests and water resources.17 The DECC monitors energy trends through a quarterly publication. The general trend in the UK is that power generated from wind, hydro and other renewables is increasing. This is set to continue with the largest increase due to offshore wind farms although the government has shown less enthusiasm now than in the past. Hydro power is also proving popular. A major mechanism to promote efficient use of energy resources is the Climate Change Levy aimed at promoting sustainable energy. POLICY ON ENERGY: DOMESTIC AND PUBLIC BUILDING AND TRANSPORT The Home Energy Conservation Act 1995 was intended to contribute to the eradication of fuel poverty through more efficient home energy use, but it has had limited success. Since August 2011, home owners have been able to claim grants for installing renewable heat equipment. Only about 9,000 homes have been given grants,18 however, and the government wishes to expand this number to 513,800 by 2020.19 The UK coalition government adopted the Green Deal20 aimed at encouraging home energy efficiency and supported the Energy

13

HC Deb 14 January 2013 col. 480 w. See the Renewable Electricity Directive, 2001/77/EC. 15 House of Commons Library Standard Note, Biomass SN/SC/6586 (18 March 2013). 16 There are a number of basic groups of biomass material: woody energy crops through forestry and coppiced willow; other energy crops such as oilseed rape, sugar beet, wheat and maize; agricultural; waste from landfill gas, municipal solid waste, waste wood and waste vegetable oils. 17 The Environment Agency, UK Biomass Strategy 2012 (2012). 18 ENDS Report 455 (December 2012), p44. 19 The most popular is biomass boilers. 20 House of Commons Library, ‘The green deal’, SN/SC/5763 (15 March 2013); ‘Risk or reward: assessing the Green Deal’, ENDS Report 446 (March 2012), 28–31. 14

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Act 2011 that came into operation on 28 January 2013 in England and Wales, and on 25 February 2013 in Scotland. The Green Deal comprises a new Energy Company Obligation (ECO) intended to eradicate fuel poverty in the poorest and most vulnerable households.21 The underlying principles are to allow energy consumers to receive loans to make energy efficiency improvements. There is a golden rule that the instalment payments should not exceed savings on an average bill. There are three strands: the Affordable Warmth System, the Carbon Saving Obligation and the Carbon Saving Communities Obligation. Potential mechanisms to support energy efficiency include feed-in tariffs to reduce energy consumption; council tax rebates for energy-efficient homes with variable duties on taxation such as stamp duty and an extension of the 5 per cent reduction in VAT on energy-efficient homes,22 heating boilers and windows.23 In October 2012 the government took the initiative in simplifying energy tariffs to help households obtain cheaper energy through reduced tariffs.24 Initiatives for smart meters,25 zero carbon homes,26 the use of solar energy, currently at a high of 5 GW in the UK, and simplifying energy tariffs are being adopted to encourage energy conservation and prudent energy use.27 In addition, local authorities have considerable potential in taking forward an effective environmental role in energy. The Localism Act 2011, the Green Deal, the Energy Act 2011 and the new Energy Company Obligation are likely to provide a stimulus to encourage energy initiatives. CONCLUSION Since the privatisation of gas and electricity, policy-making in the energy sector in the UK has favoured increased competition and market liberalisation in allowing better consumer choice through more transparency in consumer pricing. This has had limited success. The UK spends the second highest energy subsidy in the EU, next to Germany.28 Political considerations are at their most acute as commitments to meet carbon emission reduction targets and the EU emissions trading scheme are subject to variable economic, environmental and corporate influences. Renewable companies are pressing for a 30 per cent renewable energy target for the UK by 2030.29 Electricity generated from renewable sources increased by 30 per cent between 2012 and 2013 to 53.7 per cent terawatt hours,30 with wind power taking the

21

See House of Commons Library, ‘Fuel poverty’, SN/SG/5115 (23 July 2012). Houses of Parliament, Residential Heat Pumps POSTNOTE Number 426 (January 2013). 23 There are also smart meters. House of Commons Library, Smart Meters SN/SC/6179 (3 December 2012). 24 House of Commons Library, Simplifying Energy Tariffs SNSC-6440 (23 November 2012). 25 House of Commons Library, Smart Meters SN06179 (11 September 2014). 26 House of Commons Library, Zero Carbon Homes SN 6678 (18 November 2013). 27 House of Commons Library, Simplifying Energy Tariffs SN06440 (6 February 2014). 28 ENDS Report 478 (December 2014), 14. 29 ENDS Report 476 (October 2014), 7. 30 ENDS Report 477 (November, 2014), 52. 22

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lead. Oil prices determine many policy choices and present-day fluctuations in pricing may raise issues about the economic viability of alternatives such as the cost of shale gas extraction and nuclear energy. If global warming is to be limited to 2°C this would have profound effects on the economy and future planning. Doubts about UK’s continued membership of the EU are likely to add uncertainties to energy policy-making, especially in an era of oil price fluctuations.

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ENERGY AND ENVIRONMENT STUDIES: THE ROLE OF LEGAL SCHOLARSHIP Gavin F. M. Little1

For legal scholars, the interrelated issues of managing fossil fuel use, developing renewable energy, reducing CO2 emissions and mitigating potentially catastrophic man-made climate change pose a challenging question. While it is easy to see what the role of practising lawyers is in this context – advising their clients on the technicalities and practicalities of the legal and regulatory regimes governing the energy sector and related environmental law – it is less straightforward to identify a distinctive role for legal scholars. Put bluntly, it should be asked what they can bring to the energy and environment research table. It may seem surprising that a legal academic should ask this question. But it is an important one to ask, for some of the issues under consideration in energy and environment studies raise real difficulties for legal scholars. Consideration should therefore be given to these difficulties before attempting to answer the question. MAPPING ENERGY AND ENVIRONMENTAL LAW SCHOLARSHIP Richard Macrory’s analysis of Tom Burke’s differentiation between what he called the old and the new environmental agendas provides a good starting point for discussion.2 The old agenda is concerned with issues such as pollution control, where there is a broad consensus on the part of scientific and technical experts over what the problems are and how they should be tackled. Importantly, there is also consensus on the part of policy-makers, citizens and industry stakeholders that legal intervention is necessary and what, broadly, it should be. In

1

2

Gavin Little is a Professor in the Stirling Law School, University of Stirling. He specialises in environmental law, and has particular interests in public law aspects of environmental governance and in interdisciplinary approaches to legal scholarship. The themes and issues sketched out in the chapter are analysed and developed in detail in his article ‘Developing environmental law scholarship: going beyond the legal space’ in Legal Studies (2015, forthcoming). R. Macrory, Regulation, Enforcement and Governance in Environmental Law (Hart, 2014), p. 245.

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this context, as Macrory says, the ‘basic legal toolkit is not called into question’.3 Established legal principles and concepts which have been created by courts and lawyers and are central to the world of mainstream legal debate and ideas – such as criminal responsibility, personal and property rights, contractual agreements, legal obligations, liability, compensation and the vires of public authorities – feature heavily in this sort of area, even if they are now largely incorporated into legislation. Some aspects of energy and environment law, such as planning law aspects of power infrastructure development, the contractual relationships between energy suppliers and their customers, the judicial review of energy regulators, or human rights based challenges, can therefore be characterised as old agenda issues. Here, legal scholars, irrespective of whether or not they consider their research to be doctrinal or socio-legal in nature, have a clear and conventional role: to develop legal understanding from interpretative enquiry into the operation of legal principle and processes in the energy and environment context. The new environmental agenda, however, differs significantly. It is concerned with highly contested areas where scientific and technological opinion is divided or incomplete, and there is a relative lack of consensus among policy-makers, industry stakeholders and citizens as to how to proceed.4 As the essays in this book demonstrate, the macro-level debates on how to limit fossil fuel use, develop renewable energy and mitigate climate change are new agenda issues par excellence. Importantly, legal scholars wishing to contribute to these debates face some pretty fundamental challenges. This is because, relative to old agenda topics, scholars are for the most part semi-detached from the core business of mainstream legal research – the analysis of legal principle and the world of courts and adjudication. The polycentric nature of the issues under consideration means that they are generally not adjudicated by courts: they are often intrinsically non-justiciable and are conceptualised as matters of wider social, economic or state policy, rather than as individual legal rights. Put in simple terms, specialist understanding of legal principle is of limited relevance in this sort of context: inevitably, this makes life more difficult for legal scholars. The situation is compounded by the substance of large parts of energy and environment law, in the EU at least. Here, energy and environment law and regulation is made up of a complex mix of EU policy and legislation, domestic policy and legislation, and administrative rules. Much of it is dry, detailed and regulatory in nature. The substantive content of the law is often intended to give effect to technocratic policies which have emerged from trade-offs between EU and national policy-makers, industry, other stakeholders, and scientific and technical advisers. What emerges as law to be implemented through the EU and domestic regulatory systems is therefore the articulation of the policy compromises struck by these key interest groups: frequently, there is little or no legal principle involved. This has significant knock-on implications for legal scholars working in this sort of area. It leads to a focus on issues such as governance, the design of legislative and regulatory models, standard-setting, the inter-relationship 3 4

Ibid., p. 245. Ibid., p. 245.

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between substantive law and policy, and implementation and enforcement. But at a more fundamental level, legal scholarship in what might loosely be called the new agenda areas of energy and environment law can also be characterised as derivative: it is concerned largely with following up on and then analysing the technicalities of the rules, policies and processes created by others. Moreover, while those such as policy specialists, economists, scientists and engineers are involved in developing new ideas, systems and technologies which might contribute to climate change mitigation, the role of legal scholarship appears pedestrian by comparison: it is seen as part of the intellectual baggage train, rather than the vanguard of innovation. Unlike those other disciplines, legal scholarship is not, on the face of it, engaged directly in trying to save humanity from itself. WHAT LEGAL SCHOLARSHIP CAN CONTRIBUTE With these points in mind, a clearer idea of what legal scholarship can bring to the energy and environment table starts to emerge. Those scholars working in old agenda areas are able to bring specialist skills and understanding to bear in order to develop conventional legal knowledge in the energy and environment context. As in other areas of mainstream legal scholarship, this type of knowledge has a wider value beyond the confines of legal academia through facilitating the development of legislative policy at EU and national levels; commercial relationships and those between citizens, the state and industry; and the approaches taken by the senior judiciary when adjudicating disputes. And, notwithstanding the challenges posed by new agenda issues outlined above, it is clear that legal scholars working in these fields also have a valuable role in taking forward wider discourse and debate on environment and energy. For, despite the difficulties it faces, legal research can and does make an important contribution to the development of society’s understanding of governance and regulation – and huge improvements in both are required if humanity is to avert climate change of human origin on a potentially catastrophic scale. Moreover, there is a growing understanding across disciplinary divides that climate change caused by human activity requires a fundamental reconception of knowledge and understanding.5 Determining how humanity responds 5

For extensive discussion of these issues, see Little, ‘Developing environmental law scholarship’; and D. B. Rose, T. van Dooren, M. Chrulew, S. Cooke, M. Kearnes and E. O’Gorman, ‘Thinking through the environment, unsettling the humanities’, Environmental Humanities 1 (2012), 1–5, at 1–2, available at http://environmentalhumanities.org/arch/vol1/EH1.1.pdf. See also S. Sӧrlin, ‘Reconfiguring environmental expertise’, Environmental Science and Policy 28 (2013), 14–24; S. Sӧrlin, ‘Environmental humanities: why should biologists interested in the environment take humanities seriously?, BioScience 62(9) (2012), 788–9; T. Griffith, ‘The humanities and an environmentally sustainable Australia’, Australia Humanities Review 43 (2007), available at www. australianhumanitiesreview.org/archive/Issue-December-2007/EcoHumanities/EcoGriffiths.html; D. K. Swearer, ‘Introduction’, in D. K. Swearer (ed.), Ecology and the Environment: Perspectives from the Humanities (Harvard University Press, 2008), pp. 9–20; and European Science Foundation and European Cooperation in Science and Technology, ‘Responses to Environmental and Societal Challenges for our Unstable Earth (RESCUE)’ (2012), available at www.esf.org/ fileadmin/Public_documents/Publications/rescue.pdf

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to the existential risks created by its own actions cannot be left to the scientific and technological disciplines. While they can develop understanding of the environment and devise new energy technologies to improve climate change mitigation, man-made climate change is, nonetheless, an essentially human and social happening. A range of disciplines from across the humanities and social sciences – including law – should therefore work with each other and science and technology to address it through the development of new, interdisciplinary ways of thinking.6 This is an exciting intellectual prospect for legal scholarship and there are many ways in which it can engage with it.7 For example, as inferred above, understanding how law and regulation operates and its ability to facilitate change and optimise the management of human behaviour has to be a key part of humanity’s response to climate change. Legal scholarship can facilitate wider understanding of law’s potential (and also its limitations) in this context. Legal research can also provide valuable narratives which bring together a wide range of issues – social, ethical, political and scientific as well as legal. These can, like narratives in policy studies, philosophy, history and economics, contextualise complex situations in ways that are accessible to those working in other disciplines, thereby facilitating deeper interdisciplinary understanding. The best legal scholarship can, among other things, bring out and evaluate the power imbalances, inequalities, injustices and inefficiencies inherent in law and policy and the ways in which they are implemented – and then articulate proposals for reform. It can critically analyse the operation of politico-legal structures and the standards which have been set in law and regulation. Surely, therefore, to answer the question posed at the start of the chapter, legal scholars can be confident that they have much which is of value to contribute to energy and environment research.

6 7

Ibid. For extensive discussion, see Little, ‘Developing environmental law scholarship’.

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OVERVIEW OF THE EU CLIMATE POLICY BASED ON THE 2030 FRAMEWORK Noriko Fujiwara1

INTRODUCTION The European Union, under the new Commission led by Jean-Claude Juncker, set out among one of ten priorities a new initiative for the Energy Union to secure affordable and climate-friendly energy. It would lead to a sustainable, low-carbon and environmentally friendly economy through five mutually related and reinforcing dimensions which encompass various policy areas: secure supplies; internal energy market; energy efficiency; greenhouse gas (GHG) emission reductions; and research and innovation in energy.2 For EU climate change mitigation action, the first step was setting the target of reducing GHG emissions by at least 40 per cent by 2030 from 1990 levels.3 The second step is reforming the EU emissions trading system (EU ETS) and investing more in the development and deployment of renewable energy sources.

1

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Noriko Fujiwara is Associate Research Fellow and Head of Project Development at the Energy and Climate Change Unit, Centre for European Policy Studies (CEPS) in Brussels. She has undertaken research on climate change and energy at international, EU and country levels. Recent topics include low-carbon technology and innovation, post-carbon cities, climate change mitigation, energy efficiency, renewable energy, the EU emissions trading scheme and international carbon markets. She has a DPhil in International Relations from the University of Sussex, an MPhil in Development Studies from the University of Cambridge and a Master of Law (International Political Economy) from Hitotsubashi University, Japan. European Commission, ‘A framework strategy for a resilient Energy Union with a forward-looking climate change policy’, Energy Union Package, Communication from the Commission to the European Parliament, the Council, the European Economic and Social Committee, the Committee of the Regions and the European Investment Bank’, COM 80 final, Brussels (25 February 2015). Council of the European Union, European Council Conclusions 23 and 24 October 2014, available at www.consilium.europa.eu/uedocs/cms_Data/docs/pressdata/en/ec/145397.pdf

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GHG TARGET AND INTENDED NATIONALLY DETERMINED CONTRIBUTIONS (INDC) The EU is currently implementing the 2020 Climate and Energy Package, centred on three specific targets focusing on GHG emission reductions, renewable energy and energy efficiency up to 2020 (20-20-20).4 Due to the economic crisis since 2008, however, GHG emissions have resulted in a significant fall EU-wide and across member states. It soon became clear that the EU would be on track to meet the 2020 GHG target and therefore this target would not create enough incentives for investments in low-carbon technologies or innovation. Based on this, the European Commission launched a legislative proposal for the 2030 Energy and Climate Policy Framework in January 2014, which was consulted with the European Parliament and the Council of Ministers and finally approved at the European Council in October 2014.5 The Council Conclusions include agreement on the target of reducing GHG emissions by at least 40 per cent by 2030 from 1990 levels alongside other targets on renewable energy and energy efficiency. The level of the 2030 GHG target is aligned with the EU’s long-term goal of cutting GHG emissions by at least 80 per cent by 2050. This target is not only legally binding for the EU and its member states within the jurisdiction, but also an international commitment under the United Nation Framework Convention on Climate Change (UNFCCC), known as Intended Nationally Determined Commitment (INDC).6 EU ETS REFORM The ETS covers 11,000 power plants and industrial installations in the European Economic Area (EEA) which consists of thirty-one European countries7 as well as airlines for flights to, from and within the area. In 2013–20 ETS sectors will have to lower GHG emissions by 21 per cent compared to 2005, which has been largely achieved.8

4

5 6

7

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A 20 per cent reduction in EU greenhouse gas emissions from 1990 levels; increasing the share of EU energy consumption produced from renewable resources to 20 per cent; and a 20 per cent improvement in the EU’s energy efficiency. The three targets resulted in four major measures such as ETS reform; national targets for non-ETS emissions; national targets for renewable energy; and carbon capture and storage (CCS). Council of the European Union, European Council Conclusions. Parties to UNFCCC were obliged to submit respective INDCs including quantifiable information by March 2015 with a view to reaching a new international agreement at the Conference of Parties (COP21) in December 2015; European Commission, ‘The Paris Protocol – a blueprint for tackling global climate change beyond 2020’, Energy Union Package, Communication from the Commission to the European Parliament and the Council, COM (2015) 81 final/2, Brussels, 4 March 2015; Latvian Presidency of the Council of the European Union, Intended Nationally Determined Contribution of the EU and its Member States, Submission by Latvia and the European Commission on behalf of the European Union and its Member States, Riga, 6 March 2015. The EEA refers to twenty-eight EU member states and three non-EU countries, Iceland, Lichtenstein and Norway. The system covers about 45 per cent of the EU’s GHG emissions. In 2013–16 only emissions from flights within the EEA will be subject to the EU ETS.

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To meet the EU’s overall 2030 target, the sectors covered by the EU ETS would have to reduce their GHG emissions by 43 per cent compared to 2005. Despite the EU’s emphasis on the ETS being the flagship of its climate policy, the current system has not functioned well at the level it has been expected to, which has triggered a debate on future reform. The main problem has been an imbalance between demand and supply in emission allowances (European allowances, EUAs), which has led to a fall in EUA prices. The over-supply of allowances accumulated not only because of a lack of demand as a result of the economic crisis and a decrease in production levels, but also because of the inflow of international credits generated by the Clean Development Mechanism and Joint Implementation. Moreover, it is assumed that overlapping policy objectives such as renewable support measures by certain member states might have further reduced demand for allowances. In response the EU agreed to reschedule auctioning schedules by backloading allowances and re-introducing them at a later stage.9 The next step is to implement a mid-term structural reform. As part of the 2030 framework, the European Commission proposed a number of concrete revisions such as increasing the declining annual reduction factor from 1.74 per cent to 2.2 per cent, redistributing 90 per cent of allowances to be auctioned among all twentyeight member states and 10 per cent among lower income member states, and the establishment of an innovation fund (New Entrant Reserve, NER400) and a modernisation fund while continuing free allocation to energy-intensive industry sectors at risk of carbon leakage.10 The Commission also proposed a Market Stability Reserve11 to address the surplus of allowances and improve the resilience of the ETS against external shocks by adjusting the amount of allowances to be auctioned. GHG EMISSIONS FROM NON-ETS SECTORS Some sectors remain outside the EU ETS, for example, transport (except European aviation), buildings, agriculture12 and waste. Maritime shipping and international/intercontinental aviation are not subject to the ETS; instead, a global approach is preferred.13 Under the 2020 package and through the Effort-Sharing Decision, member states are directly responsible 9

European Commission, ‘Commission Regulation (EU) No 176/2014 of 25 February 2014 amending Regulation (EU) No 1031/2010 in particular to determine the volumes of greenhouse gas emission allowances to be auctioned in 2013-20’, Official Journal of the European Union (26 February 2014), L56/11-13. 10 Council of the European Union, European Council Conclusions. 11 European Commission, ‘Proposal for a decision of the European Parliament and of the Council concerning the establishment and operation of a market stability reserve for the Union greenhouse gas emission trading scheme and amending Directive 2003/87/EC’, COM 20 final, Brussels (22 January 2014). 12 Emissions from land use, land use change and forestry (LULUCF) are not included. 13 See http://ec.europa.eu/clima/policies/transport/shipping/index_en.htm and http://ec.europa.eu/ clima/policies/transport/aviation/index_en.htm

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for reducing GHG emissions from these sectors by 10 per cent in 2013–20 compared to 2005. Indicative examples of national measures may include a shift from transport based on fossil fuels, promotion of public transport, ambitious energy performance standards for buildings, more efficient heating systems, renewable energy for heating, more efficient farming practices and conversion of animal waste to biogas. In addition, some measures taken at the EU level may help member states reduce GHG emissions: CO2 emission standards for new cars and vans; requirements to improve the energy performance of buildings; eco-design requirements for energyrelated products; energy labelling systems to inform consumers; restrictions on fluorinated industrial gases (F-gases); and implementation of other EU environmental policies such as those on soil protection and waste.14 To meet the EU’s overall 2030 target, sectors outside the EU ETS would need to cut their GHG emissions by 30 per cent below the 2005 level. Based on the principles applied to the Effort Sharing Decision, efforts will be distributed among member states with the level of targets ranging from 0 per cent to 40 per cent. As the next step, the European Council invited the European Commission to prepare new proposals in the transport and the agriculture and land-use sectors.15 CONCLUSION The EU has maintained its priorities regarding climate policy and strived to set aspirational goals and associated targets in a timely manner in order to launch an Energy Union beyond 2020 and to lead international negotiations with a view to reaching a legally binding agreement at COP21. Having largely completed the infrastructure to implement the EU ETS, the EU introduced some fundamental changes for 2013–20 such as a shift to the EU-wide cap, adopting auctioning as the default allocation method and restricting the use of international credits, which will be maintained beyond 2020. Among other things, a structural reform is expected to improve the system’s performance to deal with imbalance in demand and supply of allowances and mitigate the effects of external shocks. There is less certainty about the sectors which were either later included in the ETS (European aviation) or remain excluded from the system.

14 15

See http://ec.europa.eu/clima/policies/effort/index_en.htm Upon request by EU heads of state or government, the European Commission should further examine instruments and measures for a comprehensive and technology-neutral approach for the promotion of emissions reduction and energy efficiency in transport, for electric transportation and for renewable energy sources in transport also after 2020. The Commission should also optimise the agriculture sector’s contribution to greenhouse gas mitigation and sequestration, including through afforestation in the context of the need to examine the best means of support for food production (Council of the European Union, European Council Conclusions).

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Finally, it is important to recognise the recent shift from climate change to energy security as the main driver for framing the EU debate on energy policy. In this new mindset, support measures for renewable energy are prioritised not only as a tool to achieve the GHG target but as indigenous energy resources. To a lesser extent, energy efficiency measures are also prioritised as a tool to moderate energy demand, thereby potentially reducing dependence on imports.16 This shift would require a deeper level of integration between EU climate and energy policies in coming years.

16

European Commission, ‘European Energy Security Strategy’, Communication from the Commission to the European Parliament and the Council, Brussels, COM 330 final (28 May 2014); European Commission, ‘In-depth study of European Energy Security’, Commission Staff Working Document accompanying the document, Communication from the Commission to the Council and the European Parliament: European energy security strategy, SWD 330 final/3, Brussels (2 July 2014).

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115 CLIMATE POLICY INSTRUMENTATION IN SPAIN Mikel González-Eguino,1 Anil Markandya2 and Luis Rey3

INTRODUCTION In 2014 the European Union adopted a new climate and energy package for 2030 with the following three objectives: (1) a reduction in CO2 emissions by 40 per cent relative to 1990 levels; (2) a penetration of renewable energy by 27 per cent; and (3) a target of improving energy efficiency by 27 per cent. 1

2

3

Mikel González-Eguino is a Senior Researcher at the Basque Centre for Climate Change (BC3) in Bilbao. He has a PhD in Economics (University of the Basque Country, 2006) and a degree in Engineering (University of Deusto, 2001). His main interests lie in the fields of environmental, energy and public economics, and his work has been published in several of the leading journals in the field including Climate Policy, Ecological Economics, Energy Economics, Journal of Environmental Management, The Energy Journal and Water Policy. He has worked on environmental and economy-related issues for European, Spanish and Basque firms and institutions. His doctoral thesis won him the Enrique Fuentes Quintana prize (FUNCAS, 2006) and he has obtained his accreditation as ‘Professor Titular– in Economics (ANECA, 2012). The research leading to this chapter has received funding from the European Union FP7-ENV-2012.6.1-4: Exploiting the full potential of economic instruments to achieve the EU’s key greenhouse gas emissions reductions targets for 2030 and 2050 under the grant agreement n° 308680. Professor Anil Markandya has worked in the field of resource and environmental economics for more than thirty years. He has held academic positions at the universities of Princeton and Harvard in the USA and at University College London and Bath University in the UK. He was a lead author for chapters of the third and fourth IPCC Assessment Reports on Climate Change (which were awarded a share of the Nobel Peace Prize in 2007) as well as one for the fifth IPCC Report that has just been published. In 2008 he was nominated by Cambridge University as one of the top fifty contributors to thinking on sustainability in the world. In 2012 he was elected President of the European Association of Environmental and Resource Economics and in 2013 became a member of the Scientific Council of the European Environment Agency. Anil Markandya is Director of the Basque Centre for Climate Change (BC3) in Bilbao and is honorary Professor of Economics at the University of Bath. Luis Rey received his undergraduate education at the University of Navarra (Pamplona, Spain), where he obtained a degree in Economics in 2003. The following year he obtained a Masters degree in Economics and Finance at the University of Navarra. He holds a PhD in Economics from the European University Institute in Florence, Italy. He has worked at the consultancy firm Naider in Bilbao, Spain and the Economics for Energy research centre in Vigo, Spain. He currently works as a Postdoctoral Researcher at the Basque Centre for Climate Change (BC3). His research interests are energy economics, environmental economics and international economics.

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A transition towards a low-carbon economy that at the same time stimulates economic growth and ensures competitiveness needs a careful design of climate instruments. Some authors have noted the problem of overlapping regulation.4 Although there are important reasons to have different instruments, it is clear that components of the mix and their interaction is an important research area but one that has not been much explored.5 The objective of this chapter is to review the climate policy instrument mix in Spain and explore the main interactions. The following section classifies the main instruments according to four different policy landscapes. We then go on to assess each of the instruments by policy landscape and then to analyse the overall instrument mix before offering our concluding thoughts. CLASSIFICATION OF THE INSTRUMENTS INTO POLICY LANDSCAPES The full list of instruments related to climate change in Spain is very diverse. In this chapter a selection of the fourteen main instruments are analysed. The selected instruments were categorised following the taxonomy of instruments developed by Görlach (2013):6 1. Carbon Pricing: includes policies that price CO2 emissions or other changes in the relative prices of fuel use. Apart from the obvious candidates (carbon taxes and emissions trading) this would also include the reform or removal of fossil fuel subsidies. 2. Energy Efficiency and Energy Consumption: includes measures targeted at either increasing the efficiency or at reducing overall energy consumption. 3. Promotion of Renewable Sources of Energy: includes policies aimed at increasing the share of energy from renewable sources (solar, wind, hydro, biomass, geothermal) 4. Non-CO2 mitigation: covers policies geared at reducing non-CO2 greenhouse gas emissions, typically from sectors other than the energy sector. It may include emissions like methane emissions from landfill sites or animal husbandry. The list of instruments for Spain, along with their landscape classifications, may be seen in Table 115.1. 4

5

6

C. Böhringer, H. Loschel and U. Moslener, ‘Efficiency losses from overlapping regulation of EU carbon emissions’, Journal of Regulatory Economics 33(3) (2008), 299–317. See P. del Río, ‘Interactions between climate and energy policies: the case of Spain’, Climate Policy 9(2) (2009), 119–38; P. Linares, F. J. Santos and M. Ventosa, ‘Interactions of carbon reduction and renewable support policies in electricity markets: a review of existing results and some recommendations for a coordinated regulation’, Climate Policy 8(4) (2008), 377–94; and J. Sijm, ‘The interaction between the EU emissions trading scheme and national energy policies’, Climate Policy 5(1) (2005), 79–96. B. Görlach, ‘What constitutes an optimal climate policy mix?’, CECILIA2050 project, Deliverable 1.1, Berlin (2013).

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Table 115.1 Classification of the instruments by policy landscapes Policy landscapes Policy instrument EU ETS

Carbon pricing

Energy efficiency

ü

ü

FIT-RES

Promotion of Non-CO2 renewable mitigation ü

ü

ü

Reduced subsidies for coal production

ü

Excise tax on oil products

ü

ü

Excise tax on electricity

ü

ü

Excise tax on natural gas

ü

ü

CO2-based vehicle registration tax on new cars

ü

ü

Technical Code of Buildings (CTE)

ü

Subsidies on building refurbishment

ü

Energy labelling for appliances

ü

Subsidies for replacing inefficient cars

ü

ü

Incentives to R&D on energy and climate change

ü

ü

Subsidies for equipment for anaerobic digestion

ü

ü

Tax on emissions in Andalusia

ü

ü

ü

ASSESSMENT OF INSTRUMENT WITHIN EACH POLICY LANDSCAPES Carbon pricing The most relevant instrument in this domain is the EU Emission Trading Scheme (EU ETS). In Spain, it affects around 1,100 installations, which account for approximately 45 per cent of total GHG emissions. Allowances will decrease annually, leading to a 21 per cent reduction of GHGs in the EU ETS sector by 2020, compared with 2005. The EU ETS could lead to ‘carbon leakage’, but there is no empirical evidence of this for Spain. The scheme has been criticised for two reasons: ‘windfall profits’ and ‘over-allocation’.7 These factors have generated price uncertainty, which arguably reduces the cost-effectiveness of this instrument in the medium/long term. Another relevant instrument is the reduction of subsidies for coal production that have a negative impact on GHG emissions. From 2005 to 2011 subsidies for the coal sector decreased from €503 million (€61,200 per employee)

7

D. Ellerman and P. L. Joskow, The European Union’s Emissions Trading System in Perspective (Pew Center on Global Climate Change, 2008).

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to around €380 million, while coal production decreased from 6,626 Ktoe to 2,287 Ktoe. Council Decision 2010/787/EU stipulates the phase-out of subsidies by 2018 and Spain will have to progressively reduce its support to meet this target. The excise tax on oil products is also very important. It was introduced to raise revenue, but indirectly reduces GHGs. In the case of oil the tax component (as a percentage of total price) of petrol and diesel is 51 per cent and 44 per cent respectively. In November 2012, Spain had the fourthlowest petrol prices and the third-lowest diesel prices in the EU27.8 In 1993 Spain included an excise tax on electricity production. According to Council Directive 92/12/EEC, double taxation of electricity is partly justified by the social costs not reflected in the final price. Currently the excise tax rate is 4.8 per cent of the final price (excluding VAT). Any electricity produced under the feed-in tariff regime is not subject to this tax. In addition to this excise tax, in 2013 the Spanish government implemented a new tax of 7 per cent on the revenue received by electricity generators for all the technologies. The main objective is to reduce the huge tariff deficit that the government owes to the utilities, estimated in 2014 at €26 billion, due to the accumulated difference between the regulated price for consumers and the market price. While taxes on GHG emissions are considered cost-effective, from both the static and the dynamic point of view,9 the effectiveness decreases when energy sources are levied instead of emissions. According to González-Eguino (2011) tax on electricity (without distinction of origin) is one of worst-performing measures in terms of cost.10 In addition to the new tax on electricity, the Spanish government implemented an excise tax on gas consumption in 2013. Gas consumption is only subject to VAT (21 per cent of the price for all consumers), but it will increase by 1.15 €/gigajoule consumed. In 2008, a CO2-based vehicle registration taxation was introduced. The tax rates are shown in Table 115.2, which are the minimum established by the central government. The static efficiency of this tax may be low, given that it does not provide a proper incentive to reduce emissions. However, the new system may induce to a higher level of innovation and diffusion of lowemission cars. Thus, the dynamic efficiency could be high. There is, however, no empirical evidence for this. Finally, there is regional taxation. Although Galicia was a pioneer in this matter, the scope of Andalucia’s legislation is much wider. For example, there are taxes on CO2, SOx and NOx emissions. 8

MINETUR (2011), ‘Precios de carburantes y combustibles (Noviembre 2012)’, available at www. minetur.gob.es/energia/petroleo/Precios/Informes/InformesMensuales/2012/noviembre2012.pdf 9 OECD (2013), ‘The economics of climate change mitigation: policies and options for global action beyond 2012’, available at www.oecd.org/env/cc/theeconomicsofclimatechangemitigationpoliciesandoptionsforglobalactionbeyond2012.htm 10 -M. González-Eguino, ‘The importance of the design of market-based instruments for CO2 mitigation: an AGE analysis for Spain’, Ecological Economics 70(12) (2011), 2292–302.

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Table 115.2 Vehicle registration tax rates in Spain, 2008 CO2 emissions g per km < 120

Tax rate (%)

Tax rate in Canary Islands

0

0

≥ 120, < 160

4.75

3.75

≥ 160, < 200

9.75

8.75

14.75

13.75

≥ 200

Source: Spanish Ministry of Agriculture, Food and Environment.

Revenues are used for environmental purposes such as the protection of natural areas. Around €4 million was raised in 2011. Most experts claim that it is necessary to harmonise environmental taxation among Spanish regions as they must be compatible with the EU and Spanish legislation. In summary, the development of carbon pricing in Spain is still very slow. Spain has the lowest environmental taxes (as a percentage of GDP) in the EU27. In 2009 environmental taxes only accounted for 1.6 per cent of the GDP and on average 2.4% of the GDP of the EU27. Energy efficiency One of the key instruments to promote energy efficiency in Spain is the Technical Code of Buildings (CTE) for new buildings, which account for around 40 per cent of GHG emissions in Spain. The CTE establishes technological standards and therefore does not provide any flexibility to adopt cheap abatement options. However, considering the landlord–tenant dilemma present in the investment decision in the building sector, it could be a good ‘second best’ instrument. Subsidies for domestic building refurbishment were included within the National Plan of Housing and Refurbishment 2009–12. After the housing market crash in 2008 the refurbishment of old buildings was the only way to improve energy efficiency in this sector. The subsidies were in place between 2009 and 2012. During this period, the requirements and the total amount subsidised changed. The most recent figures allowed 20 per cent of the expenses for improving energy efficiency in buildings to be subsidised. The total amount granted could not exceed €6,750 annually per household. Another instrument is energy-labelling for cars, building and appliances. Energy labels provide incentives to the industry to develop and invest in new technology. Linked to this instrument are subsidies for replacing inefficient cars. In 2012, the Spanish government launched Plan PIVE, a plan for replacing inefficient cars, which was renewed in 2015. People wishing to replace their old car can receive a subsidy of around €1,500. A similar plan exists at regional level, for example in the Basque Country, to replace windows, appliances and other energy-consuming devices.

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Promotion of renewable sources There are two main instruments for promoting renewables. The first is a feed-in tariff for renewable energy sources (FIT-RES). A FIT-RES regime has been in place for renewable sources of electricity (RES) since 1997. Owners of distribution networks are obliged to purchase all the electricity supplied by generators in the special regime. Special-regime companies can also decide to take part in the wholesale market, where they receive a premium over the market price. Those installations with a capacity higher than 50 MW are not eligible for price premiums. The Spanish FIT-RES has been successful in increasing the supply of renewable energy, particularly wind-generated electricity11 which in 2004 represented 8.3 per cent of gross final energy consumption, but by 2013 this figure had increased to 15.4 per cent. The price premium has been high enough to incentivise the production of renewable electricity. IDAE (2012) calculates that in 2010 renewable energy sources avoided 34.3 million tonnes of CO2 emissions in power generation.12 Although the fixed tariff is payable over the complete useful life of the asset used in generation, the recent changes introduced by the Spanish government have increased uncertainty about the scheme. Table 115.3 shows the premiums paid by different technologies in 2012 after a change in this instrument. The second main instrument is the introduction of economic incentives to research and development in energy and climate change. In 2011, €76.2 million were budgeted for the research and development in energy and climate change. Sixty per cent of the budget was used to finance projects in large firms. Most of the funding was in the form of loans (85 per cent) while subsidies accounted for around 15 per cent of the budget. Non-CO2 mitigation measures One of the few instruments to reduce non-CO2 emissions in Spain are the subsidies for investment in equipment for anaerobic digestion. This instrument is part of the Slurry Biodigestion Plan, which was adopted in 2008. The objective is to reduce GHG emissions by slurry treatments which allow the capture and quantification of biogas and the subsequent energy recovery. The final objective is to avoid 1.78 MT CO2-e per year. Subsidies, which are voluntary, are allocated to purchase equipment for anaerobic digestion, and can be awarded to both small farms and central installations. The subsidy per installation depends on the capacity of the installation (around €100/ m3). This plan was in place during the period 2008–12 but there is no ex-post assessment of it.

11

P. del Río, ‘Ten years of renewable electricity policies in Spain: An analysis of successive feed-in tariff reforms’, Energy Policy 36(8) (2008), 2917–29. 12 Institute for Energy Diversification and Saving, ‘Observatorio energías renovables’, Secretaría General, Departamento de Planificación y Estudios, 3rd edn (2011), available at www.idae.es/ uploads/documentos/documentos_Observatorio2011_c86aa64b.pdf

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Table 115.3 Feed-in tariffs for RES in Spain, 2012

Solar PV

Capacity

Time limit

C ≤ 100 kW

First 30 years

48.87

100 kW < C ≤ 10 MW

First 30 years

46.33

10 MW < C ≤ 50 MW

First 30 years

25.50

First 25 years

29.90

Afterwards

23.92

Solar Thermoelectric

Wind

Hydroelectric

Biomass

C ≤ 10 MW

C ≤ 2 MW

First 20 years

8.13

Afterwards

6.79

First 25 years

8.66

Afterwards

7.79

First 15 years Afterwards

2 MW < C

Fixed tariff (euro cent/kWh)

First 15 years Afterwards

13.95 9.41 11.93 8.95

Source: Spanish Ministry of Industry, Energy and Tourism.

AN ASSESSMENT OF THE OVERALL INSTRUMENT MIX To assess the overall instrument mix we will use three criteria: environmental effectiveness, cost-effectiveness and feasibility. Environmental effectiveness Given that the EU ETS is the key instrument, the environmental effectiveness of the Spanish policy mix depends on the performance of this instrument. The EU ETS ensured that a certain quantity of emissions would be reduced, although the economic crisis is probably the driving force for the reduction. In Spain, however, the FIT-RES has been the main instrument to reduce local emissions and increase the share of renewables in the electricity sector. The FIT-RES has been successful in raising the share of renewables, particularly wind electricity, even with the very low prices of CO2 in the ETS market. The environmental effectiveness of other instruments, which do not cover the EU ETS sectors, is limited. Transport, the largest non-ETS emitter, is mainly affected by the excise tax on oil products but emissions in this sector have been rising. In buildings, the effectiveness of the CTE has been also very low, since it was implemented after the housing boom. The impact of other instruments, such as the subsidies on building refurbishment and energy labelling for appliances, has been much narrower.

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Cost-effectiveness In general, market-based instruments are considered cost-effective. The EU ETS, for instance, is a system that gives companies the flexibility to meet their targets. Taxes on energy products are also a flexible mechanism that facilitates the adoption of the most cost-effective measures. However, criticism has arisen in two issues: ‘windfall profits’ and ‘over-allocation’.13 In Spain, the FIT-RES has been successful in increasing the share of renewables, but the electricity cost has risen considerably. Although the static effectiveness of the EU ETS does not increase in interactions with other instruments, it is argued that the FIT-RES and the economic incentives to research and development may in the future reduce the abatement costs, improving the dynamic effectiveness.14 Feasibility The main problem with the Spanish instrument mix has arisen from the FITRES, given that the system has raised considerably electricity production costs. For several consumer groups, electricity prices are capped and so consumers did not notice the rise in cost. Hence the acceptance of the instrument by the general public is high. However, the government has generated a huge tariff deficit that is owed to the utilities. To solve the problem the government has suspended the FIT-RES scheme for new installations and has increased excise tax on electricity and natural gas. These measures may affect negatively both the environmental effectiveness and the cost-effectiveness of the instrument mix. Some experts considered that an increase on the excise tax on oil products would be more effective.15 CONCLUSION The key instruments in the Spanish policy mix are the ETS and the FIT-RES. Carbon pricing is mainly driven by the EU ETS. At its outset, the EU ETS was characterised by an excessive number of allowances, and the financial crisis led to a surplus of unused allowances and thus to low prices. Despite the start-up problems, the system ensures a certain reduction in emissions and the flexibility to make it relatively cost-effective. The FIT-RES has also been essential in the promotion of renewable energy sources. However, with the current electricity market design, it has also led to an increase in electricity production costs and a major fiscal burden to the central budget. The economic downturn has also influenced the promotion of energy efficiency. Several instruments have been launched with the double objective

13

Ellerman and Joskow, The European Union’s Emissions Trading System in Perspective. P. Linares, F. J. Santos and M. Ventosa, ‘Interactions of carbon reduction and renewable support policies in electricity markets: a review of existing results and some recommendations for a coordinated regulation’, Climate Policy 8(4) (2008), 377–94. 15 IEA, Energy Policies of IEA Countries: Spain Review (IEA/OECD, 2009), available at http:// www.iea.org/publications/freepublications/publication/spain2009.pdf 14

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of reducing energy consumption and encouraging economic activity. For instance, subsidies for building refurbishments or the purchase of energyefficient cars were implemented to meet both goals. Although, in general, these instruments are well accepted, there is little empirical evidence as to their effectiveness. Finally, instrument interactions take place mainly around the EU ETS. Although other instruments cannot improve the environmental effectiveness of the EU ETS, they contribute to Spanish targets on GHG emission reduction, energy efficiency and the promotion of renewable energy sources. It is claimed that the other instruments alter abatement costs and thus reduce the static cost-effectiveness of the EU ETS.16 However, the FIT-RES and the economic incentives to R&D may reduce the abatement costs in the future.

16

J. Sijm, ‘The interaction between the EU emissions trading scheme and national energy policies’, Climate Policy 5(1) (2005), 79–96; and del Río, ‘Interactions between climate and energy policies’.

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116

PLANNING CONSENT AND THE LAW OF NUISANCE Francis McManus1

The following chapter focuses solely on the rather narrow issue as to the effect of planning permission on the common law of nuisance; at a more general level, however, the issues discussed below may have wider implications as to how public law impacts on private law, a subject which has traditionally troubled the courts over the years. Environmental law is, by its very nature, fragmented. Not only is there now a vast plethora of diverse legislation which ranges from contaminated land to climate change, often each discrete area of law itself comprises a battery of both primary and secondary legislation. This is attributable to the fact that the environment and, in particular, each medium can be harmed in a variety of ways by quite different forms of human activity, each of which requires to be regulated in different ways. For example, as far as noise pollution is concerned, legislation may be required to regulate a broad range of noise-generating activities which differ quite dramatically in nature, from the carrying out of construction works, to the playing of amplified music, to the flight of aircraft. Whilst UK pollution control, in its modern form at least, really took off in the mid-nineteenth century with the passing of the Nuisance Removal Acts (which owe their existence to a desire to suppress cholera), the development of town and country planning was of more recent origin. Lack of space precludes tracing the development of town and country planning in the UK, but it suffices to say, for the purposes of this chapter, that the planning system was dramatically revolutionised in 1947, with the advent of Town and Country Planning Acts.2 1

2

Francis McManus’s research interests lie in the areas of environmental law and the law of delict, in relation to which he has published widely. He has a special interest in noise law. Separate Acts were passed for Scotland and England. Both are now repealed.

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Essentially, after these Acts came into force, one could not develop land without obtaining prior state authorisation, in the form of planning permission from the relevant planning authority. However, for many years before statutory law had been introduced to tackle pollution in its many forms, and long before the relatively recent planning control regime had been introduced, the common law of nuisance had been playing its part (albeit in a much more limited but nonetheless important role) in the battle against pollution. Indeed, the common law of nuisance, which had crystallised by end of the nineteenth century, grew up alongside both the aforementioned regulatory regimes. However, to what extent, if any, either of the above regimes shaped the development of the common law of nuisance had never been considered by the courts, rather surprisingly, until relatively recently. The first occasion in which the courts had to determine the inter-relationship between statutory environmental regulation and the common law of nuisance was the 2012 case of Barr v. Biffa Waste Ltd.3 The facts of the case were simple. The defendants operated a landfill site. The residents of houses, which were situated in the vicinity of the site, claimed that they were adversely affected by odour which emanated from the landfill. They brought an action in nuisance against the defendant. By way of a defence, the defendant claimed, first, that if in fact the smell from the site did rank as a nuisance, it could avail itself of the defence of statutory authority and, second, by virtue of the fact that the defendant complied both with the terms of its permit which had been issued by the Environment Agency pursuant to the Pollution Prevention and Control (England and Wales) Regulations 2000,4 and also with the conditions which were attached to the defendant’s licence under Part 2 of the Environmental Protection Act 1990, the use of the land from which the nuisance arose was reasonable: therefore, it did not rank as a nuisance in law. At first instance, Coulson J accepted this argument.5 In the view of His Lordship, it was necessary that the common law should ‘march in step’ with the relevant statutory regime. The common law required to be flexible in order to survive. In the last analysis, in the instant case, the duties which the defendant owed to the occupiers were four-square with the defendant’s obligations in terms of compliance with the relevant permit. The claimants appealed. The Court of Appeal upheld the appeal. The leading judgment was given by Carnwath LJ (as he then was). For His Lordship there was simply no principle to the effect that the common law should march in step with a statutory scheme which covered similar matter:6 a statutory scheme for regulating landfill sites could not cut down private rights. In other words, the regulatory background had no relevance to the development of the law of nuisance.

3 4 5

6

[2012] EWCA Civ. 312 Repealed. [2011] EWHC 1003. For a case analysis of this case see F. McManus, ‘Odour nuisance’, 148 SPEL (2011) 141–2 (2011) 148 SPEL 141. [2013] QB 455 at para. 92.

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However, one outstanding question which the Court of Appeal did not consider (it was not, of course, required to do so) was the extent, if any, to which relevant planning permission could affect private rights in terms of the law of nuisance. This issue fell to be resolved in the Supreme Court Case of Coventry v. Lawrence.7 The facts of the case were simple. In 1975 the fourth defendant obtained planning permission to construct a stadium, which was to be used for various motor sports which included speedway and stock car racing. In 1992 planning permission was granted to use agricultural land which was situated towards the rear of the stadium as a motocross track for one year. A track was duly constructed there. The planning permission was renewed on a number of occasions until permanent planning permission was granted in 2002. The planning permissions placed limits both on the frequency and on the times of the activities at the stadium, but did not place any conditions on the level of noise which was to be emitted when the activities were taking place. In 2006 the claimants bought a house which was situated close to the stadium and track. In response to complaints about the noise which was generated by motor sports at the stadium and track, the local authority served abatement notices, in terms of the Environmental Protection Act 1990,8 and also upon the person who had been granted a lease of the land on which the track was situated. After works were carried out to reduce the noise, the planning authority took no further proceedings in private nuisance. At first instance, the judge held inter alia that the planning permissions for the uses of the stadium and the track did not change the character of the area in terms of the law of nuisance. However, on appeal, the Court of Appeal held that the implementation of planning permission had changed the character of the land for the purposes of the law of nuisance in such a way that the noise from both the stadium and the track was to be regarded as simply an established part of the character of the locality. The claim in nuisance, therefore, failed. The claimants successfully appealed to the Supreme Court. The court held that the noise from the defendant’s activities had not caused a nuisance for a sufficiently long period as to establish a right by prescription. Furthermore, the defendants could not rely on the defence that the claimants had come to the nuisance. As far as these grounds for upholding the appeal are concerned, Coventry does not take the law further forward. However, the approach of the court to the inter-relationship between planning permission and nuisance is of interest. For Lord Neuberger, the grant of planning permission would, normally, be of no assistance to the defendant in a nuisance action.9 However, His Lordship stated that there could be occasions where the grant of planning permission

7

8 9

[2014] 2 WLR 433. For an analysis of this case see F. McManus, ‘Noise nuisance’, 163 SPEL (2014), 64–7. Environmental Protection Act 1990, s79(1)(g). [2014] 2 WLR 433 at 94.

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could be of some relevance in a nuisance action.10 For example, the fact that the noisy activity was acceptable after 8.30 a.m. and the noise was limited to a certain decibel level in a particular locality may be of real value, at least as a starting point, in a case where the claimant is contending that the activity gives rise to a nuisance if such activity starts before 9.30 am. For Lord Carnwath, while normally planning permission had no relevance to a nuisance action, in relation to large-scale developments, a particular planning permission may be the result of a considered policy decision by the competent authority, which leads to a fundamental change in the pattern of uses of the relevant land and, as such, could not sensibly be ignored by the court when it was assessing the character of the area against which the acceptability of the defendant’s activity fell to be judged.11 Apart from what His Lordship described as ‘strategic cases’, Lord Carnwath stated that planning permission might also be of some practical utility in a different way. That is to say, where evidence showed that a set of conditions had been carefully designed to represent the authority’s (that is, the planning authority) view of a fair balance (that is, of the relevant competing uses of land) there was much to be said for the parties and their experts adopting such conditions as a starting point for their own consideration.12 Evidence of failure to comply with such conditions, while not determinative, may reinforce the case for a finding of nuisance under the reasonableness test. Lawrence is the first nuisance case to be heard in the Supreme Court. The decision certainly means that planning permission should not be accorded the importance it formerly possessed in terms of the law of nuisance: until it was issued by the Supreme Court there was authority to the effect that a so-called strategic planning decision could notionally change the character of the relevant land.13 However, to what extent planning permission is relevant in a nuisance action unfortunately remains uncertain. As far as the law of Scotland is concerned, the Scottish courts, perhaps surprisingly (given the fact that Scottish town and country planning law, while possessing some differences, is similar to that for England and Wales), have never been required to consider the relevance of planning permission to a private nuisance action. However, it is suggested that the Supreme Court’s decision in Lawrence does not represent the law of Scotland. The author bases this view on the grounds, albeit not particularly firm ones, that one can discern a tendency amongst the Scottish judges in deciding delict cases to set less store by the relevant statutory background to the facts of the case than judges south of the border. The recent Inner House decision of MacDonald v. Aberdeenshire Council14 (which concerned a negligence action against a

10

Ibid. at 96. Ibid. at 223. 12 Ibid. at 226. 13 For example, Wheeler v. Saunders [1996] Ch. 19 and Watson v. Croft Promosport Ltd [2009] 3. All ER 249. 14 [2013] CSIH 83. 11

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roads authority) illustrates this point. However, to what extent, if any, such a judicial tendency finds expression in the development of the law of nuisance is uncertain. In the wake of the Lawrence decision, the fundamental (and obvious) question which falls to be answered is whether the decision has wider implications as far as environmental law is concerned. Is the decision simply confined to the effect of planning permission on noise pollution specifically, or does it extend to pollution (smoke, fumes, etc.) in general? In the author’s view, Parliamentary intervention is required to clarify the matter. Public law and private law are uneasy bedfellows, to be sure. A provision in the respective Town and Country Planning Acts, north and south of the border, to the effect that planning permission has no effect on private law rights is required.

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MULTI-STATE ENDANGERED SPECIES ACT LISTINGS: THE IMPACT TO ENERGY AND NEW CONSERVATION APPROACHES IN THE UNITED STATES Temple L. Stoellinger1

In the United States two species of ground-dwelling prairie grouse, the greater sage grouse and the lesser prairie chicken, have had a big impact on how the energy industry, policy-makers and other affected stakeholders are approaching threatened and endangered species conservation policy. Those approaches have resulted in the energy industries’ acceptance of state-level restrictions on energy developments intended to protect sensitive species in order to preclude the application of more stringent federal-level endangered species restrictions applied under the United States Endangered Species Act (ESA). Both the greater sage grouse and the lesser prairie chicken occupy habitat that encompasses multiple states. The greater sage grouse currently occupies habitat in eleven Western states,2 while the lesser prairie chicken occupies

1

2

Temple Stoellinger joined the University of Wyoming in 2013. She has a dual appointment with the College of Law where she is the Co-director of the Center for Law and Energy Resources and an Adjunct Assistant Professor at the Haub School of Environment and Natural Resources. Temple is a Faculty Supervisor for the University of Wyoming’s Energy, Environment and Natural Resources Law Clinic and teaches a variety of Energy and Natural Resources courses. Before joining the University of Wyoming, she worked in the Projects and Technology Legal Department for Shell, International B.V. at their world headquarters in the Netherlands. From 2004 to 2010 she served as a natural resource analyst and advisor to then Wyoming Governor Dave Freudenthal where she had the opportunity to work on a wide variety of energy and natural resource issues of state-wide, regional and national significance. Department of the Interior, Fish and Wildlife Service, ‘Endangered and threatened wildlife and plants; 12 month findings for petitions to list the greater sage-grouse (Centrocercus urophasianus) as threatened or endangered’, Federal Register 75(55) (23 March 2010), available at www.fws. gov/nevada/nv_species/documents/sage_grouse/032310_gsg_fed_reg.pdf (hereafter ‘Greater sage grouse candidate species decision’).

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habitat in five southern Great Plains states.3 With such large habitat ranges, a significant overlap with multiple land uses including energy development is inevitable. As a result of the land use overlap, and the resulting habitat destruction or modification from those land uses, both populations of species have declined.4 Due to their population declines, both species were petitioned for listing as threatened or endangered under the ESA.5 States containing occupied habitat of either species, and the energy producers operating within those states, quickly realised that a listing of either species under the ESA would have significant negative effects on the ability to continue to develop energy. Those negative effects would be the result of the application of a strict statutory prohibition against ‘taking’ or harming species listed as either threatened or endangered under the ESA, including harm that results as a consequence of habitat modification and or destruction.6 An additional negative effect would result from potentially lengthy delays caused by the federal government having to determine an energy project’s potential impact on a listed species in compliance with Section 7 of the ESA for all energy projects requiring a federal permit.7 Because of the large, multi-state range of both species, the effects of the ESA’s statutory requirements on either species would result in significant negative economic consequences to both energy producers and the states that rely upon energy production revenue. Facing these consequences, policy-makers and energy industry leaders in both cases came together with other interested stakeholders to craft unique solutions that allow for energy development to continue while at the same time conserving the imperilled species. GREATER SAGE GROUSE The greater sage grouse depends upon large, interconnected expanses of sagebrush.8 Sagebrush is the most widespread vegetation in the intermountain lowlands in the Western United States, an ecosystem ‘considered one of the most imperilled ecosystems in North America’.9 Greater sage grouse currently reside in eleven Western states: Washington, Oregon, California, Nevada, Idaho, Montana, Wyoming, Colorado, Utah, South Dakota and North Dakota.10

3

Department of the Interior, Fish and Wildlife Service, ‘Endangered and threatened wildlife and plants; determination of threatened status for the lesser prairie chicken; final rule’, Federal Register 79(69) (10 April 2014), available at www.gpo.gov/fdsys/pkg/FR-2014-04-10/pdf/201407302.pdf (hereafter ‘Lesser prairie chicken threatened species decision’). 4 ‘Greater sage grouse candidate species decision’; ‘Lesser prairie chicken threatened species decision’. 5 ‘Greater sage grouse candidate species decision’; ‘Lesser prairie chicken threatened species decision’. 6 The Endangered Species Act, 16 USC 1538(a); See Babbit v. Sweet Home Chapter of Communities for Great Oregon, 515 US 687, 708 (1995) (holding that the FWS’s regulatory interpretation of harm which included significant habitat modifications or degradation that actually kills or injures wildlife). 7 16 USC 1536(a)(2) 8 ‘Greater sage grouse candidate species decision’. 9 Ibid. 10 Ibid.

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While population declines are hard to estimate, it is believed that greater sage grouse populations have declined 45–80 per cent since the 1800s11 and today occupy only 56 per cent of their historic range.12 The primary cause of their decline is the loss and fragmentation of sagebrush from multiple threats.13 Those threats included direct conversion, urbanisation, infrastructure such as roads and power lines, wildfire, invasive plants, grazing and energy development.14 Further impacting its decline, greater sage grouse have a high fidelity to seasonal habitats including breeding, nesting, brood rearing and wintering areas, and rarely adapt to new habitats once existing habitat is disturbed, thus limiting their adaptability.15 As a result of population declines and loss of habitat, the greater sage grouse was petitioned for listing under the ESA in 2002, 2003 and 2004 across the entirety of its range.16 Responding to those petitions in 2005, the United States Fish and Wildlife Service (FWS) determined that listing the greater sage grouse as threatened or endangered under the ESA was not warranted.17 That decision was appealed to a federal court and was found to be arbitrary and capricious, thus the listing decision was remanded back to the FWS.18 Upon its revised analysis, the FWS made a decision in 2010 that listing the greater sage grouse was warranted, but that listing was precluded by other higher priority species, therefore designating the greater sage grouse as a candidate species.19 Further complicating the situation, as a result of a settlement agreement between the FWS and environmental groups in 2011 concerning the agency’s backlog candidate species, the FWS was required to make a final decision whether or not to list the greater sage grouse as a threatened or endangered species under the ESA by September 2015 (a candidate decision is not possible as a result of the settlement): it decided not to list it.20

11

J. W. Connelly and C. E. Braun, ‘Long-term changes in sage grouse centrocerus urophasianus populations in Western North America’, Wildlife Biology 3 (1997), 229–34. 12 M. A. Schroeder, C. L. Aldridge, A. D. Apa, J. R. Bohne, C. E. Braun, S. D. Bunnell, J. W. Connelly, P.A. Deibert, S. C. Gardner, M. A. Hilliard, G. D. Kobriger, S. M. Mcadam, C. W. Mccarthy, J. J. McCarthy, D. L. Mitchell, E. V. Rickerson and S. J. Stiver, ‘Distribution of sage grouse in North America’, Condor 106 (2004), 363–67. 13 ‘Greater sage grouse candidate species decision’. 14 Ibid. 15 Ibid. 16 Ibid. 17 Ibid. 18 Ibid. 19 Ibid. 20 US Fish and Wildlife Service, ‘The greater sage-grouse ESA listing decision’ (FWS PowerPoint presentation on the greater sage grouse), available at www.fws.gov/greatersagegrouse/documents/GrSG%20Listing%20Decision%20022001FOR%20WEB.pdf. See also US Department of the Interior Press Release, Historic Conservation Campaign Protects Greater Sage-Grouse’, 22 September 2015, available at www.doi.gov/pressreleases/historic-conservation-campaignprotects-greater-sage-grouse

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A decision to list the greater sage grouse under the ESA, and the resulting application of the ESA’s strict statutory prohibitions, would have been most impactful to the energy industry operating in the species’ occupied range and to the state economies relying upon energy revenue. The state most impacted by a potential listing was Wyoming, home to 37 per cent of the total greater sage grouse population and second in the nation in energy production.21 Anticipating this negative impact, Wyoming had proactively led the way in conservation of the greater sage grouse, enacting its Greater Sage Grouse Core Area Protection Policy (Wyoming Core Area Strategy) by executive order in 2008 and amending it in 2011.22 Wyoming’s approach has been to include leaders in the energy industry and other affected stakeholders in the development of a statewide regulatory mechanism to conserve the species, while at the same time allowing for continued energy development, thus protecting its economy. Under the Wyoming Core Area Strategy, 82 per cent of the state’s greater sage grouse populations are included in designated ‘core areas’ where restrictive conservation measures are applied and surface disturbance is greatly limited, thus restricting energy development.23 Outside the core areas there are less stringent conservation measures, providing an incentive for development in less sensitive areas.24 The strategy appears to be successful; a recent analysis has concluded that ‘if implemented as intended and sustained over time, the policy’s measures could stem a dramatic sage grouse decline’.25 The strategy was also specifically mentioned in the FWS’s 2010 decision to designate the greater sage grouse as a candidate species.26 In its decision, the FWS cited the Wyoming Core Area Strategy as an adequate regulatory mechanism, suggesting that if similar strategies were put in place throughout the species’ range it could preclude a future ESA listing as threatened or endangered.27 Wyoming’s approach has served as a model to the other ten impacted Western states and many have developed or are in the process of developing similar approaches. Ultimately, these states hope their voluntary conservation efforts across the region will preclude a threatened or endangered ESA decision and their energy industries and economies will remain unimpaired.

21

Sage Grouse Initiative, ‘Predicting the outcome of wyoming’s sage grouse conservation’, Science to Solution Series, No. 3, Sage Grouse Initiative (2014), available at www.sagegrouseinitiative. com/wp-content/uploads/2013/07/Science-to-Solutions-Predicting-the-Outcome-of-WyomingsSage-Grouse-Conservation-Strategy.pdf (hereafter ‘Sage grouse initiative’). 22 Office of Wyoming Governor Matthew Mead, ‘Greater Sage Grouse Core Area Protection, Wyoming Executive Order 2011-5’ (2011), available at http://will.state.wy.us/sis/wydocs/execorders/ EO2011-05.pdf (hereafter ‘Wyoming Core Area Strategy’). 23 B. Rutledge, ‘Wyoming’s sage-grouse conservation strategy’, Audubon Rockies Newsletter (July 2014), available at http://energy.gov/sites/prod/files/2014/08/f18/g_rutledge_statement_qer_ cheyenne.pdf. 24 Ibid. 25 ‘Sage grouse initiative’. 26 ‘Greater sage grouse candidate species decision’. 27 Ibid.

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LESSER PRAIRIE CHICKEN The lesser prairie chicken currently occupies habitat in five states: Kansas, Colorado, New Mexico, Oklahoma and Texas.28 Facing threats from energy development, agriculture, invasive species and road construction, it occupies only 17 per cent of its historic range, and population estimates suggest an 84 per cent decline.29 The lesser prairie chicken was petitioned for listing under the ESA in 1995, and in 1997 the FWS designated it as a candidate species, requiring a yearly review of its status.30 In 2012, the FWS issued a proposed decision to list the lesser prairie chicken as a threatened species.31 The threat of a potential listing of the lesser prairie chicken under the ESA, and the prohibitions and delays that would result, sparked a five-state effort to develop a voluntary conservation programme designed to restore the bird across its range.22 That effort resulted in the development of the Range-wide Conservation Plan for the lesser prairie chicken that was finalised in September 2013.33 The energy industry and others can enrol in the Range-wide Conservation Plan by paying a fee and agreeing to follow a list of guidelines designed to reduce impact to the bird and to pay for impacts that cannot be avoided.34 The money raised will be used to provide financial incentives to landowners who voluntarily participate in the programme by managing their property for the benefit of the species.35 Once enrolled, participants are given protection from prosecution under the ESA for incidentally harming a lesser prairie chicken when engaging in activities specifically listed under the Range-wide Conservation Plan.36 Unfortunately, the Range-wide Conservation Plan was developed too late and in March 2014 the FWS made the decision to list the lesser prairie chicken as a threatened species under the ESA.37 However, the Range-wide Conservation Plan and the effort that went into it were not wasted. When issuing its decision, the FWS simultaneously issued a final special rule for the lesser prairie chicken under Section 4(d) of the ESA.38 That special rule, the Lesser Prairie Chicken 4(d) Rule, allowed energy developers and others enrolled in the Range-wide Conservation Plan to incidentally take or harm the lesser prairie chicken, an action normally prohibited under the ESA.39 28

‘Lesser prairie chicken threatened species decision’. P. Taylor, ‘Drilling groups launch legal assault on interior’s prairie chicken listing’, E&E News PM (12 June 2014), available at www.eenews.net/eenewspm/stories/1060001233 30 ‘Lesser prairie chicken threatened species decision’. 31 ‘Lesser prairie chicken threatened species decision’. 32 S. Streater, ‘Industry embraces voluntary measures to help lesser prairie chicken’, E&E News PM (3 June 2014), available at www.eenews.net/eenewspm/stories/1060000638 33 W. Van Pelt and the Lesser Prairie Chicken Interstate Working Group Members, ‘The Lesser Prairie-Chicken Range-wide Conservation Plan’ (October 2013), available at www.wafwa.org/ documents/2013LPCRWPfinalfor4drule12092013.pdf 34 Ibid. 35 Ibid. 36 Ibid. 37 Ibid. 38 Ibid. 39 Ibid. 29

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Many have heralded the lesser prairie chicken approach a success despite the species’ ultimate listing under the ESA because of the 4(d) Rule. Recently released numbers suggest that despite the listing, a total of 160 energy company have enrolled 9 million acres in the Range-wide Conservation Plan, and have committed more than $43 million for habitat conservation.40 However, despite this success, a number of lawsuits have been filed against the FWS over its listing decision and the 4(d) Rule. A number of energy industry associations have filed lawsuits arguing that the FWS’s decision to list the species as threatened under the ESA ignored the Range-wide Conservation Plan and other conservation plans put in place to protect the species.41 On the other side, environmental groups filed a lawsuit arguing that the lesser prairie chicken should have been listed as endangered rather than threatened and challenged the FWS’s decision to allow exceptions to ESA prohibitions under its 4(d) Rule.42 CONCLUSION Without knowing how the pending lesser prairie chicken litigation will be resolved or if the species will ultimately recover as a result of the conservation measures put in place under the Range-wide Conservation Plan, it is too soon to call the lesser prairie chicken effort an ultimate success. However, the relaxed ESA standards contained within the Lesser Prairie Chicken 4(d) Rule that allowed for continued energy development while at the same time providing protection for the species, does signal to both states and the energy industry that it pays to work together to develop multi-state species conservation plans. Conversely, Wyoming’s greater sage grouse approach suggests that proactive efforts that allow for energy development while at the same time protecting an imperilled species’ core habitat are considered an adequate regulatory mechanism by the FWS and can stem a species’ decline, thus potentially precluding an ESA listing. Both processes are works in progress, but they do demonstrate changes in thinking by both the energy industry and state policy-makers to develop conservation plans that may initially impact energy development opportunities, but ultimately preserve long-term development potential by precluding or limiting the impact of an ESA listing.

40

Streater, ‘Industry embraces voluntary measures’. Taylor, ‘Drilling groups launch legal assault’. 42 Ibid. 41

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DELIVERING ENERGY TO THE DRYLANDS: OBLIGATIONS UNDER THE UN CONVENTION TO COMBAT DESERTIFICATION (UNCCD) TO PROVIDE ENERGY, WATER AND MORE Roy Andrew Partain1

While energy policies are often placed in contraposition to other critical policy areas, such as water or humanitarian policies, this need not be so. This chapter explores international obligations to combat desertification and the effects of long-term droughts and examines a pathway that coordinates energy policies and laws with environmental and human welfare agendas to deliver energy, water and more to combat desertification in the dryland areas. THE DRYLANDS: A LACK OF ENERGY, WATER AND SOLUTIONS There are areas of the world that are parched and dry; their lands do not yield to crops and their people often go hungry. Nearby, in offshore waters, the people might have access to abundant supplies of fresh water, yet those waters would go unproduced. Even with abundant fresh water supplies, they

1

Roy Andrew Partain, PhD (Law), JD, MSc (Econ), MSc (Econ), is a Reader of Energy Law at the School of Law within the University of Aberdeen. His energy law research applies a law and economics focus on unconventional or innovative sources of energy. Recent research has included studies on efficient mechanism design for the potential risks of offshore methane hydrate developments, on providing a law and economics foundation to liabilities from the operation of carbon capture and storage (CCS) facilities and on the potential liability regimes for novel forms of nuclear fusion energy devices.

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might still be unable to develop those fresh water resources because they lack the financial means to explore, develop and produce that water. And even if they had financing and water supplies, they would still lack fuel to operate the farms that would grow the food. Often, the inhabitants of these drylands suffer from climate change problems more than other locations due to the marginal existence within which they survive. This raises a truly fundamental problem: people die because they have no water, no energy, no fuel and no money. It was for these reasons that the UN Convention to Combat Desertification (UNCCD) was developed.2 OBLIGATIONS UNDER THE UNCCD TO ACT The UNCCD recognises that the threats posed by desertification3 could place a significant portion of the world’s population at great risk4 of poverty and famine.5 The objective of the UNCCD is ‘to combat desertification and [to] mitigate the effects of droughts’6 via the development of long-term strategies.7 While the UNCCD calls for particular urgency with regard to the harsh conditions of drylands in Africa,8 it was enacted with annexes to address drylands in Asia,9 Latin America and the Caribbean,10 and the northern Mediterranean.11 The UNCCD calls for the ‘sustainable management of land and water resources, leading to improved living conditions’.12 There are obligations to harness the potential of international trade and marketing arrangements to facilitate this programme.13 Developed countries have specific obligations to provide financial resources and to mobilise funding from the private sector.14 The programme is to be supported by academic institutions, by the scientific community and by non-governmental organisations of both developed countries and affected developing countries.15 Science, technology and engineering are to be brought to bear on this campaign; ‘technical and scientific cooperation’ is obligatory.16 The technological

2

United Nations Convention to Combat Desertification in Countries Experiencing Serious Drought and/or Desertification, Particularly in Africa, 1954 UNTS 3; 33 ILM 1328 (1994) (hereafter ‘UNCCD’). 3 UNCCD Part I, Art. 1 (a): ‘“Desertification” means land degradation in arid, semi-arid, and dry sub-humid areas resulting from various factors, including climactic variations and human activities.’ 4 UNCCD Preamble. 5 UNCCD Decision 3/COP.8, ‘10 year strategic plan and framework to enhance the implementation of the convention (2008–2018)’, Annex, at I,1 and Annex, at III, 9 (Strategic Objective 1). 6 UNCCD Part I, Art. 2, Sec. 1. 7 UNCCD Part III, Art. 10, Sec. 2(a). 8 UNCCD Part I, Art. 2, Sec. 1. and Annex I. 9 UNCCD Annex II. 10 UNCCD Annex III. 11 UNCCD Annex IV. 12 UNCCD Part I, Art. 2, Sec. 2. 13 UNCCD Part II, Art. 4, Sec. 2(b). 14 UNCCD Part II, Art. 6, Sec. (b) and (d). 15 UNCCD Part III, Art. 9, Sec. 1 and 3. 16 UNCCD Part III, Art. 17, Sec. 1.

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focus should be drawn to identify and implement ‘solutions that improve the living standards of people in affected areas’.17 Critically, those technologies should ‘enhance the availability of water resources in affected areas’.18 To the extent that such water-providing, standard-of-living-enhancing technologies exist, there is a requirement of the parties to ‘facilitate the financing of the transfer, acquisition, adaption, and development of environmentally sound, economically viable and socially acceptable technologies’.19 Those technology transfer plans should facilitate access to the technologies,20 facilitate their technological cooperation via financial assistance or other means21 and extend such assistance where relevant by joint ventures.22 The parties have a duty to ‘make every effort to ensure that adequate financial resources are available’,23 to mobilise grants and concessional loans,24 to promote ‘adequate, timely and predictable’ financial tools 25 and to ensure that such is coordinated with technological cooperation to provide the necessary knowledge and know-how;26 private sector entities are to be included in this scope.27 If there are technologies and financial resources that could be utilised to bring relief, especially water resources, to dryland areas, the obligation is binding on the parties to find a way to provide that relief. ENERGY, WATER AND MORE FROM OFFSHORE METHANE HYDRATES Just offshore of many dryland nations lie extensive deposits of methane hydrates.28 Methane hydrates are a unique natural resource that could provide abundant volumes of both methane and fresh water. For every cubic metre of extracted methane hydrate resource, 800 litres of fresh water and 170 m3 of

17

UNCCD Part III, Art. 17, Sec. 1(b). UNCCD Part III, Art. 17, Sec. 1(g). 19 UNCCD Part III, Art. 18, Sec. 1. 20 UNCCD Part III, Art. 18, Sec. 1(b). 21 UNCCD Part III, Art. 18, Sec. 1(c). 22 UNCCD Part III, Art. 18, Sec. 1(d). 23 UNCCD Part III, Art. 20, Sec. 1. 24 UNCCD Part III, Art. 20, Sec. 2(a). 25 UNCCD Part III, Art. 20, Sec. 2(b). 26 UNCCD Part III, Art. 20, Sec. 2(c). 27 UNCCD Part III, Art. 20, Sec. 2(d). 28 P. Englezos and J. Lee, ‘Gas hydrates: a cleaner source of energy and opportunity for innovative technologies’, Korean Journal of Chemical Engineering 22(5) (2005), 671–81, at 674; J. F. Gabitto and C. Tsouris, ‘Physical properties of gas hydrates: a review’, Journal of Thermodynamics (2010), 1–10, at 2. Maps of the global distribution for offshore methane hydrates can be found at J. B. Klauda and S. I. Sandler, ‘Global distribution of methane hydrate in ocean sediment’, Energy & Fuels 19(2) (2005), 459–70, at 469; they present different maps based on varying assumptions, see ibid., Figure 7. Methane hydrates are also known as gas hydrates, methane clathrates and natural gas hydrates. 18

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natural gas can be obtained.29 The US has estimated the methane content of the global reserves of natural gas at 24,000 Tcm,30 which can be seen in comparison to the BP estimate of global conventional natural gas reserves of nearly 200 Tcm. Estimates vary from several thousand to several million Tcm, but certainly the amount of natural gas lying within offshore methane hydrates is sufficiently large to merit attention. Given the above ratio of methane volumes to litres of water, the US estimate would suggest approximately 140 trillion metric tons of fresh water.31 There are therefore large accumulations of fresh water and natural gas within the Exclusive Economic Zones (EEZ) of many dryland nations. The technology to extract offshore methane hydrate has recently become operational; Japanese researchers were the first to achieve continuous-flow production from offshore methane hydrates in 2013.32 A variety of research programmes exist to improve on the safety and cost factors of that technology.33 Thus, the production of offshore methane hydrates is already feasible and will benefit from near-term reductions in costs and developments in tech duced natural gas offshore to provide electrica l power supplies and how the greenhouse gas emissions can be resequestrated within the hydrate reservoir system;34 such a system might enable the production of carbon-neutral electrical power for dryland nations. Additionally, in a hydrogen fuel era, the fresh water can be converted to steam to use in generating hydrogen from the natural gas co-produced with the water.35 Thus, fresh water can be produced from offshore methane hydrates with co-production of natural gas; electrical power, hydrogen fuel, and carbon capture and storage can be implemented alongside the production activities.

29

Englezos and Lee, ‘Gas hydrates’, at 673; A. Demirbas, ‘Methane hydrates as potential energy resource: Part 1 – importance, resource and recovery facilities’, Energy Conversion Management 51(7) (2010), 1547–61, at 1548. 30 Enacted at 30 USC, Sec. 2001(2)-(3). The statute provides an estimate of the potential US reserves at 200,000 trillion cubic feet (Tcf) and then states that the US reserves make up approximately a quarter of the global reserves, yielding a global estimate of 800,000 Tcf. Converting from imperial to metric units, 800,000 Tcf is equivalent to 24,000 Tcm. 31 It is only reasonable to take this estimate as a first approximation; however the point is that significant volumes of fresh water are likely available. 32 R. A. Partain, ‘Avoiding Epimetheus: planning ahead for the commercial development of offshore methane hydrates’, Sustainable Development Law and Policy 15(1) (2015), 16–25, 56–8, at 18. See footnote 49 at 56. 33 J. F. Gabitto and M. Barrufet, ‘Gas hydrates research programs: an international review’, Technical Report, Prairie View A&M University (2009). 34 S. Maruyama, K. Deguchi, M. Chisaki, J. Okajima, A. Komiya and R. Shirakashi, ‘Proposal for a low CO2 emission power generation system utilizing oceanic methane hydrate’, Energy 47(1) (2012) 340–7, at 342. 35 W. Rice, ‘Hydrogen production from methane hydrate with sequestering of carbon dioxide’, International Journal of Hydrogen Energy 31(14) (2006) 1955–63, 1957. See also R. Kikuchi, ‘Analysis of availability and accessibility of hydrogen production: an approach to a sustainable energy system using methane hydrate resources’, Environment, Development & Sustainability 6(4) (2005), 453–71, at 454.

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OBLIGATIONS TO ACT ON ENERGY AND WATER Natural gas, hydrogen, electrical power and fresh water are all products with ready placement on global markets. Depending on the particular hydrate development plan, a dryland nation could transform its offshore methane hydrates into commercial exports that could generate revenues to support both the production and co-production activities in support of broader domestic programmes to combat desertification and the effects of long-term droughts as part of their ‘national action plans’.36 All of the parties have obligations under UNCCD to enable the fulfilment of national, regional and sub-regional action plans.37 To the extent that the dryland nation is also a developing economy member of the General Agreement on Tariffs and Trade (GATT),38 other GATT members would have affirmative duties to (1) support the export marketing of those primary products39 and (2) to assist in the advancement of the dryland nation’s industrial capacity to progress beyond primary product reliance.40 Parties to UNCCD and the UN’s Development Programme could engage with private operators to provide technological and operational know-how via joint ventures;41 the private operators could coordinate the revenues from production activities to cover their operational costs, provide revenues for the national and regional governmental budgets, and to oversee the trust fund for local communities.42 It would appear that a humanitarian and environmental problem exists which nations have already entered into an international convention to address, and that recent science and engineering advances have made additional water resources feasible for coastal drylands. While there needs to be additional legal research conducted,43 it would seem that offshore methane hydrates could be 36

UNCCD Part III, Arts 10, 11 and 14. Ibid. 38 General Agreement on Tariffs and Trade, 1867 UNTS 187; 33 ILM 1153 (1994) (hereafter GATT). 39 GATT Part IV, Art. XXXVI, Sec. 4.; Art. XXXVII., Sec. 1(b); and Art. XXXVIII, Sec. 2(a). For an in-depth review of these issues, see Roy Andrew Partain, ‘Gored by a cornucopia: the risk of green paradoxes from laws and policies that incentivize competitive energy innovations’, Louisiana State University, Journal of Energy Law and Resources 3(2) (2015), 433–81. 40 GATT Part IV, Art. XXXVI, Sec. 5. 41 UNCCD, Part III, Art. 20, Sec. 1 and Sec. 2(d). 42 Functional examples of such trust funds can be found with the Alaska Permanent Fund, Mongolia’s Human Development Fund, Bolivia’s Renta Dignidad and the Norwegian Statens pensjonsfond Utland. Concerns on oversight and transparency have resulted in novel non-governmental solutions, such as Norway’s Extractive Industries Transparency Initiative (EITI). 43 See Magdalena A. K. Muir, ‘Challenges and opportunities for marine deposits of methane hydrate in the circumpolar arctic polar region’, Retfærd 32(3) (2009), 61–71. See also Partain, ‘Avoiding Epimetheus’; Roy Andrew Partain, ‘The application of civil liability for the risks of offshore methane hydrates’, Fordham Environmental Law Review 26(2) (2015), 225–312; and Roy Andrew Partain, ‘A comparative legal approach for the risks of offshore methane hydrates: existing laws and conventions’, Pace Environmental Law Review 32(3) (2015), 101–233. See also the student note from Erin Jackson, ‘Fire and ice: regulating methane hydrate as a potential new energy source’, Journal of Environmental Law & Litigation 29(3) (2014), 611, 629–32 and Adegoke Olubayode Arowosebe, ‘Developing a legal framework for the exploration and exploitation of methane hydrates in the Northwest Territories and offshore Canada’, LLM thesis, University of Calgary (2012). 37

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sustainably produced,,44 especially given the immediate needs of those suffering from desertification and droughts. If the technological means do exist to alleviate dryland suffering, if marketable products could be co-produced alongside efforts to increase fresh water supplies and if financial mechanisms are readily available to sustain these efforts, then it would be imperative under the UNCCD to determine if national, regional and sub-regional action plans could in fact be created on the basis of these possibilities.

44

See note 43 above. While hazards might remain, the risks can be mitigated and managed, for example by taking operational precautions, by following best practices and by careful site selection to avoid riskier reservoir systems. Recommendations have been made for a combined approach of civil liability, public regulations and private regulations to provide the optimal portfolio of incentives and controls to attain efficient levels of social welfare from offshore methane hydrates.

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DELIVERING NEW ENERGY TECHNOLOGIES: THE MILITARY AS CONSUMER AND INNOVATOR Samuel R. Schubert1

What does it take to deliver energy policies that are both effective and sustainable, particularly in terms of developing a market for substitute fuels and technologies? This chapter suggests that past experience indicates the best approach is to focus such policies around a major governmental player capable of multi-decade-long planning and purchase commitments; and, pointing to the US case, the most relevant player is the military. Because technologies are fluid and resource endowments are not, policies that are most likely to have the broadest strategic impact are those that change the primary fuels being used by the industrial and transport base. Yet even when policy goals are set, funds are committed and scientists and businesses develop the relevant alternatives, substitute fuels struggle to become economically viable without dedicated long-term consumers. In the US, there is no larger, more dedicated long-term energy consumer than the military. 1

Dr Samuel R. Schubert is an Assistant Professor of International Relations at Webster University in Vienna, Austria and author of several energy-related works on USA, UK and EU energy policy, EU-Russian energy relations and the effects of energy-resource wealth on state stability. His most recent work includes (with Johannes Pollak and Maren Kreutler), Energy Policy of the European Union (Palgrave); ‘Lessons for European autonomy in space from past pursuits of energy autonomy’ in C. Al-Ekabi (ed.), European Autonomy in Space (Springer, 2015); and (with Elina Brutschin) ‘Two futures: EU-Russia relations in the context of Ukraine’, European Journal of Futures Research 2(1) (2014), 52–9. His research into energy-related national security matters dates back to 2006 when he published ‘Revisiting the oil curse’, Development 49(3) (2006), 64–70, which led to a 2007 study for the European Parliament, ‘Being rich in energy resources – a blessing or a curse’, that examined how aspects of a resource curse in many of the EU’s primary external suppliers affects the EU’s energy security. In addition to his scholarly research, Dr Schubert brings over a decade of policy experience through his work with the UN and think tanks. He is a graduate of George Washington University’s Political Science programme and earned his PhD at the University of Vienna writing on the relationship between national energy policies, international cooperation and conflict, and energy R&D.

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Energy policies produce long-term national security and foreign policy consequences. When successful, they produce spinoffs, changing the calculus of almost every other area of public policy by altering the technological foundation of a country’s industrial base. One need only take witness of the social, economic and environmental impact of the shifts from wind to steam and from coal to oil. In cooperation with its military and sometimes directly through it, the US has, since 1950, succeeded in developing independent access to space (via the Apollo Programme), building up a global naval power projection capability (through nuclear engineering) and developing a nuclear deterrent (initially through the Manhattan Project). Each success was the result of a cooperative research programme between the government, the military, universities and key industrialists, and they were massive in both scale and duration, with $21 billion ($2007) invested over five years in the Manhattan Project and 2.2 per cent of all federal outlays between 1960 and 1973 for the Apollo Programme.2 Together with the development of the US nuclear navy, these programmes substantially advanced the knowledge of energy physics and brought about huge industrial and economic gains.3 Each was driven by broad security concerns, had dedicated institutional customers embedded within the national security apparatus and was supported by a cohesive executive authority that spanned administrations and political party affiliations to ensure public support over many years. The US military is unique as an institutional buyer primarily because of the long-term nature of its strategic planning and budgeting. It is keenly aware of the vulnerability of international energy supplies: if it is unable to fuel its ships, planes and vehicles, it cannot project power. This creates a logical nexus of motivations to develop and deploy substitute technologies and fuels. It possesses the political prestige to win funding for research and development. Its Defense Advanced Research Agency (DARPA) has an annual R&D budget of almost $3 billion, and, since 2007, its sister institution, ARPA-E, has funded over 360 energy technology projects, investing in excess of $600 million.4 It has the institutional stability to plan and act over long temporal horizons and thus carries special weight as a consumer, that is, when it funds research, commercial producers know that success will lead to large scale, long-term supply contracts, enhancing the incentive to take risks and produce the volumes necessary to establish a market where it would otherwise not exist. No amount of subsidies or any existing civilian programme can offer anything close to that kind of investment security for the private sector.

2

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4

D. D. Stine, ‘The Manhattan Project, the Apollo Program, and federal energy technology R&D programs: a comparative analysis’, Congressional Research Service Report (2008). For a history of the US nuclear navy programme, see R. G. Hewlett and F. Duncan, Nuclear Navy, 1946–1962 (University of Chicago Press, 1974). See Advanced Research Projects Agency – Energy website at http://arpa-e.energy.gov/?q=arpa-esite-page/arpa-e-history

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As an energy consumer, the US military is huge. Throughout the 1990s, it was the ‘single largest consumer of petroleum’ in the country.5 Under the management of the Defense Logistics Agency (DLA), the US military purchases millions of barrels per month of military-grade jet fuel and manages fuel supply agreements all over the world.6 It maintains an international network of suppliers from which it buys and resells to operational command centres; and it stockpiles to account for disruptions. In 2013, it spent more than $17.4 billion on energy expenses around the world.7 Costs are a big part of the reasoning here.8 Because the market price of petroleum directly affects the cost of US power projection, it is understandable that it is actively investing in alternative energy including, for example, batteries and flexible solar technologies to reduce liquid fuel dependency in forward land deployments, and biofuel programmes to find alternative mixes for aviation fuels.9 Although just a drop in the bucket compared to its overall energy needs, the US military’s pursuit to free itself from fossil fuels is something that commercial alternative energy suppliers can count on for the long haul. The military has not acted alone. Major policy decisions and public energy initiatives have helped drive the process so far.10 While renewable energy targets of the Energy Policy Act of 2005 provided the legal basis for demonstrating alternative fuel mix technologies, civilian and Department of Defense agencies and task forces have been calling for more energy-efficient weapons systems, alternative fuels use and reduced combat vehicle fuel intensity since as early as 2001.11 By 2009, the military had a Director of Operational Energy Plans and Programs with the authority to ‘establish and implement an energy strategy, [and] coordinate all the branches’ energy plans and research-and-development investments’.12 The US military now leads US government agencies on renewable energy, setting bold 5

E. C. Aldridge and D. M. Etter, ‘Leap ahead technologies and transformation initiatives within the Defense Science and Technology Program: hearing before the subcommittee on emerging threats and capabilities of the committee on armed services’, United States Senate, 117th Congress, 1st session, 5 June 2001 (US Government Printing Office, 2001), 10. 6 A. Andrews, Department of Defense Fuel Spending, Supply, Acquisition, and Policy (Congressional Research Service, 2009). 7 See Defense Logistics Agency Energy, Fiscal Year 2013 Fact Book, p. 24, available at www. energy.dla.mil/Documents/Fiscal%202013%20Fact%20Book%20low%20resolution.pdf 8 According to Blackwell, a $10 increase in the price of a barrel of oil translates into an operating cost increase of close to $1.3 billion (in $2007). See K. E. Blackwell, Department of Defense and Energy Independence: Optimism Meets Reality (Air University, 2007), p. 2. 9 DESC, DESC Fact Book: Providing Energy Solutions Worldwide (Defense Logistics Agency, 2010). 10 M. Schwartz, K. Blakeley and R. O’Rourke, Department of Defense Energy Initiatives: Background and Issues for Congress (Congressional Research Service, 2012). 11 United States Department of Defense, More Capable Warfighting Through Reduced Fuel Burden: The Defense Science Board Task Force on Improving Fuel Efficiency of Weapons and Platforms (Office of the Under-Secretary of Defense For Acquisition, Technology, and Logistics, 2001); United States Department of Defense, Energy Security Task Force, Highlights of DoD’s Energy Security Efforts (US Department of Defense, 2007). 12 PEW, Reenergizing How the Armed Forces Are Stepping Forward to Combat Climate Change and Improve the U.S. Energy Posture of America’s Defense (The Pew Charitable Trusts, 2010), p. 10.

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targets ‘to cost-competitively acquire 50% of [the Air Force’s] domestic aviation fuel via an alternative fuel blend’ and to deploy ‘a “green” carrier strike group using biofuel and nuclear power’.13 It is literally churning out change by inventing, funding, testing and deploying new technologies and the fuels to run them. The US Navy already commissioned its first all-electric-drive amphibious assault ship, the USS Makin Island and has tested biofuels in its F/A-18 engines. As President Obama succinctly stated in 2010, ‘For decades, we’ve talked about the risks to our security created by dependence on foreign oil’, but ‘here at home . . . our own military’s determined that we can no longer afford not to’.14 All of the evidence about the US military leading a green revolution by playing a key role as the long-term stable institutional investor for alternative energy raises the question: is there an equivalent institution in Europe? The history behind Europe’s pursuit of energy autonomy demonstrates that subsidies, efficiency standards and even carbon taxes are insufficient to get the job done alone. That is a real problem for Europe, which has invested so much in liberalising its national energy markets. A massive programme of subsidies could supply the demand for alternative fuels, replicating the effect of the military in the US, but one has to ask whether the European Union can sustain over the long haul multi-billion dollar investments in multiple, even contradictory alternative fuel supplies. One positive example is the EU’s material support in recent years for fusion research. Yet it also abruptly turned away from first- and second-generation biofuels in hopes that a third will satisfy the divergent interests present among the member states. Nuclear power has come and gone (and come again) in some of the member states. Meanwhile, competing interests have weakened solidarity on EU dependence on Russian gas and stalled development, no matter how small, on hydraulic fracturing. On the commercial side, Europe’s national energy champions are not in the position to act because doing so would challenge EU competition laws. That leaves big companies like Airbus, Volkswagen and Daimler to unilaterally switch the fuel capabilities of their vehicles, and there is an aviation-industry-wide initiative to build a marketplace for at least 2 million tonnes of sustainable aviation fuel production and consumption by 2020. What is most likely to have a positive impact, however, is a political rather than commercial step, namely the establishment of an Energy Union, which legally coordinates and consolidates energy research development budgets among the EU’s twenty-eight member states. Such an institution may be able to invest €4–5 billion annually in energy research and development creating a similar impact to that of the military in the US. It could even cooperate directly with Washington to share the burden. But alas, while governments can decrease development costs, they cannot impose discovery. The two most profound technological advancements of the industrial age, electricity and the internal combustion engine, were developed with little to no government support. 13

United States Department of Defense, Quadrennial Defense Review Report, February 2010 (US Department of Defense, 2010), pp. 87–8. 14 B. Obama, ‘Remarks at Andrews Air Force Base, Maryland’ (31 March 2010), online in G. Peters and J. T. Woolley, ‘The American Presidency Project’, available at www.presidency.ucsb.edu/ws/ ?pid=87685

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DELIVERING ENERGY POLICY FOR PLANET OCEAN BY INVESTING IN OCEAN THERMAL ENERGY CONVERSION INFRASTRUCTURE Anastasia Telesetsky1

INTRODUCTION Oceans cover approximately 70 per cent of the globe, and so perhaps we should regard ourselves as residents of Planet Ocean rather than Planet Earth. Yet, in the search for sustainable energy strategies, we frequently overlook the potential for energy generation at sea in favour of developing our terrestrial resources. Given that approximately half of the world’s population lives within 60 km of a coast and three-quarters of the world’s largest cities are located along the coast, there is great untapped potential for developing a network of renewable marine energy production centres to supply energy to coastal cities and communities.2 DELIVERING CLEAN ENERGY TO THE COASTS The current marine energy focus in the United States has been largely centred on offshore oil and gas development with an increasing willingness to permit offshore drilling on the United States Outer Continental Shelf.3 Continued expansion of fossil fuel production has the disadvantages of perpetuating dependency 1

2

3

Anastasia Telesetsky is an Associate Professor of Law at the University of Idaho College of Law where she teaches in the Natural Resources and Environmental Law Programme. Her research focuses on sustainability and marine resources. United Nations Environmental Programme, Cities and Coastal Areas, available at www.unep. org/urban_environment/issues/coastal_zones.asp A. Vann, ‘Offshore oil and gas development: legal framework’, Congressional Research Service Report (26 September 2014).

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on carbon-rich energy sources and exposing the marine environment to continued high levels of risk that can lead to disasters such as the 2010 Deepwater Horizon Oil Spill. Building adequate transmission systems for the delivery of renewable energy to major populations areas along both the west and east coast of the United States should quicken the transition of certain major metropolitan areas to renewably sourced energy and assist the United States in achieving its carbon reduction emissions targets. Achieving a viable network of renewable energy sources will depend on the ability of energy companies to work with multiple stakeholders, including commercial fishermen and the cargo industry, and to take into consideration environmental impacts when siting renewable ocean energy infrastructure. While offshore wind and hydrokinetic energy technology seem to be technologies currently favoured by the US government, part of the renewable marine energy mix should also include ocean thermal energy conversion which holds great potential for California, Hawaii and Florida. In the 1980s, the US government recognised the potential of ocean thermal energy but has never provided the sorts of financial incentives to expand the renewable marine energy infrastructure that has been provided to the fossil fuel sector.4 SUBSIDISING OCEAN THERMAL ENERGY CONVERSION RESEARCH AND INFRASTRUCTURE Subsidies are essential for ocean thermal energy conversion to become a viable energy source for regions where it is possible to use a sufficient thermal gradient to generate energy. While most of the existing subsidies available within the renewable energy industries go to wind energy development, including offshore wind, ocean thermal energy conversion has all of the clean energy benefits of wind with the added benefits of producing fresh water, mariculture, liquid fuels (such as hydrogen and ammonia) and sea water air-conditioning.5 Targeted subsidies on a par with those received by the fossil fuel industry would make a significant difference to building ocean thermal energy conversion facilities, building ‘plantships’, creating sufficient cable networks to deliver energy to coastal cities and assisting ‘plantships’ to optimally locate their conversion activities.6 4

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See, for example, M. Clayton, ‘Budget hawks: Does US need to give gas and oil companies $41 billion a year?’ The Christian Science Monitor (9 March 2011) (citing $41 billion in oil and gas subsidies in comparison to $6 billion in renewable energy subsidies and indicating that the oil and gas industry receive over half of any financial benefits distributed to the energy industry). National Oceanic and Atmospheric Administration, ‘Ocean thermal energy conversion: assessing potential physical, chemical and biological impacts and risks’ (22–4 June 2010), available at http://coastalmanagement.noaa.gov/otec/docs/otecjun10wkshp.pdf A ‘plantship’ is ‘any vessel which is designed to use temperature differences in ocean water while floating unmoored or moving through such water, in order to produce electricity or another form of energy capable of being used directly to perform work, and includes any equipment installed on such a vessel to use such electricity or other form of energy to produce, process, refine or manufacture a product, and any equipment used to transfer such product to other vessels for transportation to users, and all other associated equipment and appurtenances of such vessel’, 42 US Code 9102(12).

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The US was an early supporter of ocean thermal energy conversion. In the early 1980s, within the area that is now designated as the US exclusive economic zone, the US announced its goal to develop ocean thermal energy conversion ‘plantships’ and link this energy by cable or pipeline to the United States.7 The US anticipated creating ‘a legal regime which [would] permit and encourage the development of ocean thermal energy conversion as a commercial energy technology’.8 Even though Congress ultimately designated a extensive system for ocean thermal conversion that takes into consideration the interests of navigation, the environment and adjacent coastal states,9 the potential for mainstreaming ocean thermal energy conversion has yet to be realised. The barriers to innovation have been a lack of adequate return for developing commercial ‘plantships’ and the absence of a well-developed energy ‘grid’ of electric transmission cables to transport ocean energy from thermal gradient sites to population centres. While short-term capital costs are high, the long-term benefits of delivering marine energy justify US financial investment into supporting the already existing law and governance framework provided for ocean thermal energy conversion in the 1980s.10 Even though the appropriations to support ocean thermal energy conversion stopped in 1987,11 the technology still holds great promise particularly for areas such as southern California, where both energy and fresh water are scarce commodities. As of 2010, ocean thermal energy conversion technology was still evolving and the output from facilities has been relatively low in comparison to fossil fuel sources.12 Most of the focus on developing plants within the United States has been on Hawaii. The United States should revisit the potential for ocean thermal energy conversion to meet the demands of population centres. Specifically, it should map thermal gradient plumes that are already close to electricity distribution lines as well as analyse all ocean temperature data to identify areas for optimal operation where new transmission lines could be feasibly installed. Based on this data, the US could provide incentives for companies to invest in conversion plants or ‘plantships’ to supply major energy centres near thermal plumes which are close to population centres such as Honolulu, Miami or Los Angeles. It may also be feasible to redeploy portions of existing oil platforms that are slated for decommissioning as the foundations for future ocean thermal energy conversion power plants.

7

42 US Code 9101(a)(1) and (a)(2); Ibid., 9101 (a)(4) 9 42 US Code Chapter 99, Subchapter I Regulation of Ocean Thermal Energy Conversion Facilities and Plantships. 10 For an overview of the law and governance framework, see NOAA Office for Coastal Management, Ocean Thermal Energy Conversion, available at http://coast.noaa.gov/czm/thermalenergy/ ?redirect=301ocm (providing links to the Ocean Thermal Energy Conversion Act of 1980 and the Ocean Thermal Energy Conversion Research, Development and Demonstration Act). 11 42 U.S. Code 9166 12 National Oceanic and Atmospheric Administration, ‘Ocean thermal energy conversion’ (referring to the world record for ocean thermal energy production having been set in 1993–8 at 103 kW). 8

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Delivering good energy policy for the United States includes reviving closedcycle ideas that have been overlooked for decades in favour of ‘cheap’ fossil fuel. Ocean thermal energy conversion has immense potential to provide 24-hour energy production across the year with low environmental risk and without depending on global trading partners. The challenge will be whether the US is willing to finance the start-up expenses for a marine energy industry capable of innovating for renewable energy delivery on Planet Ocean.

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THE NECESSITY OF GOVERNMENT SUPPORT FOR THE SUCCESSFUL DEPLOYMENT OF CARBON CAPTURE AND STORAGE Matthew Rooney1

INTRODUCTION: A UNIQUE TECHNOLOGY The cost of solar photovoltaic panels has declined rapidly in the past decade.2 In parts of the world where conditions are suitable, solar PV is a competitive form of electricity generation without the need for government support, if system costs are not taken into account. Nuclear power plants are expensive to build and require investors to take on a large amount of risk, and therefore few are constructed today without some form of government support. However, it is possible that future innovations in nuclear fission technology could reduce both the upfront capital cost and the risk to investors (perhaps small modular reactors will provide the solution) and new nuclear power plants will be financed and built independently in the private sector and without direct subsidy. Power plants fuelled by coal or gas and equipped with carbon capture and storage (CCS) technology are not like this. They are a special case. The extra equipment cost necessary to capture carbon dioxide, compress it, transport it to a suitable underground storage site and contain it there indefinitely will mean that without some sort of environmental tax or government subsidy, power plants with CCS technology will always be more expensive than those without.

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2

Matthew Rooney is a Chartered Mechanical Engineer currently working towards a PhD in Energy Policy at the University of Cambridge. International Energy Agency, Technology Roadmap: Solar Photovoltaic Energy (OECD/IEA, 2014), p.14.

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There is also an associated reduction of plant efficiency with the capture of carbon dioxide, meaning that fuel costs will also be significantly higher. It has been estimated that adding CCS to future fossil fuel power plants will add between 1.5 and 3 eurocents/kWh to the cost of electricity produced.3 More recently a study commissioned by the UK government4 estimated that capital (overnight) costs for newly constructed coal plants would be increased by 76.5 per cent by the addition of post-combustion carbon capture. Reducing these additional costs to an acceptable level is one of the key challenges for the industry. One way to improve the profitability of CCS projects is through the sale of the captured carbon dioxide. The gas has many industrial applications, but enhanced oil recovery (EOR – the process of injecting heavy gases into an oil reservoir to boost production) is the largest. Coupling CCS with EOR can increase revenues for a given project, but it will not in itself be a saviour for the industry. The total demand for carbon dioxide for EOR in the United States is 60 million tonnes,5 whilst total American carbon dioxide emissions from electricity generation in 2012 were over 2,023 million tonnes.6 In other words, supply of carbon dioxide would outstrip demand many times over. So CCS is unique amongst low-carbon energy sources in that it can never compete without policy support, but why is it needed at all? The International Energy Agency estimates that the capital investment required for emissions reductions necessary to limit global temperature rises to 2°C would have to increase by 40 per cent if CCS was not included in the technology mix.7 CCS is even more important for the decarbonisation of heavy industries where it is ‘the only largescale mitigation option available to make deep reductions in the emissions from industrial sectors such as cement, iron and steel, chemicals and refining’.8 WHAT CAN GOVERNMENTS DO? Having established that CCS could be a key technology for reducing carbon emissions, and that government intervention is required in order for it to proliferate, it is worth examining what exactly governments can do. 3

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J. David and H. Herzog, ‘The cost of carbon capture’, Proceedings of 5th International Conference on Greenhouse Gas Control Technologies (GHGT-5), Cairns, Australia (2001), D. J. Williams, R. A. Durie, P. McMullan, C. A. J. Paulson and A. Y. Smith (eds), CSIRO (2001), 985–90, available at http://sequestration.mit.edu/pdf/David_and_Herzog.pdf Department of Energy & Climate Change, ‘Parsons Brinckerhoff electricity generation model: 2013 update of non-renewable technologies’ (2012), pp. 45, 47, available at www.gov.uk/government/ publications/parsons-brinkerhoff-electricity-generation-model-2013-update-of-non-renewabletechnologies International Energy Agency, Technology Roadmap: Carbon Capture and Storage (OECD/IEA, 2013), p.20. Environmental Protection Agency, Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2102 (Environmental Protection Agency, 2014), p. ES-5. International Energy Agency (2012), Energy Technology Perspectives 2012 Executive Summary, (OECD/IEA, 2012), p. 4. International Energy Agency, Technology Roadmap: Carbon Capture and Storage, p. 8.

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Transport and storage regulation Although the major cost of CCS is associated with the capture of carbon dioxide, rather than the transport and storage infrastructure,9 inefficient design of pipeline networks can add large and unnecessary costs. Put very simply, it is more cost-effective to build one large pipe than five small ones. Government intervention can help reduce costs here by ensuring pipeline infrastructure is designed in such a way as to enable easy expansion as CCS capacity increases. Until recently carbon dioxide was considered a waste product and the subsea disposal of waste products was prohibited in the European Union by the London Protocol until it was amended in 2006. Although no longer strictly illegal, companies must still go through a process of applying for licences to store carbon dioxide. It is the responsibility of legislative bodies around the world to put a framework in place that is not unduly onerous as to prevent or delay the expansion of CCS projects. A worry for the CCS community at present is that the two-thirds of countries required to ratify a 2009 update to the London Protocol to allow the transnational transport of carbon dioxide waste have yet to do so.10 Ensuring carbon capture can compete In order to make power plants with CCS competitive with other electricitygeneration technologies, various policy options are available: Carbon tax Economists tend to favour a carbon tax as the economically efficient way to reduce carbon dioxide emissions in the energy sector. A sufficiently high tax on greenhouse gas emissions should, in theory, mean that a competitive energy market will create the lowest-cost energy system given the technologies available at the time. The main barriers to the implementation of a sufficiently high carbon tax are twofold: (1) for the tax to work and be accepted it has to be international. Not many countries are likely to be willing to reduce their competiveness through artificially high energy prices unless their neighbours also agree to do so; and (2) any assessment of the politics of climate change mitigation policies so far suggests that a global tax on carbon is not likely. This uncertainty increases the risk to investors in low-carbon technologies and makes it more likely that they will cancel or delay investments,11 the repeal of the Australian carbon tax in 2014 (Clean Energy Legislation (Carbon Tax Repeal) Bill 2014) being a cautionary tale.12 The EU Emissions Trading Scheme has also had a limited effect. The price of emissions certificates following the 9

Department of Energy & Climate Change, ‘Parsons Brinckerhoff electricity generation model’. International Energy Agency, Carbon Capture and Storage and the London Protocol: Options for Enabling Transboundary CO2 Transfer (OECD/IEA, 2011). 11 S. Brunner, C. Flachsland and R. Marchinski, ‘Credible commitment in carbon policy’, Climate Policy 12(2) (2012), 255–71. 12 Clean Energy Legislation (Carbon Tax Repeal) Bill 2014 (2014), Parliament of Australia. 10

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global financial crisis of 2007–8 collapsed13 and has not yet recovered to a level sufficient to have a large effect on the carbon intensity of the European energy system. Direct subsidies A number of countries, particularly in Europe, have introduced direct subsidies for low-carbon technologies such as wind turbines and solar photovoltaics. These typically are intended to be generous at first to kick-start the industry then taper off when the industry matures and production costs begin to fall due to technological learning and economies of scale. At the moment, direct subsidies for CCS are being put forward in the form of large grants from national or regional governments in order to build commercial-scale demonstration plants. In the UK, new power plants with CCS will also be eligible to apply for so-called Contracts for Difference,14 which help decrease risk to the investor by paying a guaranteed price for the electricity produced for a certain number of years. Bans Outright bans on polluting technologies can be a very effective method of instigating technological change and have a history of success. The UK has already effectively banned the construction of new coal-fired power plants unless fitted with CCS technology. The Energy Act 201315 introduced an emissions performance standard that limits the average emissions of any new power plant to 450 g/kWh. Coal plants without CCS would not meet this target, whilst the limit will still allow new power plants powered by natural gas as their average emissions would be beneath this limit. CONCLUSIONS Given the complexity of CCS projects, the many stakeholders that will need to be involved and the increased cost of power plants with CCS, in order for it to play a significant part in our climate change mitigation efforts policy-makers will need to provide at least: • a simple and timely process for receiving consent to store carbon dioxide underground and a clear demarcation of responsibility between the company and the state • some form of guarantee to investors that supports long-term CCS investment and can be seen to be at least somewhat irreversible.

13

European Commission (2014), The EU Emissions Trading System (EU ETS), available at http://ec.europa.eu/clima/policies/ets/index_en.htm 14 Parliament of the United Kingdom, Energy Act 2013 (2013), Chapter 2. 15 Ibid., Chapter 8.

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TOO LITTLE AND TOO LATE? AN EVALUATION OF THE REGULATION OF CARBON CAPTURE AND STORAGE AS AN INTEGRAL ELEMENT OF A FU TURE LOW-CARBON ENERGY SYSTEM Stuart Bell1

The capture, transport and storage of carbon emissions (CCS) has been proposed as a potentially significant contributor to the international response to the threat of climate change2 and the meeting of challenging greenhouse gas reduction targets.3 It has also been touted as an integral element of a ‘secure, affordable, low carbon energy system’.4 For all the promotion of CCS found in international treaties and policy documents,5 the reality is that progress towards wholesale adoption of CCS technology has been slow. This chapter aims to evaluate the progress of CCS as a technology along with a suggested prescription for future action. 1 2

3

4

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Professor Stuart Bell is a Professor of Law at York Law School, University of York. The International Energy Agency has estimated that CCS will provide around 14 per cent of cumulative CO2 reductions by 2050 as compared to a ‘business as usual model’; see IEA, Energy Technology Perspectives 2014 (IEA, 2014), p. 76. For the UK, this target is to reduce greenhouse gas emissions by at least 80 per cent from a baseline of 1990 by 2050, see Climate Change Act 2008, s.1. Department of Energy and Climate Change, Next Steps in CCS: Policy Scoping Document, p. 6, available at www.gov.uk/government/publications/ccs-policy-scoping-document There are numerous examples of policy-based ‘roadmaps’ published by governmental bodies in the US, Australia, Canada, England and Scotland (to name a few) as well as non-governmental examples published by agencies such as the International Energy Agency and the Global CCS Institute. See, for example, DECC, CCS Roadmap – Supporting Deployment of Carbon Capture and Storage in the UK (2012), available at www.gov.uk/government/uploads/system/uploads/ attachment_data/file/48317/4899-the-ccs-roadmap.pdf; Scottish Government and Scottish Enterprise, Carbon Capture and Storage – A Roadmap for Scotland, (2010), available at www.gov.scot/ Resource/Doc/306380/0096201.pdf; and International Energy Agency, Technology Roadmap: Carbon Capture and Storage (OECD/IEA, 2013).

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WHAT IS CARBON CAPTURE AND STORAGE? The CCS process involves technology which ‘captures’6 CO2 from major point emissions sources such as power generation facilities or other energyintensive activities;7 transports compressed CO2 through pipelines;8 and finally injects and stores the captured gases for an indefinite period in underground geological formations. Thus the aim of the process is to reduce overall emissions of CO2 through the long term ‘disposal’ of waste emissions through storage. This seemingly simple explanation conceals a range of issues which centre around the operational risks associated with the capture, transport and indefinite storage of large volumes of potentially harmful emissions; the incentives available to potential operators who are required to undertake investment over long periods to secure the technological infrastructure for CCS; and the provision of a clear and consistent regulatory framework that provides certainty for regulators and operators. Such regulatory frameworks need to create efficient administrative systems to control operational activities associated with CCS whilst at the same time imposing transparent and equitable systems of allocating and apportioning liability for any losses/damage caused by operational activities and post-operational storage. BACKGROUND A key driver of change for CCS can be found in the Clean Development Mechanism (CDM) of the Kyoto Protocol9 to the UN Framework Convention on Climate Change. The Protocol imposed binding obligations on so-called Annex I parties10 including mandatory reduction targets for greenhouse gas emissions and flexible mechanisms designed to achieve those reductions.11 The CDM provides flexibility by permitting offsets against targets through funding emissions-reduction projects in developing countries. In 2011,12 CCS was finally included within the list of activities which can be considered to be eligible under the CDM, thus providing some momentum for wider adoption 6

The term ‘capture’ is relative here with common pre- and post-combustion processes reducing emissions rates by up to 90 per cent with more recent oxy-fuel processes during combustion reducing emissions by some 98 per cent. 7 This can involve chemical processes to ‘scrub’ the gases clean of impurities. 8 Transportation typically occurs over long distances as suitable storage sites are rarely close to locations where CO2 is produced. 9 Kyoto Protocol to the UN Framework Convention on Climate Change, Art. 12. See UN Doc FCCC/CP/1997/7/Add.1 at unfccc.int/resource/docs/convkp/kpeng.pdf, Art. 12. 10 Thirty-seven industrialised countries including USA, Canada, the Russian Federation, Australia and the fifteen member states of the European Union at the time of signing. 11 Key provisions dealing with aggregated emissions targets, joint implementation mechanisms and emissions trading systems. 12 See Decision 2/CMP.4: ‘Further guidance on the Clean Development Mechanism’; Decision 2/CMP.5: ‘Further guidance relating to the Clean Development Mechanism’; and Decision 7/CMP.6: ‘Carbon dioxide capture and storage in geological formations as Clean Development Mechanism project activities’, all available at cdm.unfccc.int/about/ccs/index.html

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of policies and legislation to promote CCS as a mechanism to address the reduction of greenhouse gas emissions.13 PROGRESS TOWARDS GREATER USE OF CCS TECHNOLOGY Although the clarification of the role of CCS in the CDM provided some certainty for operators, the progress towards full-scale implementation of CCS has remained slow and focused on a mixture of experimental pilot plants and a small number of large-scale projects.14 The development of CCS law and policy frameworks reflects this patchy implementation with mixed progress in different regions. In terms of policy initiatives, the European Union has been active with a range of direct incentives to invest in pilot projects through the European Energy Programme for Recovery and NER300.15 In addition, in 2009, the EU Emissions Trading System (ETS) was amended to allow emissions which were captured and stored in accordance with an authorised CCS process to be treated as ‘not emitted’, thereby providing an indirect financial incentive for CCS operations.16 Alongside broader policy initiatives, there has been some progress in introducing legislative frameworks for CCS. The EU has a comprehensive CCS Directive.17 The Directive forms one of four pieces of legislation intended to deliver emissions reductions targets in the EU’s Climate Change ‘Package’.18 The Directive addresses the authorisation, monitoring and risk management of the capture, transport and storage components of CCS. The Directive anticipated an ambitious expansion of CCS facilities within Europe but in practice progress has been disappointing.19 The Directive was subject to a mandatory 13

Decision 10/CMP.7 makes provision for rules and procedures which must be complied with before any credit for an associated CCS project can be used to account against Annex I mitigation targets under the Kyoto Protocol FCCC/KP/CMP/2011/10/Add.2 ‘Modalities and procedures for the carbon dioxide capture and storage in geological formations as clean development mechanism project activities’, available at unfccc.int/resource/docs/2011/cmp7/eng/10a02.pdf 14 In 2014 there were thirteen large-scale CCS projects in operation, with the majority found in the US. By contrast, in 2011 there were eight projects operating with four of those in the US; see Global CCS Institute, The Global Status of CCS: 2014, p. 41, available at www.globalccsinstitute.com/publications/global-status-ccs-2014 15 NER300 arises from the revised Emissions Trading Directive 2009/29/EC Art. 10a(8) which allocated 300 million emission unit allowances for new entrants to the Trading Scheme. These allowances were sold and the proceeds made available for CCS pilot schemes and renewable schemes. In two rounds of bidding only one CCS scheme was funded. The EEPR allocated funds to six projects. See http://ec.europa.eu/clima/policies/lowcarbon/index_en.htm 16 See Emissions Trading Directive 2009/29/EC, Annex I. 17 Directive 2009/31/EC on the geological storage of carbon dioxide OJ L140/114. 18 This package includes other initiatives on renewable energy, see Directive 2009/28/EC; Emissions Trading, see Directive 2009/29/EC; and a decision on sharing emissions reduction targets, see Decision No. 406/2009/EC. 19 It was anticipated that within a five-year period following the introduction of the Directive there would be up to twelve large-scale CCS plants operating in Europe. In fact only two have commenced operations within that period; see Triple E Consulting, Ricardo AEA and TNO, ‘Support to the review of Directive 2009/31/EC on the geological storage of carbon dioxide (CCS Directive)’; see www.ccs-directive-evaluation.eu

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review process in December 2014.20 The conclusions of the review underlined the relative lack of progress on practical implementation and a general view that wholesale changes to the Directive would be premature.21 In North America, the focus of CCS activity has been through enhanced oil recovery operations (CO2-EOR) with projects in Canada22 and the US.23 Unlike Europe, there is no overarching or comprehensive policy or legislative framework for CCS development. In the US, the emphasis of law and policy has been on performance standards for new and existing power plants.24 The lack of a broader range of incentives and a coherent approach to regulation means that the adoption of CCS projects outside CO2-EOR projects is minimal.25 Elsewhere in the world, progress has been slow with projects at various stages of the development cycle in the Middle East, China, Australia, Brazil, Japan and Korea, but again little large-scale operating capacity.26 EVALUATION OF PROGRESS Although initial practical implementation has been slow, progress on large-scale CCS projects is set to accelerate.27 It is anticipated that a tranche of new projects will provide further evidence of the feasibility of large-scale projects across different industrial sectors and with different capture and storage technologies. In turn, the increased adoption of large-scale projects should address any remaining issues about the ‘experimental’ nature of CCS technologies, increase confidence and lead to broader implementation – in particular in non-Organization for Economic Cooperation and Development countries post-2020. Notwithstanding the number of pipeline projects, the slow take-up of largescale CCS technology raises some interesting questions about the extent to which the technology really is a feasible part of a package of climate change measures. If, as proponents argue, the benefits of utilising CCS as a costefficient method of achieving emissions reduction targets outweigh the potential risks associated with the technology, what is needed to maintain and accelerate progress? MORE INTERNATIONAL COLLABORATION IS REQUIRED The initial phase of development has been concentrated in a few countries.28 Operational knowledge is therefore restricted and more international collaboration 20

See the requirement to review contained in Directive 2009/31/EC, Art. 38. Triple E Consulting et al., ‘Support to the review of Directive 2009/31/EC’. 22 For example, an EOR operation run by the PCOR Partnership in Alberta has been operational since 2006. In 2014, Canada also became home to the first large-scale CCS facility at a powergeneration facility at Boundary Dam Power Station in Saskatchewan. 23 For example, the Val Verde Project in Texas. 24 Clean Air Act, s.111 (b) and (d). 25 With the notable exception of the Boundary Dam Project – the world’s first large-scale postcombustion CCS facility at a coal-fired power station. 26 Global CCS Institute, The Global Status of CCS: 2014, Chapters 3 and 4. 27 Ibid., Chapters 3 and 4. In 2015 there are a further twenty-two projects which are far advanced in the stages of planning and pre-operation. 28 Ibid., Chapters 3 and 4. 21

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is required to speed up wider participation. Greater knowledge exchange would facilitate new projects by reducing implementation time and costs in developing countries. In addition to knowledge exchange, collaboration is required to address geographical and regulatory issues. Sites which are suitable for largescale storage purposes are not evenly distributed geographically or necessarily located in close proximity to activities which produce emissions. Regional and international cooperation on storage site identification and utilisation is a pre-requisite for joint action. Finally, transportation across state boundaries requires cooperation on access to shared networks through a consistent regulatory regime. FINANCIAL AND OTHER MARKET-BASED MECHANISMS NEED TO BE REINFORCED The regulatory structure for CCS is a complex mixture of ‘carrot’-based market mechanisms and the ‘stick’ of familiar command-and-control administrative regulation. One factor in the slow uptake is that the ‘carrot’ side of the equation has not sufficiently incentivised investment in new projects. Further work is needed to develop the so-called ‘carbon economy’ to provide adequate financial incentives to invest in large-scale CCS activities as compared to alternatives (or simply as compared to maintaining ‘business as usual’). The introduction of carbon pricing mechanisms as part of a broad ‘carbon market’ has not provided the necessary kick-start to incentives to invest in CCS.29 The economic recession and corresponding impact upon energy markets have caused problems for many carbon pricing mechanisms – in particular emissions trading schemes. In Europe, the EU ETS has seen an oversupply of emissions allowances and a dramatic fall in the price of carbon.30 Although there have been moves to address the structural deficiencies of the scheme, the knock-on effects of the oversupply have led to a lack of incentives to invest significantly in CCS.31 The relative failure of the EU ETS to incentivise operators has led to efforts to reform the EU ETS through a proposal to introduce a Market Stability Reserve to shore up the market price of carbon in addition to plans to address the 29

World Bank and Ecofys, ‘State and trends of carbon pricing’ (2014), The World Bank, Documents and Reports, available at http://documents.worldbank.org/curated/en/2014/05/19572833/ state-trends-carbon-pricing-2014 30 This fell from a high of around €30 in 2008 down to a low of around €4 in 2013; see ‘EU carbon price crashes to record low’, The Guardian (24 January 2013), available at www.theguardian. com/environment/2013/jan/24/eu-carbon-price-crash-record-low 31 Under Art.10a(8) of the amended Emissions Trading Directive 300 million allowances for new entrants to the ETS were reserved to support commercial CCS demonstration projects. Under NER300 no funding was allocated in the first round of bidding and only one CCS bid was successful in the second round. See European Commission, ‘Award decision under the first call for proposals of the NER 300 funding programme C(2012) 9432 final’, available at ec.europa.eu/ clima/policies/lowcarbon/ner300/docs/c_2012_9432_en.pdf, and European Commission, ‘Award decision under the second call for proposals of the NER 300 funding programme C(2014) 4493 final’, available at eur-lex.europa.eu/legal-content/EN/TXT/HTML/?uri=URISERV:200106_1&fro m=EN, respectively.

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problem of carbon leakage.32 If market mechanisms are to be a key element of a climate change policy, a more rigorous approach to carbon pricing needs to be enforced. CONTINUING REGULATORY UNCERTAINTIES NEED TO BE CLARIFIED If the ‘carrot’ element of the regulatory regime is not operating as a true incentive, the ‘stick’ of legislation is relatively uncontroversial, if as yet also untested.33 There is, however, ongoing uncertainty over what is a probably a unique feature of CCS regulation, namely the allocation and apportionment of liabilities which arise from risks associated with long-term storage.34 In general, most regulatory schemes address the transfer of liability with the state typically taking over indefinite liabilities from operators after a given period of time.35 There is, however, little detail on either the funding of these long-term liabilities or the overlap between the statutory regimes and parallel private-law liability systems. The temporal factors at play here are more than just hypothetical. Although the geological conditions under which storage is maintained is stable, it is clear that over the decades and even centuries, it would be reasonable to foresee at least some geological changes to a contiguous storage area. The exact nature of those changes; how and when they occur; and the nature of any consequences are all unpredictable – even with the current state of modelling. In addition, it is also reasonable to foresee at least some changes within the legal and regulatory context of storage. Societal attitudes to CCS, legislation and technology will all inevitably change. It is unreasonable to suggest that any liability scheme in 2015 will adequately address all risks in 2115. Whilst the risks involved may be manageable in the medium to long term (as technological advances permit) the costs of post-closure management are difficult to predict, make provision for or allocate to potentially responsible parties. 32

Carbon leakage is a term for the situation where operators in certain sectors transfer activities away from countries where the carbon price is high to countries with laxer controls – potentially maintaining or increasing overall emissions levels. Directive 2009/29/EC Art. 10a addresses this situation. In practice, the low price of carbon has meant it is unlikely to have been a significant issue; see Y. Spassov, ‘EU ETS: upholding the carbon price without incidence of carbon leakage’, Journal of Environmental Law 24(2) (2012), 311–44. 33 T. Barker, I. Bashmakov, A. Alharthi, M. Amann, L. Cifuentes, J. Drexhage, M. Duan, O. Edenhofer, B. Flannery, M. Grubb, M. Hoogwijk, F. I. Ibitoye, C. J. Jepma, W.A. Pizer and K. Yamaji, ‘Mitigation from a cross-sectoral perspective’, in Climate Change 2007: Mitigation. Contribution of Working Group III to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (eds B. Metz, O. R. Davidson, P. R. Bosch, R. Dave and L. A. Meyer) (Cambridge University Press, 2007), available at ipcc.ch/publications_and_data/ar4/wg3/en/ ch11.html 34 When the term ‘long-term’ storage is used here, there is theoretically no time limit on the need to manage any risks which arise from the storage and any consequent leakage of CO2. 35 For example, under the EU CCS Directive, the period is a minimum of twenty years post-closure, see Art. 18.

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There is a growing view that the coming decade will be critical if CCS is going to feature as a key element of a low-carbon energy system. Although progress has been slow, there are key factors which should assist in faster implementation: these are greater international collaboration in developing CCS projects; reinforcement of current market mechanisms to reflect the true cost of carbon; and greater clarification of the allocation of post-closure stewardship costs for long-term storage.

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CARBON CAPTURE AND STORAGE READINESS ASSESSMENT: A PREMATURE REGULATORY REQUIREMENT? Owen McIntyre1

INTRODUCTION Article 33(1) of the 2009 Directive on the geological storage of carbon dioxide (CCS Directive)2 requires an assessment of the readiness of certain new thermal power stations for the retrofitting of carbon capture and sequestration technology as and when such technology becomes available and feasible.3 The requirement for CCS readiness was perceived to be of such urgency4 that Article 33(1) was not subject to the deadline for general transposition of the Directive (25 June 2011),5 but instead entered into force on 25 June 2009.6 1

2 3

4 5 6

Professor Owen McIntyre is a Senior Lecturer and Director of Research at the School of Law, University College Cork. His principal area of interest is environmental law and he currently serves as Chair of the IUCN World Commission on Environmental Law’s Specialist Group on Water and Wetlands; as a member of the Project Complaints Mechanism of the European Bank for Reconstruction and Development; and as a member of the Scientific Committee of the European Environment Agency. Directive 2009/31/EC, OJ L 140/114, 5 June 2009. According to the International Energy Agency, CCS readiness means that ‘Developers of captureready plants should take responsibility for ensuring that all known factors in their control that would prevent installation and operation of CO2 capture have been eliminated. This might include: (i) A study of options for CO2 capture retrofit and potential pre-investments, (ii) Inclusion of sufficient space and access for the additional facilities that would be required, (iii) Identification of reasonable route(s) to storage of CO2’. See www.iea.org/papers/2007/CO2_capture_ready_plants.pdf, at 2–3. See CCS Directive, Recital 47. As specified under Article 39(1). That provision itself stipulates that the requirement for operators to assess whether the relevant CCS readiness conditions are satisfied applies to plants for which the original construction or operating licence ‘is granted after the entry into force of Directive 2009/31/EC’. Article 40 of the 2009 CCS Directive provides that it ‘shall enter into force on the 20th day following its publication in the Official Journal of European Union’. The Directive was officially published on 5 June 2009 (OJ L 140/114, 5 June 2009). Therefore, Article 33 became applicable on 25 June 2009.

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Therefore, quite unusually for an imperative EU Directive provision, the requirements of Article 33(1) became applicable almost immediately, though this might partly be explained by the fact that Article 33 simply amends an existing Directive, which was already in force.7 However, in the light of recent setbacks and continuing uncertainty relating to the deployment of viable CCS technology,8 this provision increasingly appears to have introduced a premature and ineffective regulatory requirement. Article 33(1) provides that Member States shall ensure that operators of all combustion plants with a rated electrical output of 300 megawatts . . . have assessed whether the following conditions are met: • suitable storage sites are available, • transport facilities are technically and economically feasible, • it is technically and economically feasible to retrofit for CO2 capture. Where these conditions are met, Article 33(2) requires that ‘the competent authority shall ensure that suitable space on the installation site for the equipment necessary to capture and compress CO2 is set aside’. Therefore, Article 33(1) would appear to require, in the first instance, that an assessment be conducted of thermal power plant projects in order to establish the overall feasibility of CO2 capture, transport and storage. Where such feasibility is established, it must then be established under Article 33(2) that sufficient space is set aside at the plant site for the capture and compression of CO2 from the plant. AVAILABILITY OF A STORAGE SITE Regarding the availability of a suitable storage site, an operator ought, as a minimum, to carry out its assessment in accordance with the requirements of Annex I of the CCS Directive, which establishes ‘Criteria for the Characterisation and Assessment of the Potential Storage Complex and Surrounding Area’. Annex I usefully stipulates that such characterisation and assessment ‘shall be carried out in three steps according to best practices at the time of the assessment and to the . . . criteria’ set down therein. The three steps elaborated comprise: • Step 1 – data collection • Step 2 – building a three-dimensional static geological earth model • Step 3 – characterisation of the storage dynamic behaviour, sensitivity characterisation, risk assessment. 7

8

Directive 2001/80/EC on the limitation of emissions of certain pollutants into the air from large combustion plants, OJ L309/1, 27 November 2001 (hereafter the Large Combustion Plant (LCP) Directive). In 2010, the LCP Directive was incorporated into the new consolidated Directive 2010/75/EU on industrial emissions (integrated pollution prevention and control), OJ L334/17, 17 December 2010 (hereafter the Industrial Emissions Directive (IED)). Article 33 of the CCS Directive can now be read as Article 36 of the IED Directive. See, for example, S. Robinson, ‘Cutting carbon: should we capture and store it?’, Time (22 January 2012).

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Further official guidance exists in relation to the assessment of the availability of a suitable storage site in the form of the European Commission’s Guidance Document 2,9 which provides technical detail on the methodology required for each of the assessment steps outlined above. In addition, detailed guidance on the practice of assessing CCS readiness has been produced by the national authorities of EU member states10 and by industry groups and fora dedicated to the development and promotion of CCS technology.11 In practical terms, the UK guidance cited above suggests that demonstration of a suitable storage area should involve: • identification of a possible storage area, including delineating the geographical extent of that area, and identification within that area of at least two ‘viable’ or ‘realistic’ geological formations; • reliance on authoritative data sources for identification of the suitability of these areas and geological formations • a short summary including an estimate of the total volume of CO2 likely to be captured and stored by the power station and an estimate of the CO2 storage potential of the area(s) identified by the applicant. ECONOMIC FEASIBILITY OF CO2 CAPTURE, TRANSPORT AND STORAGE Regarding the assessment of the technical and economic feasibility of CO2 transport facilities and of retrofitting the power plant for CO2 capture, the 2009 CCS Directive does not provide any form of guidance. However, the general concepts of ‘economic feasibility’ and ‘technical feasibility’ are outlined elsewhere in EU law and policy. For example, the European Commission’s 2008 ‘Guide to cost-benefit analysis of investment projects’12 provides detailed guidance and case studies on financial and economic analysis of projects, including guidance on feasibility analysis. Despite the absence of detailed guidance in the

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European Commission, ‘Implementation of Directive 2009/31EC on the geological storage of carbon dioxide: Guidance Document 2 – characterisation of the storage complex, CO2 stream composition, monitoring and corrective measures’ (2011), available at http://ec.europa.eu/clima/ policies/lowcarbon/ccs/implementation/docs/gd2_en.pdf 10 See, for example, Department of Energy and Climate Change (UK), ‘Carbon Capture Readiness (CCR): a guidance note for Section 36 Electricity Act 1989 consent applications’ (2009), available at https://whitehall-admin.production.alphagov.co.uk/government/uploads/system/uploads/ attachment_data/file/43609/Carbon_capture_readiness_-_guidance.pdf. While this guidance concerns the specific requirements for consent applications made under Section 36 of the 1989 UK Electricity Act, it makes it quite clear (at 7, Para. 2) that ‘This guidance implements both Article 33 of the Directive and the Government’s further requirement that if a proposed power station is subject to the Directive requirements, it will only be granted development consent if it is assessed positively against the Article 33 criteria.’ 11 Global Carbon Capture and Storage Institute/ICF International, ‘CCS Ready Policy: considerations and recommended practices for policymakers (2010), available at: www.cslforum.org/ publications/documents/CCS_Ready_Policy_Considerations.pdf 12 European Commission, ‘Guide to cost-benefit analysis of investment projects: structural funds, cohesion fund and instrument for pre-accession’ (2008), available at http://ec.europa.eu/regional_ policy/sources/docgener/guides/cost/guide2008_en.pdf

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CCS Directive, Recital 47 to that measure does provide a broad indication of what an assessment of economic feasibility might consider, stating that the economic feasibility of the transport and retrofitting should be assessed taking into account the anticipated costs of avoided CO2 for the particular local conditions in the case of retrofitting and the anticipated costs of CO2 allowances in the Community. The projections should be based on the latest evidence; a review of technical options and an analysis of uncertainties in the assessment processes should also be undertaken.13 More usefully, perhaps, a report examining CCS readiness at a proposed power plant in Slovenia has defined ‘economically feasible’ in the context of CCS readiness to mean that during the operating life of the plant, there is a probability that a plant if retrofitted and operated with CCS can earn a reasonable rate of return on investment. The plant’s total cost for capture, transport, and storage would include planning, construction capital, and operating costs, including the time value of money.14 Therefore, the assessment should attempt to balance the costs likely to be incurred in deploying CCS technology with its possible economic benefits having regard to the likely cost of CO2 emission allowances. Taking Recital 47 as its starting point, the 2009 UK guidance on assessment of CCS readiness sets out a reasonably comprehensive methodology and set of parameters for assessment of the economic feasibility of CCS.15 In practical terms, in order to ensure ‘that the assessments are a meaningful part of the CCR process’, the UK government advises that ‘applicants should conduct a single economic assessment which encompasses retrofitting of capture equipment, CO2 transport and the storage of CO2’.16 The UK guidance also provides an indicative list of information sources which might be helpful in conducting the assessment of economic feasibility,17 and a list of parameters to be taken into account including, inter alia, the assumed exchange rate; internal rate of return; fuel price; carbon price; power output with/without CCS; lifetime load factor; CO2 emitted with/without CCS; cost of transport (construction and operation); cost of retrofitting capture equipment (construction and operation); and cost of storage (permitting and operation).18 As regards a methodology for the assessment of economic feasibility, the UK guidance proposes a model structure, within 13

Emphasis added. Bellona Foundation/Environmental Law Service, ‘CCS readiness at Šoštanj: ticking boxes or preparing for the future?’ (2011), 13, available at http://bellona.org/publication/ccs-readinesssostanj-ticking-boxes-preparing-future 15 Department of Energy and Climate Change (UK), ‘Carbon Capture Readiness (CCR): a guidance note for Section 36 Electricity Act 1989 consent applications’, at 24, Para. 64. 16 Ibid., at 24, Para. 64. 17 Ibid., Annex E(ii), at 56. 18 Ibid., at 25, Para. 68. 14

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which applicants should justify the capture, transport and storage options chosen for their proposed development. The UK guidance advises that, ultimately, after having conducted an assessment and made a determination of economic feasibility, the applicants should ‘then produce a clear summary of their results and state under which reasonable scenarios and parameter ranges operational CCS would be economically feasible’.19 TECHNICAL FEASIBILITY OF CO2 CAPTURE AND TRANSPORT The Bellona Report suggests that the term ‘technically feasible’ can be interpreted in the specific context of CCS readiness as meaning that ‘technologies exist that can be applied to capture and transport and store a significant portion of the CO2 emitted from the plant, while substantially preserving the original functionality of the plant’.20 This common-sense interpretation is based on a general conception of the term ‘technically feasible’ to mean that ‘technical resources capable of meeting the needs of a proposed system can be acquired by the operator in the required time’ and largely relies on a 2009 United Nations Industrial Development Organization (UNIDO) manual on preparing general industrial feasibility studies.21 Regarding the technical feasibility of retrofitting for CO2 capture and storage specifically, the 2009 UK guidance advises applicants that ‘the Government intends to consider applicants’ CCR assessments with a “no barriers” approach’, whereby ‘[a]pplicants are asked to demonstrate that there are no known technical or economic barriers which would prevent the installation and operation of their chosen CCS technologies’.22 Regarding assessment of the technical feasibility of CO2 transport to the proposed storage area, the same UK guidance elaborates extensive advice.23 For example, in terms of a feasible route from the plant, it suggests that applicants should, for the first 10 km surrounding the power station, identify a favoured route within a 1 km wide corridor, while also identifying major preexisting obstacles arising due to safety or environmental concerns.24 Beyond the first 10 km from the power station, applicants are advised to identify a 10 km wide corridor to the proposed storage area (or to the coast in the case of an offshore storage area).25 The guidance also makes it clear that ‘given the inevitable uncertainty about the precise route and what might by the CCS stage 19

Ibid., at 26, Para. 68. Bellona Foundation/Environmental Law Service, ‘CCS readiness at Šoštanj’, 13. 21 W. Behrens and P. M. Hawranek, Manual for the Preparation of Industrial Feasibility Studies (UNIDO, 2009). 22 Department of Energy and Climate Change (UK), ‘Carbon Capture Readiness (CCR): a guidance note for Section 36 Electricity Act 1989 consent applications’, at 14, Para. 27, which goes on to explain that ‘Government does not intend to prescribe the detail of how CCS technology will apply in individual cases, but does expect that applicants will follow best practice as far as this knowledge is available and provide a reasoned justification of their choices’. 23 Ibid., at 18–23. 24 Ibid., at 18, Para. 44. 25 Ibid., at 19, Para. 46. It should be pointed out that UK government policy dictates that ‘only offshore areas are currently considered suitable by Government for CO2 storage’, see Ibid., at 15, Para. 33. 20

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in the future be the safety and environmental requirements, we do not envisage any formal environmental impact assessment (EIA) being undertaken’, although ‘[t]his will however need to be done when an operator wishes to fit CCS to the plant’.26 Generally, it advises that ‘[a] precautionary approach will need to be taken by developers . . . given the developing regulatory regime, to ensure that no known barriers exist along the proposed route’.27 The guidance also sets out the essential contents of the required ‘Transport Technical Feasibility Study’.28 ALLOCATION OF SPACE FOR CARBON CAPTURE EQUIPMENT Regarding the second phase of the CCS readiness assessment required under Article 33(2) if the first phase shows that CCS is feasible, that is, that of ensuring ‘that suitable space on the installation site for the equipment necessary to capture and compress CO2 is set aside’, the CCS Directive provides little practical guidance. However, detailed technical guidance on space allocation is provided in a 2006 report by the International Energy Agency (IEA), which sets out an approximate minimum land footprint for CO2 capture installations for different types of gas and coal plant.29 In addition, using such IEA technical values as a starting point, the 2009 UK guidance provides useful practical advice on the factors to be considered in the allocation of suitable space, as well as a comprehensive methodology for ensuring compliance with the relevant UK legislative requirements.30 More generally, the UK guidance requires that applicants demonstrate that ‘suitably located land will be available for them to use for the capture element of the CCS chain at the point of retrofit’,31 and also provides detailed advice on the information required to assist in the making of such assessments, including the contents of site plans which operators should include in their applications.32 CONCLUSION Given the uncertainties inherent in what amounts to a speculative assessment of the economic and technical feasibility of retrofitting an as yet unproven and unavailable technology, Article 33 appears to represent a regulatory requirement of questionable utility and effectiveness, as well as a misallocation of the scarce resources available for environmental protection and improvement.

26

Ibid., at 19, Para. 48. Ibid., at 21–2, Para. 58. 28 Ibid., at 23, Para. 61. 29 IEA Greenhouse Gas R&D Programme (IEAGHG), ‘CO2 capture as a factor in power plant investment decisions’, IEAGHG Report 2006/8, available at www.ieaghg.org/docs/General_ Docs/Reports/2006-8%20Capture%20in%20power%20stations.pdf 30 Department of Energy and Climate Change (UK), ‘Carbon Capture Readiness (CCR): a guidance note for Section 36 Electricity Act 1989 consent applications’, at 9–12. 31 Ibid., at 11, Para. 15. 32 Ibid., at 12, Para. 18. 27

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VALUE OF ENERGY STORAGE: THE REQUIRED MARKET AND POLICY SUPPORTS Behnam Zakeri1 and Sanna M. Syri2

Intermittency challenge is still the most pronounced technical barrier in the integration of variable renewable energy sources (VRES). The World Energy Outlook (2014), published by the International Energy Agency (IEA), estimates the share of VRES to reach 23 per cent of total electricity generation in the European Union by 2040.3 An array of solutions is discussed in the literature for enhancing the flexibility of the power and energy systems, from generation to demand side. Energy storage is one of the remedies to balance the variations in power supply from VRES. Electrical energy storage (EES) systems comprise a wide range of technologies with different characteristics that can be potentially employed in different levels of the power supply chain, from generation, through transmission and distribution (T&D) to the end-user level. 1

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Behnam Zakeri is a Doctoral Researcher in the fields of energy systems analysis, energy economics and power markets. He has recently examined the possible role of energy storage systems in the future high renewable energy scenarios. His work on the economics of energy storage in the Nordic power market was acclaimed as one of the best papers in the eleventh International Conference on European Energy Markets (EEM 2014), Krakow, Poland. He is also studying the benefits of flexibility solutions, including energy storage for the island energy systems. He is a member of a multidisciplinary research project on Sustainable Transition of European Energy Markets (STEEM), supported by Aalto University’s Energy Efficiency platform. The research fields and expertise of Professor Sanna Syri are energy economics, mitigation of climate change, EU-wide energy and climate policy and electricity markets. She is frequently consulted by the Finnish Parliament to support national-level decisions in environmental and energy policies. She is also a member of the Finnish Climate Panel nominated by the Minister of Environment. International Energy Agency, World Energy Outlook 2014 (OECD/IEA, 2014).

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EES has long been serving power systems in load-levelling, energy arbitrage, nuclear capacity firming, ancillary services and power quality applications. Pumped hydropower storage (PHS) is the dominant EES technology with an installed capacity of over 140 GW worldwide. Environmental awareness and the scarcity of attractive sites have caused a decline in the construction of new PHS sites since the late 1980s.4 Moreover, the deregulation of power markets based on a marginal cost pricing mechanism has further complicated the issue of investment on capital-intensive storage technologies such as PHS. On the other hand, the volatility in the electricity prices due to the introduction of VRES and the required backup power calls for a more robust cost-benefit analysis of EES systems based on the emerging market conditions. Lack of adequate knowledge about the economy of utility-scale EES systems is one of the major obstacles in the establishment of feasible business models, ownership structures and required regulation strategies. In 2013, the US Department of Energy (DOE) announced four major challenges in the widespread deployment of EES, of which cost-competitiveness is to be resolved with a focus on life-cycle costs (LCC) of EES systems.5 In this respect, the uncertainty in the estimation of LCC of EES is deemed to be a major hindrance, even for those commercially proven technologies such as PHS and compressed air energy storage (CAES).6 With the absence of commercial applications for most batteries, their cost per kilowatts installed capacity is relatively high with a wide disparity among different suppliers. The LCC is highly variable depending on the service requirements including discharge cycles per day, lifetime of service and depth of discharge, for example. For bulk energy storage, the levelised cost of electricity (LCOE) discharged by storage varies from €120 €/MWh for PHS to €244 and €323/MWh for sodium-sulphur and lead-acid batteries, respectively.7 The high capital cost of EES systems is a primary barrier in the widespread adoption of these technologies, demanding more research to reduce costs rather than improvements in marginal performance.8 EES can create revenue through a wide range of applications. Price arbitrage is one of the frequently discussed benefits of EES. The level of profitability in this application directly depends on fuel and carbon prices, EES technological features and, most importantly, the degree of price spread in the examined market. It has been shown that price arbitrage is not sufficient 4

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J. P. Deane, B. P. Ó Gallachóir and E. J. McKeogh, ‘Techno-economic review of existing and new pumped hydro energy storage plant’, Renewable & Sustainable Energy Reviews 14(4) (2010), 1293–302. The US Department of Energy (DOE), ‘Grid energy storage’ (2013), available at http://energy. gov/oe/downloads/grid-energy-storage-december-2013 Behnam Zakeri and Sanna Syri, ‘Electrical energy storage systems: A comparative life cycle cost analysis’ Renewable & Sustainable Energy Reviews 42 (2015), 569–96. Assuming 8 per cent interest rate, 250 cycles per year, €50/MWh price of charging electricity. See Deane et al., ‘Techno-economic review of existing and new pumped hydro energy storage plant’, for more details. D. Bhatnagar, A. Currier, J. Hernandez, O. Ma and B. Kirby, ‘Market and policy barriers to energy storage deployment’, Sandia Report, Sandia National Laboratories (2013).

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to compensate EES costs in different electricity markets.9 More importantly, solar power may reduce the peak prices, and with the higher costs of baseload generation in the future, the profitability of price arbitrage may further deteriorate.10 Inclusion of other marketplaces enhances the profitability of EES in the context of competitive power markets, for example participation in ancillary and capacity markets.11 The Nordic power market is one the pioneer free electricity markets expanding from the UK through the Nordic to the Baltic states. Through the Nordic power market, day-ahead (Elspot) and intraday (Elbas) trades can be settled among the participating countries, while ancillary services markets are managed by each country’s transmission system operator (TSO). The study of possible benefits of EES in different marketplaces demonstrates great potential in the

Figure 124.1 The annual costs of three EES technologies (right) compared with the possible yearly benefits in competitive marketplaces in the Nordic power market (left, for Finland 2014) Elspot: day-ahead market; Elbas: intraday market; FCDR: frequency containment disturbance reserve; FCNR: frequency containment normal reserve.

9

D. Connolly, H. Lund, B. V. Mathiesen, E. Pican and M. Leahy, ‘The technical and economic implications of integrating fluctuating renewable energy using energy storage’, Renewable Energy 43 (2012), 47–60. 10 M. Kloess and K. Zach, ‘Bulk electricity storage technologies for load-leveling operation – an economic assessment for the Austrian and German power market’, International Journal of Electrical Power & Energy Systems 59 (2014), 111–22. 11 R. Sioshansi, S. H. Madaeni and P. Denholm, ‘A dynamic programming approach to estimate the capacity value of energy storage’, IEEE Transactions on Power Systems 29(1) (2014), 395–403.

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ancillary services market.12 The case of Finland is illustrated in Figure 124.1 to compare the LCC of three major EES technologies with the potential benefits in different market levels. Considering a service lifetime of ten years and an interest rate of 5 per cent, low-cost batteries may offer profitability if they could collect the revenues across different markets. In calculation of these benefits, it is assumed that power prices are known or forecasted just for the next twenty-four hours. The longer time-span for energy arbitrage will definitely increase profits. However, the value streams of EES are beyond those offered in free, competitive markets, and can be extended to other services that are not typically deregulated. For example, services in T&D support and congestion relief, T&D investment deferral, reliability and power quality services, renewable energy firming and integration are among those with no clear mechanism for competitiveness in common electricity markets. The National Renewable Energy Laboratory has investigated the value of EES for operational- and capacity-related benefits in the US power markets.13 The study concludes that high-value benefits lie in those services with a very limited market potential, like reserves capacity. In another study,14 the value of EES is assessed for the UK using a system-based approach to account for cost savings in generation, transmission and distribution levels. The results indicate that EES can significantly improve the economy of the power system by alleviating wind curtailment and the capital cost of backup generation or carbon capture and storage (CCS). In research by Sandia National Laboratories,15 the benefits and value propositions of EES systems are demonstrated for a wide range of services, some of which can be realised in parallel. The aggregation of benefits of EES has been widely announced as a major step in the commercialisation of these technologies. The optimal scheduling and capacity allocation to different services are, however, technical limitations that must be thoroughly examined when aggregating the benefits. More importantly, to facilitate this aggregation, the associated market and policy barriers must be alleviated. Lack of EES standards and codes, coherent evaluation methodologies and tools, as well as limited knowledge and experience in implementation of gridscale projects are the main technological obstacles. Rules and regulations are not yet established for the siting, permitting, safety, recognition and valuation of services, as well as for the assessment of risks and revenues of EES. To permit the aggregation of benefits, efficient coordination among numerous stakeholders in 12

B. Zakeri and S. Syri, ‘Economy of electricity storage in the Nordic electricity market: the case for Finland’, Proceedings of 11th International Conference on the European Energy Market (EEM), Krakow, Poland, 28–30 May 2014. 13 P. Denholm, J. Jorgenson, M. Hummon, T. Jenkin, D. Palchak, B. Kirby, O. Ma and M. O’Malley, ‘The value of energy storage for grid applications’, National Renewable Energy Laboratory Technical Report (2013). 14 G. Strbac, M. Aunedi, D. Pudjianto, P. Djapic, F. Teng, A. Sturt, D. Jackravut, R. Sansom, V. Yufit and N. Brandon, ‘Strategic assessment of the role and value of energy storage systems in the UK low carbon energy future’, Report for Carbon Trust by Imperial College London (2012). 15 J. Eyer and G. Corey, ‘Energy storage for the electricity grid: benefits and market potential assessment guide’, Sandia Report, Sandia National Laboratories (2010).

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different power supply levels is required, indicating a possible need for a market reform or restructuring. Traditional frameworks that require the classification of some limited technologies for grid applications should be transformed, permitting the emerging technologies such as EES and electric vehicles to provide services that the grid requires. In this regard, the cost-benefit of other flexibility measures that compete with EES, for example, demand-side management and distributed generation, needs to be evaluated. One of the most significant needs in further penetration of EES is to understand the impact of EES on further integration of VRES, and the methods to value this impact. Future green policies may promote innovative feed-in tariffs that can qualify wind and solar energy for additional incentives as for peak reserves or capacity credits, if these VRES will be combined with EES.

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ENERGY STORAGE SYSTEMS: A RISKY INVESTMENT TO PROVIDE THE REQUIRED FLEXIBILITY FOR FUTURE SMART GRIDS Diletta Colette Invernizzi1 and Giorgio Locatelli2

INTRODUCTION The increasing penetration of Renewable Energy Technologies (RET) producing non-dispatchable and highly variable electricity is becoming a key challenge for the management of the electrical grid. As RET’s electricity production is not related to consumption and is hard to forecast (for example, the wind also blows during the night when electricity demand is low), it could cause imbalances on the grid. Therefore mitigations such as the installation of large Energy Storage Systems (ESS), availability of power plants producing readily dispatchable electricity (such as natural gas fired plants) and more grid interconnections are required.3 In this context, large-scale ESS are among the most promising solutions to balance the effect of renewables, as they can store electricity and deliver it on 1

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Diletta Colette Invernizzi is a PhD student at the School of Civil Engineering at the University of Leeds. Diletta has a Bachelor’s degree in Energy Engineering and a Masters Degree in Management Engineering, both obtained at Politecnico di Milano. Her final Masters dissertation focused on investment appraisal in energy storage systems, which remains one of her main research topics. Dr Giorgio Locatelli is a Lecturer at the School of Civil Engineering at the University of Leeds. He has a Bachelor’s and a Masters degree in Mechanical Engineering and a PhD in Industrial Engineering, Economics and Management from Politecnico di Milano. His main research topic is infrastructural megaprojects, particularly in the energy sector, with a focus on the nuclear industry. He is author of more than eighty international publications, mostly on energy megaprojects. He also works as a consultant and visiting academic for several institutions, including the International Atomic Energy Agency. International Energy Agency, ‘Renewable energy: medium-term market report 2012’ (2012), 182, available at https://www.iea.org/publications/freepublications/publication/MTrenew2012_web.pdf

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demand, contributing to the creation of a reliable stream of power throughout the day. In particular, the technologies suitable for these large-scale applications are Pumped Hydroelectric Storage (PHS) and Compressed Air Energy Storage (CAES). PHS and CAES can economically benefit from operating ‘price arbitrage’, that is, the practice of purchasing low-cost off-peak energy in order to sell it during periods of high prices, and Short Term Operating Reserves (STOR), one of the UK National Grid reserve services. Price arbitrage and STOR are the most relevant for the integration of large amounts of renewable energy, especially of wind power.4 PHS AND CAES PHS is a widely implemented and long-proven storage technology. It consists of two reservoirs located at different heights, a unit that pumps water to the upper reservoir during off-peak hours and a turbine that generates electricity converting hydraulic potential energy during peak hours.5 Its growth capacity stalled from the mid-1980s both in the US and Europe, mostly due to a lack of suitable sites. The siting requirements and the environmental opposition promoted the development of new designs to address these issues, such as: • sub-surface PHS, that uses abandoned mines as reservoirs • sea water PHS, that uses the ocean as the lower reservoir • variable-speed PHS, that allows the machine to work at peak efficiency over a wide range of speeds. The technology concept of CAES systems is more than fifty years old and works on the basis of a conventional gas turbine. During low-cost off-peak periods, a motor uses power to compress air and to store it in an underground cavern. During peak periods the process is reversed and the air is heated and expanded in a gas turbine in order to spin the generator and produce electricity.6 This allows the electricity drawn from the grid to be transformed into compressed air energy and stored in underground caverns.7 Similarly to PHS, CAES systems also require careful evaluation regarding the siting and design of the underground reservoir, which have to meet stringent requirements. As a result, only two CAES systems have been operating for more than twenty years. However, recent geological analysis shows promising results regarding the construction of underground salt caverns for storage in a few countries, such as Germany, 4

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R. K. Edmunds, T. T. Cockerill, T. J. Foxon, D. B. Ingham and M. Pourkashanian, ‘Technical benefits of energy storage and electricity interconnections in future British power systems’, Energy 70 (2014), 577–87. D. O. Akinyele and R. K. Rayudu, ‘Review of energy storage technologies for sustainable power networks’, Sustainable Energy Technologies and Assessments 8 (2014), 74–91. H. Lund and G. Salgi, ‘The role of compressed air energy storage (CAES) in future sustainable energy systems’, Energy Conversion and Management 50(5) (2009), 1172–9. H. Chen, T. N. Cong, W. Yang, C. Tan, Y. Li and Y. Ding, ‘Progress in electrical energy storage system: a critical review’, Progress in Natural Science 19 (2009), 291–312.

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Denmark and the Netherlands. Evaluation for the construction of compressed air storage caverns is also taking place in Northern Ireland.8 R&D efforts have also led to the development of new designs: • Advanced CAES, which stores the heat energy generated during compression and uses it to reheat the air during expansion. • Isothermal CAES, which eliminates the requirement for fuel and high-temperature heat-energy storage, offering an improved roundtrip efficiency. • Small-medium CAES, which uses artificial pressure vessels instead of an underground cavern. • Underwater CAES, which stores air in an underwater storage cavern, and could be integrated with offshore RET. These large scale ESS allow the efficient balancing of RET effects, but suffer from several investment risks. Policy-makers and utilities aim for investments with the highest return at the lowest possible risk, so a risk analysis is essential. INVESTMENT RISKS For a utility, the construction of a new, complex (and often unique) infrastructure is an investment jeopardised by market risks, technology-specific risks and policy risks.9 Market risks are related to the electricity and natural gas supply system; technology-specific risks include uncertainties in capital cost, construction time and environmental externalities; and policy risks are the institutional incentives that could support investment in ESS. Figure 125.1 shows the main risks affecting the investment in PHS and CAES systems: • costs overrun and delays (that causes further costs overrun and postpones the positive cash inflows) mainly occur in the construction phase; and • lower electricity price spread and volatility, and the increase of natural gas cost (that directly affects CAES profitability) reduces the profitability of PHS and CAES during the operation phase. Institutional incentives, as discussed below, can influence every phase of the development of a project and can offset both technology-specific risks and market risks. 8

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S. Donadei and G.-S. Schneider, ‘Compressed air storages: energy from the underground’, Ees International: The Electrical Energy Storage Magazine 1 (2014), 40–3. J. Radcliffe, P. Taylor, L. Davies, W. Blyth and E. Barbour, ‘Energy storage in the UK and Korea: innovation, investment and co-operation. Appendix 3 – impact of risk on investment decisionmaking: the case of energy storage’, Centre for Low carbon Futures Report (July 2014). Available at www.lowcarbonfutures.org/energy-storage/korea; G. Locatelli, M. Mancini and E. Romano, ‘Systems engineering to improve the governance in complex project environments’, International Journal of Project Management 32 (2014), 1395–410.

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Figure 125.1 Main investment risks MAJOR DRIVERS FOR THE DEVELOPMENT OF PHS AND CAES Utilities and investors are widely influenced by the institutional framework of policy makers. Institutions can be classified in two main ways: ‘hard institutions’ (regulators, government agencies etc.) embrace formal written regulations, such as technical standards and risk management regulations, while ‘soft institutions’ refers to informal interfaces including the norms and values of individuals, firms, organisations, regions and industries.10 Hard institutions can encourage ESS investments in many different ways. Market risks, for instance, can be offset after the publication of long-term and stable energy policies specifically designed for ESS. In fact, ESS revenues are believed to increase with the share of intermittent renewables, as electricity produced by renewables is not related to consumption, which affects electricity price spread and volatility.11 However, the intermittency and unpredictability of wind might negatively affect electricity price spread and volatility, and photovoltaic provokes a reduction of midday price peaks, reducing the daily price spread. Therefore fixed tariffs per kWh sold specifically designed for ESS would be valuable to guarantee ESS profitability. Moreover, regarding CAES, the promotion and support of long-term contracts will reduce the risk connected to an increase of natural gas costs. 10

A. Darmani, N. Arvidsson, A. Hidalgo and J. Albors, ‘What drives the development of renewable energy technologies? Toward a typology for the systemic drivers’, Renewable and Sustainable Energy Reviews 38 (2014), 834–47. 11 M. Kloess and K. Zach, ‘Bulk electricity storage technologies for load-leveling operation – an economic assessment for the Austrian and German power market’, International Journal of Electrical Power & Energy Systems 59 (2014), 111–22.

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Conversely, technology-specific risks can be offset by soft institutions and network incentives. On the one hand, soft institutions (and social factors in particular) are strong drivers of changes in the energy market, so the increase in the public awareness of ESS benefits would decrease the aversion against the exploitation of new sites, lowering the risks of delays in the development of the project. On the other hand, promoting the formation of new networks, fostering the cooperation between research group and utilities, and strengthening the supply chain would support efficient R&D and would help to overcome risks connected to limited experience, lack of innovation and delays in procurement. CONCLUSION PHS and CAES are suitable for the storage of large amounts of MWh; however, several investment risks affect their profitability. Within the aforementioned risks, the major challenge is cost overrun, as the capital costs of PHS and CAES are, respectively, more than 80 per cent and 35 per cent of their life-cycle costs. This demonstrates that the impact of a reduction in capital costs will have a significant impact on the investment profitability, and factors such as major technology breakthrough, mass production and long-term industrial learning should be carefully examined. Moreover, incentives for ESS are a relevant and controversial topic currently under discussion. Investors need to be aware of this and they should monitor the development of national energy policies. Indeed, factors such as the eventual publication of long-term energy policies specifically designed for ESS would guarantee their investment sustainability.

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AN ENERGY PARTNERSHIP BETWEEN THE EUROPEAN UNION AND BRAZIL FOR THE PROMOTION OF SECONDGENERATION BIOFUELS Stavros Afionis1 and Lindsay C. Stringer2

Biofuels for transport are liquid or gas renewable energy sources that are produced from biomass and can be used as a substitute or blend for petroleum fuels. Biofuels from food sources are collectively known as first-generation (1G) biofuels, while those that are produced from inedible sources, such as woody crops, energy grasses or even agricultural and forestry residues, are collectively referred to as second-generation (2G) biofuels. The latter are thought to offer more sustainable alternatives than their 1G counterparts, as they are more energy-efficient and less water- and land-intensive, and are expected to achieve greater greenhouse gas emissions reductions.3 However, unlike the easily processed 1G biofuels, the complex substances found in the woody or inedible 1

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Stavros Afionis is a Postdoctoral Research Fellow at the Sustainability Research Institute (SRI) of the School of Earth and Environment at the University of Leeds. His doctoral research examined the role played by the European Union in international climate change negotiations. His research interests currently focus on environmental politics and, in particular, international climate change negotiations and global biofuel policies. Lindsay C. Stringer is Professor in Environment and Development at the Sustainability Research Institute (SRI) of the School of Earth and Environment at the University of Leeds. Lindsay’s research advances understanding of human-environment relationships, focusing on the links between livelihoods and environment; and science, policy and environmental governance, with particular emphasis on the land, climate, water and energy sectors. The authors thank Vivek Mathur for his helpful comments. The research leading to the material in this chapter received funding from the European Community’s Seventh Framework Programme (FP7/2007–2013) under the Grant Agreement No. 251132. SUNLIBB, ‘Sustainable Liquid Biofuels from Biomass Biorefining’ Policy Brief (October 2014), available at www.york.ac.uk/org/cnap/SUNLIBB/pdfs/policy-brief-3-Oct2014.pdf

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tissues of plants are much more challenging to chemically process and convert to energy with currently available methods. Consequently, several technological breakthroughs are still required for 2G biofuels to become commercially viable.4 The same is true of third-generation (3G) biofuels, which are based on marine algae and seaweeds. Promotion of biofuels has been supported by various countries worldwide, most prominently the United States and Brazil, for a wide range of reasons, namely climate change mitigation, energy security concerns and rural development stimulation. During the early 2000s, European Union officials also appeared largely convinced as to the prospects of this renewable energy source for transport, investing heavily in its promotion. The most ambitious EU attempt to boost the use of (mainly) 1G biofuels among its member states came with the promulgation of the 2009 Renewable Energy Directive (RED), which stipulated a mandatory 10 per cent biofuels target to be reached by 2020.5 However, in the immediate aftermath of the RED’s adoption, the use of 1G biofuels in the European market progressively developed into a highly controversial policy area, due to the rise of a number of previously overlooked sustainability complications, such as the food v. fuel dilemma and the potential of biofuels to cause indirect land use change (ILUC).6 Once thought of as a viable green alternative, biofuels gradually transformed therefore from a policy solution to a policy headache for EU authorities, who came under great pressure to reform the RED. Intra-EU negotiations to this effect commenced in 2010, and were only concluded in April 2015 with a political compromise between the EU institutions to set a 7 per cent cap on 1G food-crop biofuels and encourage member states to individually put in place indicative targets for 2G and 3G (advanced) biofuels.7 It should be reiterated at this point that the above deliberations concern the RED’s end date of 2020. The European Commission has already made it clear that post2020 public support for 1G biofuels will not be forthcoming.8 While the EU is in the process of moving away from 1G biofuels, it has yet to clarify its post-2020 vision with respect to advanced biofuels. Indeed, in the EU’s policy framework for climate and energy in the period from 2020 to 2030, which was released in January 2014, 2G biofuels were specifically portrayed as representing a key option for decarbonising the transport sector.9 Yet, lack of detail and targets has 4

5

6 7

8

9

S. Afionis, ‘Biodiesel & biofuels’, in M. Garrett (ed.), Encyclopedia of Transportation: Social Science and Policy (SAGE, 2014). S. Afionis and L. C. Stringer, ‘European Union leadership in biofuels regulation: Europe as a normative power?’, Journal of Cleaner Production 32 (2012), 114–23. ILUC refers to the process of biofuel plantations replacing pasturelands, which in turn replace forests. European Parliament, ‘Parliament supports shift towards advanced biofuels’ (28 April 2015), available at www.europarl.europa.eu/pdfs/news/expert/infopress/20150424IPR45730/20150424 IPR45730_en.pdf; Council of the European Union, ‘Proposal on indirect land-use change: Council reaches agreement’ (13 June 2014), available at www.consilium.europa.eu/uedocs/cms_data/docs/ pressdata/en/ trans/143191.pdf European Commission, ‘A policy framework for climate and energy in the period from 2020 to 2030’ (22 January 2014), available at http://ec.europa.eu/energy/doc/2030/com_2014_15_en.pdf Ibid.

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resulted in an uncertain policy environment which has caused great unrest within the EU biofuels industry. The latter has repeatedly reprimanded the Commission for failing to provide the market with pre- as well as post-2020 clarity.10 Domestic uncertainty has also had repercussions on the EU’s international collaborative projects on biofuels with third countries. Brazil, for instance, with which the EU has had a strategic partnership since 2007, had emerged in the late 2000s as a key partner of the EU when it came to biofuels promotion. In fact, the two had even discussed, albeit inconclusively, the possibility of undertaking joint trilateral projects with African countries, particularly Kenya and Mozambique.11 Over time, however, a number of issues have emerged that have greatly polarised biofuel relations between the EU and Brazil. A first issue relates to the EU-wide standards and certification criteria that have been promulgated by the RED with the intention of fostering a more sustainable biofuels industry, but which have been perceived by Brazilian policy-makers as constituting technical barriers to trade.12 A second issue concerns the EU’s biofuel import tariffs and tax credits, which constrain the commercialisation of inter alia Brazilian ethanol in the European market.13 This tense situation has had a knock-on effect in terms of fostering EU-Brazil partnerships in the 2G sector. To date, cooperation is mostly concentrated in the areas of science, technology and innovation, with a few joint projects having been funded through partnerships with individual member states like the United Kingdom or Germany, or through the EU’s Framework Programmes for Research and Technological Development (FPs).14 In 2013, however, the planned publication for 2015 of a joint call on 2G biofuels that was to be funded under the remit of Horizon 2020 was postponed until further notice by the Brazilians, as funds were reallocated to the Science without Borders initiative.15 In the meantime, Brazil is making concentrated investment efforts into 2G biofuels, with its National Development Bank (BNDES) having financed a number of relevant commercial undertakings.16 The 2G ethanol plants by 10

Leaders of Sustainable Biofuels (LSB), ‘The advanced biofuels sector concerned by the EU Climate and Energy Package’ (23 January 2014), available at www.sustainablebiofuelsleaders.com/ newsIE8.html; ePURE, ‘ePURE calls for binding renewable and GHG emissions reduction targets in transport’ (21 January 2014), available at www.epure.org/media-centre/press-releases 11 S. Afionis and L. C. Stringer, ‘The environment as a strategic priority in the European UnionBrazil partnership: is the EU behaving as a normative power or soft imperialist?’ International Environmental Agreements: Politics, Law and Economics 14 (2014), 47–64. 12 Interview, Brazilian Mission to the EU (Brussels, October 2013); Interview, Ministry of Agriculture (Brasilia, September 2014); Interview, Ministry of External Relations (Brasilia, September 2014). 13 Interview, Brazilian Embassy to the United Kingdom (London, December 2014); Interview, Brazilian Mission to the EU (Brussels, October 2013); Interview, University of São Paulo (São Paulo, August 2014); Interview, UNICA (Brussels, October 2013). 14 Interview, EU Delegation to Brazil (Brasilia, September 2014). 15 The latter is a Brazilian government scholarship programme, which aims to send in excess of 100,000 undergraduate and postgraduate Brazilian students to top universities around the world. 16 Interview, BNDES (Rio de Janeiro, August 2014).

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GranBio and Raizen in Alagoas and Piracicaba respectively have already commenced production,17 while BNDES approved in 2014 plans by Abengoa Bioenergy to implement a 2G plant in Pirassununga. The above schemes are projected to raise Brazil’s overall 2G production capacity to almost 200 million litres per year.18 In September 2015, Brazil’s pledge for the 2015 Paris climate summit included a goal for increasing the share of sustainable biofuels in the Brazilian energy mix to approximately 18 per cent by 2030, with 2G biofuels envisaged to play a core role.19 Brazil has also joined forces with the US, with the two countries having signed a Memorandum of Understanding (MoU) in March 2007 on biofuels cooperation.20 Apart from engaging in various R&D cooperation initiatives, focusing, for example, on maximising the efficiency of flex-fuel vehicle engines, the two partners have also set up trilateral cooperation pacts with seven countries in the Central American and Caribbean region (inter alia the Dominican Republic, Honduras and St Kitts & Nevis), plus two in Africa (Senegal and Guinea-Bissau).21 In addition, the US-Brazil bilateral MoU was extended in 2011 to include activities aimed at facilitating the commercial-scale development and deployment of aviation biofuels. Amyris, for instance, is a US-based company with production facilities in São Paulo that has actively invested in aviation biofuels from sugarcane, having also partnered to this effect with Brazilian airline GOL. In July 2014, a demonstration flight using farnesane was performed from Orlando, Florida, to São Paulo, Brazil,22 while in December 2014 the Brazilian fuels regulator ANP23 approved this renewable jet fuel, thus clearing the way for its commercialisation and uptake by the various airlines that have so far expressed interest, including Air France, KLM and Lufthansa.24 In January 2015, Boeing and Embraer inaugurated a joint sustainable aviation biofuels research centre in São Paulo in order to coordinate and co-fund joint projects in this sector.25 The above discussion highlights that the US public and private sectors have been far more active in Brazil compared to their EU counterparts. Biofuels 17

Telephone interview, GranBio (September 2014). J. Lane, ‘BNDES OKs $116M in financing for Abengoa cellulosic ethanol plant in Sao Paulo State’ (19 December 2014), available at www.biofuelsdigest.com/bdigest/2014/12/19/bndes-oks116m-in-financing-for-abengoa-cellulosic-ethanol-plant-in-sao-paulo-state 19 Federative Republic of Brazil, ‘Intended nationally determined contribution: towards achieving the objective of the United Nations Framework Convention On Climate Change’ (28 September 2015), available at www4.unfccc.int/submissions/INDC/Submission%20Pages/submissions.aspx 20 US Department of State, ‘Memorandum of Understanding between the U.S. and Brazil to advance cooperation on biofuels’ (9 March 2007), available at www.state.gov/p/wha/rls/158654.htm 21 Interview, Ministry of External Relations (Brasilia, September 2014). 22 Interview, United States Diplomatic Mission to Brazil (Brasilia, September 2014). 23 Agência Nacional do Petróleo, Gás Natural e Biocombustíveis. 24 Amyris, ‘Amyris renewable jet fuel receives regulatory approval in Brazil’ (16 December 2014), available at http://amyris.com/amyris-renewable-jet-fuel-receives-regulatory-approval-in-brazil 25 Boeing, ‘Boeing, Embraer open joint aviation biofuel research center in Brazil’ (14 January 2015), available at http://boeing.mediaroom.com/2015-01-14-Boeing-Embraer-Open-Joint-AviationBiofuel-Research-Center-in-Brazil 18

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are expected to remain a prominent feature of the post-2020 landscape, with a recent estimate valuing the global 2G biofuels market alone at $23.9 billion in 2020.26 The danger of the EU lagging behind the US and Brazil in the development of the 2G biofuels market requires urgent remedial action.27 As noted, the EU envisages 2G biofuels as being part of its future decarbonisation strategies. However, successful deployment of 2G technologies rests critically on the EU collaborating effectively with Brazil, given the latter’s ample biofuel feedstock availability and extensive R&D experience and capability, attributes that attracted US companies to cooperate with Brazil in the first place. A number of potential steps could facilitate successful collaboration with Brazil on the part of the EU. First, the various Directorates-General (DGs) of the EU should reach a common position on biofuels. Currently, while DG Research & Innovation (RTD) is working together with Brazil on various biofuel-related dossiers, others, like DG Energy (ENER) and DG Development and Cooperation (DEVCO), have adopted negative stances toward biofuels and are thus perceived as blocking collaborative projects in this policy area. Second, there is a need for better coordination of EU and member state initiatives on biofuels, as often the EU Delegation in Brasilia is not aware of member state-led projects in Brazil.28 Finally, the energy dialogue in the context of the EU-Brazil strategic partnership should enhance collaboration on 2G biofuels. While it would be unrealistic to expect that the two partners could steer away from contentious discussions over 1G trade barriers, the overall process could transform itself into a more forward-looking process by having a parallel strand on 2G collaboration. Apart from small-scale FP7 or Horizon 2020 scientific initiatives, there are currently no joint projects between the EU and Brazil on 1G or 2G biofuels whatsoever.29 Since the EU itself has already highlighted the potential of 2G biofuels for its post-2020 energy vision, the strategic partnership dialogue could launch a small number of joint 2G undertakings that would initially build trust among the two actors and later culminate in more comprehensive cooperative endeavours like, for example, the signing of a MoU. The latter course of action has proved beneficial for US commercial interests and there is no reason to assume that such an avenue would not be equally fruitful as far as EU interests are concerned.

26

J. Lane, ‘Cellulosic will overtake biodiesel by 2020, according to allied market research’ (22 December 2014), available at www.biofuelsdigest.com/bdigest/2014/12/22/cellulosic-willovertake-biodiesel-by-2020-according-to-allied-market-research 27 EU authorities are aware of the dangers involved in being placed at a competitive disadvantage, with Nils Torvalds, the European Parliament’s rapporteur on ILUC, stating in February 2015 that if Europe does not act swiftly, it ‘will be out of 2G biofuels for the foreseeable future’. See Vieuws, ‘“We need ILUC factors for biofuels” argues rapporteur Nils Torvalds’ (6 February 2015), available at www.vieuws.eu/environment/we-need-iluc-factors-for-biofuels-argues-rapporteur-nils-torvalds 28 Interview, EU Delegation to Brazil (Brasilia, September 2014). 29 Ibid.

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CONCLUSION

We shall not cease from exploration And the end of all our exploring Will be to arrive where we started And know the place for the first time T. S. Eliot, ‘Little Gidding’, Four Quartets We hope that this is the case and that you have enjoyed your journey through this Reader. One of its key aims, as stated at the beginning, is to explore new thinking and concepts in relation to EU and US energy law and policy. In the energy sector, there has been the growing realisation that traditional economic thinking, policy-making and regulation do not capture the effects of pollution effectively, are inefficient in the allocation of resources and in general have not supported innovation to any great extent – or certainly not to the extent required to address potentially catastrophic global challenges such as climate change caused by humankind’s use of fossil fuels. For many countries, however, the energy sector is now, at last, on the verge of reform. This is in part because of the failings of traditional economics and the need to build new energy infrastructure but also in part because of new technological development. The way we use energy is also changing, and as the world grows collectively wealthier there is the slowly developing realisation that too much fossil fuel derived pollution is impacting significantly upon climate change and our own health and security. But, notwithstanding the prospect of change, when we look back at energy law and policy across the world over the last four to five decades it has mostly been underdeveloped or has remained static, without significant improvements being made in the majority of countries. And incumbent companies in the energy sector – largely multi-national fossil fuel companies – still dominate the energy sector and the law and policy process, and they also continue to reap the most profits. Market revolution or even significant evolution has not as yet happened in the energy sector. In this context, this Reader is not about changing the profile of the energy sector itself but, in addition to engaging in constructive criticism of current provision,

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it does seek to facilitate thinking about faster and better ways to deliver our energy policy goals in the EU and US, now that we appear to be arriving at the threshold of potentially significant change and reform. One of the key themes underlying many of the chapters in the Reader is that slow delivery of energy policy goals encourages incumbents and in essence maintains their status. Other important themes that emerge are that the energy sector needs to meet more societal needs now, to integrate itself with new technological developments, to feed into other areas of society in terms of the provision of public services and to deliver a more balanced provision of the benefits and costs of the energy industry. There is a host of issues and problems in the energy sector, and it is hoped that the contributions in this Reader will inspire people to think about potential solutions to them, or at least provide a platform for further discussion. For there are many great chapters in this book. Rather than picking out our own favourites, we want to leave it to readers to make their own selection. That there is such a rich diversity of discussion and ideas is due to the contributors, and we would like to thank them all once again for their efforts. There is a mix of contributors, from senior researchers to those starting out in their careers, and we hope that bringing together different generations adds originality to new thinking and concepts on energy law and policy. A further hope is that the book inspires people to read the other works of those who have contributed and that it will encourage new collaborations involving scholars across the disciplines and around the world. Working together can help to build the intellectual critical mass needed to influence the future development of energy law and policy. By doing so, scholars can address the existential challenges posed by climate change and the importance of creating a low carbon society. We therefore conclude with Tennyson’s stirring words: Tho’ much is taken, much abides; and tho’ We are not now that strength which in old days Moved heaven and earth; that which we are, we are; One equal temper of heroic hearts, Made weak by time and fate, but strong in will To strive, to seek, to find, and not to yield. Alfred, Lord Tennyson, ‘Ulysses’

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INDEX

Aarhus Convention, 554–8 Abadie, L. M., 154 ACER Regulation (EU), 34, 37 acid mine drainage, 340–1 acid rain, 62 Act on Compensation for Nuclear Damage (Japan), 253 Act on Indemnity Agreements for Compensation of Nuclear Damage (Japan), 253 Action Plan on Nuclear Safety (IEAE), 248 activism and community energy projects, 562 and energy policy, 327 against fracking, 325–8, 330, 547–8, 554 against pipelines, 547 against smart metering, 456 against wind farm developments, 546, 554 see also public opposition adenosine triphosphate (ATP), 414–15 advanced boiling water reactors (ABWRs), 230, 231 advanced gas-cooled reactors (AGRs), 228, 229, 525–6 Advanced Research Projects Agency – Energy (US), 64–5, 640 advertising, 51, 172 affirmative principle of energy justice, 378–80 affordable sustainable energy technologies (ASETs), 391–4 Agency for Cooperation of Energy Regulators (ACER), 37, 38, 39, 352

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Agenda 21 (UN), 98, 587–8, 597 agriculture-related emissions, 607–8, 611, 615 air conditioning systems see HVAC systems aircraft, 93, 95–6, 121–4, 498–9, 607, 642, 677 alcohol-to-jet (ATJ) fuel, 95–6 Aldy, J. E., 463 Ali, O., 531 Allied Command Transformation Act (NATO), 481 Amending Protocols (2004), 246–7, 250 America see United States ancillary service markets, 431–2, 666–7 antitrust law see competition law AP1000 reactors, 225, 230, 231, 233 appliances see domestic appliances APR-1400 reactors, 523 Arab Spring, 532 Arbitration Institute, Stockholm Chamber of Commerce, 25, 484–5 Arctic energy infrastructural development, 385–8 and energy justice, 385–8 energy law, 370–3, 539–40 and energy policy, 537–41 environmental regulation, 370–3 environmental research, 541 exploration and exploitation rights, 386 impact of climate change, 538–9 indigenous people, 386–8, 537, 539 and international law, 371, 386, 539–40 oil and gas, 370–3, 385–8, 537–41

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DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

Arctic (Cont.) renewable energy, 387 resource ownership, 386 shipping routes, 387, 539 temperatures, 538 wind energy, 387 Arctic Climate Impact Assessment (ACIA), 538 Arctic Council, 388 Arctic Offshore Oil and Gas Guidelines, 371 Areva, 142, 217, 224, 233, 239 Argentina coal, 534 electricity, 534 energy policy, 533–6 energy prices, 533, 536 energy regulation, 533–4, 535, 536 expropriation of oil resources, 158 gas, 533, 534, 536 hydropower, 534 liquefied natural gas, 534 market regulation, 533–4 oil, 533, 534 peso crisis, 533, 535 renewable energy, 534, 535–6 shale gas and oil, 534, 535–6 wind energy, 535 armed forces see military Atherton, T., 462 Atomic Energy Act (Germany), 132 Atoms for Peace plan, 68–9 Austria, 161, 191, 239, 356 Australia, 13, 649, 654 automobiles see motor vehicles aviation see aircraft awareness campaigns see public information Babis, Andrej, 509 Baker, Philip, 516–17 balancing risk, 182 Baltic Energy Market Interconnection Plan (BEMIP), 356 bargaining power European Union, 106 Russia, 146 Barnett, J., 469 Barrasso, John, 480 Bator, R. J., 7 behavioural change and climate change mitigation, 583 and energy demand, 442–7, 458 Belarus, 191

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Belgium energy consumers, 114 energy law, 299–301 energy prices, 114 energy regulation, 114 green certificate system, 299–301 legal certainty, 299–301 renewable energy, 299–301 subsidies, 299–301 Bellona Report, 662 benchmarking, 43, 46–7 bioenergy see biomass and biofuels biofuels see biomass and biofuels biogas see biomass and biofuels biological energy cycle, 415–16 biomass and biofuels from animal waste, 615 for aviation, 677 Brazil, 154–5, 674–8 and energy policy, 674–8 ethanol fuel58–9, 154–5, 676–7 European Union, 552, 585, 642, 674–8 Finland, 141, 142–3 and forests, 142, 585 Germany, 130, 133 impact of climate variability, 190 incentive schemes, 585 military use of, 95–6, 641, 642 research and development, 70, 676, 677 second-generation biofuels, 674–8 Spain, 615 tax breaks, 676 technological innovation, 676 United Kingdom, 522, 598 United States, 58–9, 95–6, 282, 585, 641, 642, 675, 677–8 see also renewable energy ‘Blue Arctic’ programme, 370–3 Blyth, William, 21 Boarin, S., 257 body temperature, 406–7, 410–11 Boomhower, J., 463 Borden, J., 140 BP, 22, 633 branding, 51, 53 Brazil biomass and biofuels, 154–5, 674–8 carbon capture and storage, 654 carbon emissions, 593 ethanol fuel production, 154–5, 676–7 fossil fuel investment, 14 research and development, 677

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INDEX BRELL electricity system, 191 Britain see United Kingdom British Energy, 229 Brooks, Harvey, 8–9 Brundtland Commission, 98 Brussels Supplementary Convention (nuclear liability), 253 Bucharest Summit (NATO), 480 buildings energy efficiency, 70, 76, 89, 130–1, 133–4, 397–8, 400–4, 502–6, 512–13, 614, 616 and greenhouse gas emissions, 607–8 thermal insulation, 130, 133–4, 397; see also housing Bulgaria dependence on Russian gas, 145 gas transmission networks, 356–7 renewable energy incentive schemes, 126–7 Bureau of Land Management (US), 331–2 Burke, Tom, 601 Buzek, Jerzy, 147 Byers, Michael, 538 C40 Cities Climate Leadership Group, 589, 593 California, 66, 78, 421, 435, 547–8, 571–5, 625, 644, 645 California-Québec Agreement, 269 Cameron, David, 30 Canada Arctic energy exploration, 386 fossil fuel investment, 14 oil supplied to US, 57 renewable energy investor–state disputes, 28 shale gas and oil, 547 Cañete, Miguel Arias, 39 cap and trade systems see emissions trading capacity allocation mechanisms, 350–1 capacity markets, 176, 431, 434–5, 666 Cape Wind project, 546 carbon, unburnable, 12, 15, 21–2 carbon and greenhouse gas emissions agriculture sector, 607–8, 611, 615 Brazil, 593 and buildings, 607–8 capture and storage see carbon capture and storage China, 90–1, 589, 593 Clean Development Mechanism, 607, 652–3

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683 and climate change see climate change mitigation and domestic heating, 401–2 European Union, 581, 593–4, 596, 606–8 Finland, 141–2, 143–4 Germany, 132, 138, 265–7 impact of renewable energy, 265–7, 268–72 increases in levels of, 90–1, 171, 581–2 India, 90–1, 593 Kyoto Protocol, 88–9, 593, 596, 652–3 Malta, 496, 497–9 measurement of, 593–4 motor vehicle emission standards, 608 pricing of see carbon pricing Russia, 319–20 Spain, 611, 612–14, 616 taxation of see carbon taxes trading of see emissions trading transport sector, 607–8, 616 United States, 90–1, 157, 346, 442–3, 581, 589 US–China climate agreement, 88–91 virtual emission reductions, 272 volatility of allowances, 155 carbon capture and storage (CCS) Australia, 654 Brazil, 654 and carbon taxes, 649–50 China, 654 and climate change mitigation, 21, 62, 648 definition, 652 economic feasibility, 660–2 and energy policy, 157, 647–50, 653–4 and energy regulation, 157, 649, 651–7, 658–63 European Union, 649, 653–4, 655–6, 658–63 incentives, 655–6 and international collaboration, 654–5 Japan, 654 and liability, 656 and methane hydrate production, 633 Middle East, 654 South Korea, 654 storage availability, 659–60 subsidies, 650 technical feasibility, 662–3 transmission networks, 655 United Kingdom, 229, 650, 660–3 United States, 62, 157, 654

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DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

Carbon Capture and Storage Directive (EU), 653–4, 658–60 Carbon Plan (UK), 597–8 carbon pricing, 15, 61–2, 182, 266, 583, 611, 612–14, 655–6; see also carbon taxes; emissions trading carbon taxes, 78, 583, 612–14, 649–50; see also carbon pricing Carley, S., 280 Carney, Mark, 22 cars see motor vehicles Carter, Jimmy, 58 Center for Climate and Security (US), 95 Center for Naval Analyses (US), 94 Central Electricity Generating Board (UK), 163, 520, 525–6 Centrica, 238, 290 ČEZ, 508–10 Chamorro, J. M., 154 Chernobyl reactor disaster, 129, 132 Chevron, 325, 327–8 Chicago Convention, 122, 123 Chicago School (economics), 172 Chicago Summit Declaration (NATO), 480 China bilateral agreement with NREL, 72 carbon capture and storage, 654 carbon emissions, 90–1, 589, 593 climate agreement with the US, 88–91 climate change mitigation, 88–91, 589 coal production, 89 distributed energy resources, 567 emissions trading pilot scheme, 593 energy poverty, 393 fossil fuel investment, 14 nuclear energy, 90, 233, 234 water management, 99 China General Nuclear, 238 China National Nuclear Corporation, 238 chlorofluorocarbons (CFCs), 62 Christian Democrats (Czech Republic), 509 Christian Social Union (Germany), 132 Chu, Steven, 258 Cialdini, R. B., 7 cities and climate change mitigation, 589, 590 and energy policy delivery, 559–61 and national networks, 589 and international networks, 589, 590 Civil Liability for Nuclear Damage Act (India), 253–4

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Clean Air Act (US), 60, 62 Clean Development Mechanism (CDM), 607, 652–3 Clean Energy Alliance (US), 71 Clean Energy Manufacturing Initiative (US), 65 Clean Power Plan (US), 344, 346 Clean Water Act (US), 305 Climate and Energy Package (EU), 496, 499, 584, 606, 610 Climate Change Levy (UK), 598 climate change mitigation and behavioural change, 583 and carbon capture and storage, 21, 62, 648 and carbon emissions see carbon and greenhouse gas emissions China, 88–91, 589 city-level initiatives, 589, 590 Clean Development Mechanism, 607, 652–3 and cleaner energy generation, 51–2 Copenhagen Accord, 172 and distributed energy resources, 569 and emissions trading see emissions trading and energy conservation, 51–2 and energy efficiency, 51–2, 437–41, 583 and energy policy, 61–7, 136, 581–6, 587–91, 605–9, 610–18 and energy prices, 584 and energy security, 582–6 and environmental law, 164, 226, 592–5, 596–600 European Union: Covenant of Mayors initiative, 590; emissions trading, 155, 182, 265–7, 269, 270, 497–9, 593, 596, 606–8, 612, 616–18; and energy policy, 589–90, 605–9; goals and targets, 17–18, 21, 39, 182, 582, 596, 606; multi-level approaches, 589–90 Finland, 142 Germany, 129, 132, 265–7, 589 and global governance, 587–91 incentives, 65–6, 583 India, 589 Intergovernmental Panel on Climate Change, 442, 582, 590 Kyoto Protocol, 88–9, 593, 596, 652–3 and legacy reputation, 29–32 and legal scholarship, 601–4 Malta, 497, 499

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INDEX and marketing of cleaner energy options, 51–3 Marrakesh Accords, 88 motivations for, 29–32 multi-level approaches, 587–91 Paris Agreement, 594–5 and pollution reduction, 585 public information provision, 437–41 regional initiatives, 589 research and development, 583 and shale gas and oil, 585 Spain, 610–18 target limit of two degrees, 12, 15, 17, 21, 172, 581–2, 648 tax breaks, 65 and technological innovation, 62–7 UN Framework Convention, 15, 88, 371, 497, 593, 594–5, 596, 606 United Kingdom, 17–18, 21, 589, 596–600 United States: carbon taxes, 78; climate agreement with China, 88–91; emissions trading, 61–2, 66, 78, 269, 589; and energy policy, 61–7; incentive schemes, 65–6; and the military, 94–5; regional initiatives, 589; and technological innovation, 62–7 see also climate variability and change (CV&C) Climate Change Act (UK), 164, 226, 597 climate law see environmental law: and climate change mitigation climate variability and change (CV&C) and energy security, 184–90 impact on drylands, 631 impact on electricity generation and transmission, 184–90, 310 impact on the Arctic 538–9 see also climate change mitigation coal Argentina, 534 China, 89 decline in production, 344–8 demand for, 12 and employment, 345–6 Finland, 141 Germany, 130, 266 power plant construction, 345–6, 520–6 prices, 12–13 Spain, 612–13 taxes on, 77, 346 United Kingdom, 164, 166, 520–6

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685 United States, 77, 340–1, 344–8 see also fossil fuels Cohen, Andrew, 412 Colorado, 100, 331, 362, 571–5, 625, 628 combined-cycle gas turbines (CCGTs), 166, 522 combined heat and power (CHP) plants, 141, 142–3 Commercialisation Assistance Programme (US), 71 Community Energy England, 565 community energy projects collective purchasing and switching, 563 and distributed energy resources, 563 and energy conservation, 563 and energy demand, 177, 563 and energy generation, 563–4 Germany, 177 and renewable energy, 563–4 United Kingdom, 177, 562–5 Community Energy Scotland, 564–5 Community Energy Strategy (UK), 562 Community Energy Wales, 565 competition and consumer engagement, 111–15 and distributed energy resources procurement, 571–7 in energy markets, 34–5, 41, 43–4, 81, 111–15, 171–3, 493, 496, 510 and energy prices, 41, 171 and infrastructural investment, 171 and regulation, 41, 43, 112–15 and research and development spending, 171, 172 competition law and energy prices, 41 and energy regulation, 107–10 European Union, 34–5, 107–10, 119, 146–7, 149, 239, 642 and technological innovation, 642 United States, 107 competitive bidding, 292–7 Comprehensive Energy Policy Act (US), 58 compressed air energy storage (CAES), 665, 670–1, 672 Conference on Sustainable Development 2012 (UN), 394 conjunctive water management, 99–100 Connecting Europe Facility programme, 105, 355–7 construction risk, 216, 223–7, 232

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686

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

consumers see energy consumers contracts for difference (CfDs), 159–60, 162, 232, 237, 239, 516, 517–18, 650 Convention for the Protection of the Marine Environment of the NorthEast Atlantic (OSPAR), 371 Convention on International Trade in Endangered Species (CITES), 304 Convention on Supplementary Compensation (CSC), 243, 244, 247, 249–50, 254 Convention on the Law of the Sea (UN), 371, 386, 539–40 Convention to Combat Desertification (UN), 630–5 Copenhagen Accord, 172 Corporate Average Fuel Economy (CAFE) standards (US), 60 corporate reputation, 52 corporate social responsibility (CSR), 52 cosmopolitan justice, 378, 384 Council for Mutual Economic Assistance (COMECON), 482–3 Court of Justice of the European Union (CJEU), 26, 117, 119, 120, 121–4 Covenant of Mayors initiative (EU), 590 Cowboy Indian Alliance, 547 Cox, Brian, 412 critical stakeholder analysis, 9 Croatia, 355, 356 Cullen, J. M., 422 curtailment service providers (CSPs), 432, 435 Czech Republic energy law, 507–10 energy prices, 507 energy regulation, 507 gas transmission networks, 149, 356 market competition, 510 nuclear energy, 509 renewable energy, 24, 25, 26 unbundling, 507–10 data protection law, 105–6 Datta, S., 462–3 Davey, Ed, 367–8 Davis, L. W., 462, 463 de Jong, J., 319 Defense Advanced Research Agency (US), 640 Defense Logistics Agency (US), 641 deforestation, 585 Delmas, M. A., 280, 281

5053_Delivering Energy Law and Policy_Part 15.indd 686

Delors, Jacques, 147 demand response in capacity markets, 176, 431, 434–5 definition, 430 emergency/standby programmes, 430 and energy policy, 434–5 European Union, 435 price response bidding programmes, 430 price-responsive demand, 430 in wholesale markets, 429–36 United States, 431–5 Denmark Arctic energy exploration, 386 cooperative investment, 6 distributed energy resources, 567 energy efficiency, 462, 583 energy policy, 583 energy prices, 583 energy security, 583 energy source diversification, 583 energy storage, 671 wind energy, 6 see also Faroe Islands; Greenland Department of Communications, Energy and Natural Resources (Ireland), 204, 206 Department of Defense (US), 65, 91–6, 641; see also military Department of Energy (US), 64–5, 69, 99, 157, 330, 479, 665 Department of Energy and Climate Change (UK), 19, 237, 367–9, 450–1, 597–8 Department of Environment, Community and Local Government (Ireland), 556 Department of the Interior (US), 331–2 Department of Transportation (US), 360 deregulation electricity markets, 79, 80–1, 160, 163–4, 169–70 European Union, 160 nuclear energy markets, 216 United Kingdom, 163–4, 169–70, 229 United States, 79, 80–1, 160, 216 see also energy regulation desertification, 630–5 Deutsche Bahn case (Germany), 121–4 developing countries and the Clean Development Mechanism, 652 energy poverty, 392–3 least developed countries, 393 newly industrialised countries, 393

31/05/16 9:54 AM

INDEX renewable energy, 72, 276–7 research and development spending, 276 Dias, A. G., 155–6 Director of Operational Energy Plans and Programs (US), 95 distributed energy resources China, 567 and climate change mitigation, 569 and community energy projects, 563 definition, 567–8 and demand response, 433, 435 Denmark, 567 and energy policy, 450, 566–9, 570–7 European Union, 575–7 Germany, 567 and net metering, 568–9 procurement strategies, 570–7 and renewable energy, 563, 566–9, 570–7 and stranded costs, 568 and transmission networks, 566–9, 570–7 United Kingdom, 450, 563 United States, 435, 567, 570–5 distributional justice, 378, 382, 386–7 Dixit, A. K., 154 Djibouti, 528 domestic appliances energy efficiency, 89, 460–4, 614, 616 smart appliances, 175 domestic heating, 398–9, 400–4, 405–11, 560–1 Dong, C. G., 280 Donoghue, Helen, 206 Dowling, P., 186 drylands, 630–5 Dworkin, Michael, 378 Earth Summit (UN), 587–8, 597 Ecodesign Directive (EU), 425 economic downturn see financial crisis economic theory, 61–3, 172–3, 427–8 Ecotricity, 291 Edison, Thomas, 566 education see public information Effort-Sharing Decision (EU), 607–8 Egypt, 530 Einstein, Albert, 8 Eisenhower, Dwight D., 68 Elbadawi, Ibrahim, 531 Electric Consumers Protection Act (US), 305 electric vehicles, 76, 164–5, 197–201, 271

5053_Delivering Energy Law and Policy_Part 15.indd 687

687 Électricité de France (EDF), 217, 225, 226–7, 229, 230, 237, 238–9 electricity Argentina, 534 BRELL system, 191 consumer engagement, 111–15, 177 cross-border transmission, 191–6, 318–21 demand reduction incentives, 176–7 deregulation, 79, 80–1, 160, 163–4, 169–70 and distributed energy resources, 433, 435, 350, 563, 566–9, 570–7 dynamic pricing, 176, 433–4 electric vehicles, 76, 164–5, 197–201, 271 energy demand, 164–5, 174–8, 442–7, 523–4 and energy poverty, 393–4 energy security, 159–62 energy storage, 90, 198–201, 308, 310, 664–8, 669–73 European Union: consumer engagement, 111–15; cross-border transmission, 191–6, 318–21; deregulation, 160; distributed energy resources, 575–7; market competition, 34–5, 111–15; network cooperation, 37–8, 105–6, 191–6, 318–21; prices, 113; regulation, 36–7, 105–6; Sector Inquiry, 34–5, 109; subsidies, 160–2; susceptibility to climate variability, 184–90; Target Model, 127; transmission network investment incentives, 192–5; unbundling, 35–6, 490–1 Finland, 141–4 fossil fuel-generated see coal; fossil fuels; gas; oil France, 187, 191, 523–4 frequency regulation, 167, 200–1 generated by community energy projects, 563–4 Germany, 130, 191, 489–94, 567 grid stability, 166–7, 289–90 hourly pricing, 176 Hungary, 208–12 hydroelectric energy see hydropower Ireland, 167, 202–7 low-carbon generation, 163–70, 171–3 Malta, 496 market competition, 34–5, 81, 111–15, 171–3, 493, 496, 510 military usage, 93

31/05/16 9:54 AM

688

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

electricity (Cont.) net metering, 279, 281, 568–9 network cooperation, 37–8, 105–6, 191–6, 318–21 from nuclear sources see nuclear energy power plant construction, 520–6 prices, 81, 113, 165, 168, 175, 176, 202–3, 210–11, 433–4, 528 privatisation, 163, 169–70, 208 public opposition to pylons, 554 Qatar, 528 regulation, 36–7, 105–6, 208–12 from renewable sources see renewable energy Russia, 191–2, 318–21 sector reform, 171–3, 175–7 smart metering, 89, 106, 111, 168, 175, 176, 430, 433, 444, 452–6, 494, 599 Spain, 176, 187, 613 subsidies, 160–2 susceptibility to climate variability, 184–90 taxes on production, 613 time-of-use tariffs, 165 transmission network see transmission networks unbundling, 35–6, 80, 490–1, 507–10 United Kingdom: demand levels, 164–5; demand reduction incentives, 176–7; deregulation, 163–4, 169–70; distributed energy resources, 450, 563; generated by community energy projects, 563–4; generation policy, 163–70, 171–3, 520–6, 597; grid stability, 166–7; lowcarbon generation, 163–70, 171–3; power plant construction, 520–6; privatisation, 163, 169–70; sector reform, 171–3; smart metering, 452–6, 599; susceptibility to climate variability, 190 United States: deregulation, 79, 80–1, 160; distributed energy resources, 435, 567, 570–5; energy storage, 200–1, 665; market competition, 81; military usage, 93; net metering, 279, 281; prices, 81; provision to hinterlands, 57; transmission networks, 79–83; unbundling, 80 Electricity Acceleration Directive (EU), 489, 490 Electricity Act (Hungary), 209, 210 Electricity Act (UK), 163, 169

5053_Delivering Energy Law and Policy_Part 15.indd 688

Electricity (Supply) Act (UK), 163 Electricity Transit Directive (EU), 191 Eliot, T. S., 679 Emergency Petroleum Allocation Act (US), 58 emergency planning zones (EPZs), 259–60 emergency/standby programmes, 430 eminent domain authority, 359–64 emissions trading China, 593 and energy regulation, 42, 43 European Union, 155, 182, 265–7, 269, 270, 497–9, 593, 596, 606–8, 612, 616–18, 653, 655 and renewable energy promotion, 265–7, 268–72 Spain, 612, 616–18 United States, 61–2, 66, 78, 269, 589 Emissions Trading Directive (EU), 498 employment coal industry, 345–6 gas industry, 330 Germany, 140 Greece, 397 Middle East, 528 nuclear energy industry, 221 oil industry, 330 and shale gas production, 334 unemployment, 330, 345–6, 397 United States, 70, 278, 330, 334, 345–6 endangered species, 304, 305, 624–9 Endangered Species Act (US), 304, 305, 624–9 EneMalta Corporation, 496, 497 Energiewende (Germany), 129–34, 137–40, 240 Energy Act (UK), 232, 253, 598–9, 650 Energy Act (Norway), 314, 315 Energy and Water Research Integration Act (US), 97–8 Energy Charter Treaty (ECT), 24–6, 28, 476, 485–6 Energy Community, 472, 475, 511 Energy Company Obligation (UK), 599 energy conservation and behavioural change, 442–7, 458 and climate change mitigation, 51–2 and community energy projects, 563 by the consumer, 442–7 and energy policy, 425–6 European Union, 425–6 Germany, 129, 130–1, 137–8 incentives for, 51–2 marketing of, 51–2

31/05/16 9:54 AM

INDEX and pricing, 51 research on, 70 United Kingdom, 425–6 see also energy demand energy consumers and behavioural change, 442–7, 458 Belgium, 114 consumer engagement, 111–15, 177 energy conservation, 442–7 and energy efficient appliances, 460–4 and energy policy, 111–15 energy use feedback, 444–5 European Union, 111–15 information provided to, 7, 52, 112–13, 177, 434, 437–41, 444, 455, 458 Italy, 114 and regulation, 112–15, 176 research with, 443–5 switching between suppliers, 112–14 tax credits, 76, 462 United Kingdom, 112–13, 176–7 United States, 76 vulnerability of, 115, 396–9 see also energy demand; energy poverty energy consumption see energy conservation; energy consumers; energy demand; energy efficiency energy demand and behavioural change, 442–7, 458 and community energy projects, 177, 563 demand reduction incentives, 176–7 demand response, 176, 429–36 distinguished from consumption, 457–8 and domestic usage practices, 457–9 drivers of, 426–7 Egypt, 530 electricity, 164–5, 174–8, 442–7, 523–4 and energy efficiency, 177, 419–23, 425–7 and energy policy, 174–8, 271–2, 424–8, 434–5, 457–9, 527–32 European Union, 424–8, 457 and feed-in tariffs, 428 flexibility of, 175 France, 523–4 investment support measures, 177 Iran, 530 Kuwait, 530 measurement of, 421 Middle East, 527–32 military, 93, 639–41 Oman, 530

5053_Delivering Energy Law and Policy_Part 15.indd 689

689 peak reduction, 164–5, 175, 177, 310, 430, 432 and prices, 175, 176, 529–30 and rebound effects, 421–2, 426, 427, 458–9, 463–4 reduction of see energy conservation; energy efficiency and regulation, 176 and renewable energy, 271–2 research approaches, 457–9 Saudi Arabia, 530 and taxation, 427 United Arab Emirates, 530 United Kingdom, 164–5, 176–7, 425–6, 523–4 United States, 421, 431–5 see also energy consumers energy efficiency buildings, 70, 76, 89, 130–1, 133–4, 397–8, 400–4, 502–6, 512–13, 614, 616 and climate change mitigation, 51–2, 437–41, 583 Denmark, 462, 583 domestic appliances, 89, 460–4, 614, 616 and domestic heating, 400–4 and energy demand, 177, 419–23, 425–7 energy performance contracts, 503–6 and energy policy, 425–7, 448–51, 502–6 and energy poverty, 395, 397–8, 598–9 European Union, 425–7 and financial incentives, 460–4 fossil fuel generating plants, 89–90 France, 462 Germany, 129, 130–1, 133–4, 137–8 housing, 70, 76, 89, 130–1, 133–4, 397–8, 400–4, 598–9, 614, 616 HVAC systems, 89 Italy, 462 Japan, 583 Malta, 500 marketing of, 51–2 measurement of, 419–21 Mexico, 462 motor vehicles, 89, 614 Poland, 462 public information provision, 437–41 and rebound effects, 421–2, 426, 427, 458–9, 463–4 research on, 70 Romania, 502–6

31/05/16 9:54 AM

690

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

energy efficiency (Cont.) smart efficiency, 177 Spain, 463, 611, 614, 616 tax breaks, 599 and taxation, 462, 463 Ukraine, 512–13 United Kingdom, 400–4, 425–6, 448–51, 598–9 United States, 421, 462, 463 Energy Efficiency and Renewable Energy Office (US), 65, 70 Energy Efficiency Deployment Office (UK), 451 Energy Efficiency Directive (EU), 425, 435, 503 Energy Frontier Research Centers (US), 64 energy independence, 57, 160, 317–18, 334, 470 Energy Independence and Security Act (US), 58, 93, 95 Energy Industry Act (Germany), 489, 490–2, 493 Energy Information Administration (EIA), 303, 534–5 Energy Innovation Hubs (US), 64 Energy Innovation Portal (US), 71 energy intensity, 98, 419–20 energy justice affirmative principle, 378–80 Arctic case study, 385–8 decision-making checklist, 380, 384 defining, 378–9 and energy policy, 377–80, 381–4, 385–8, 582 and energy poverty, 383 prohibitive principle, 378–80 and sustainable development, 381–4 energy labelling, 425, 608, 614, 616 Energy Labelling Directive (EU), 425 energy law Arctic, 370–3, 539–40 and competition law, 107–10 Belgium, 299–301 Czech Republic, 507–10 European Union, 1–2, 33–9, 107–10, 119–20, 149, 318, 602–3 Germany, 133, 268–9, 293–7, 489–94 Greenland, 370–3 legal certainty for renewable energy projects, 298–301 and legal scholarship, 1–2, 601–4 Malta, 497–8 and marketing, 50–3 and nuclear liability, 242–50, 251–5

5053_Delivering Energy Law and Policy_Part 15.indd 690

Romania, 502–3 Ukraine, 511–14 United Kingdom, 365–9, 596–600 United States, 57, 58, 60, 84–7, 304–6 see also energy policy; energy regulation energy markets ancillary service markets, 431–2, 666–7 capacity markets, 176, 431, 434–5, 666 competition in, 34–5, 41, 43–4, 81, 111–15, 171–3, 493, 496, 510 and demand response, 176, 429–36 deregulation see deregulation and energy policy, 467–70 and energy security, 467–70 and energy storage, 664–8 failures of, 59–60 for flexibility, 176 and hydropower, 309 impact of free movement provisions, 116–20 and nuclear energy, 239–40 and price arbitrage, 665–7, 670 reform of, 171–3, 175–6 regulation of, 533–4 and renewable energy, 179–83, 292–7, 309 wholesale markets, 429–36 see also international energy trade Energy NATO proposal, 479 Energy OSCE proposal, 479 energy performance contracts, 503–6 Energy Performance of Buildings Directive (EU), 425, 512 energy policy and activism, 327 and the Arctic, 537–41 Argentina, 533–6 and biofuels, 674–8 and carbon capture and storage, 157, 647–50, 653–4 at city level, 559–61 and climate change mitigation, 61–7, 136, 581–6, 587–91, 605–9, 610–18 and community energy projects, 562–5 and the consumer, 111–15 decision-making principles, 5–11 and demand response, 434–5 Denmark, 583 and distributed energy resources, 566–9, 570–7 and economic theory, 61–4, 427–8 and energy conservation, 425–6 and energy demand, 174–8, 271–2, 424–8, 434–5, 457–9, 527–32

31/05/16 9:54 AM

INDEX and energy efficiency, 425–7, 448–51, 502–6 and energy justice, 377–80, 381–4, 385–8, 582 and energy markets, 467–70 and energy poverty, 395–9 and energy security, 467–71, 472–6, 582–6 and energy services, 10–11, 459 and energy storage, 664–8 European Union: and biofuels, 674–5; and carbon capture and storage, 653–4; and climate change mitigation, 589–90, 605–9; and the consumer, 111–15; and energy conservation, 425–6; and energy demand, 424–8; and energy efficiency, 425–7; and energy poverty, 395–9; and energy security, 468–9, 472–6; Energy 2020 strategy, 381–2, 472, 502, 606; and free movement provisions, 116–20; German Energiewende policy, 129–34, 137–40, 240; and international energy trade, 472–6; network cooperation, 37–8, 105–6, 191–6; proposed Energy Union, 103–6, 147–50, 240–1, 354–8, 473, 605; and public engagement, 551–3; pushpull frameworks, 283–7; regulation, 36–7, 105–6, 490; and relations with Russia, 145–50, 317–21, 477–9, 482–6; and renewable energy, 283–7, 551–2; resource pooling, 104–5; and sustainable development, 135–40; 2030 Energy and Climate Policy Framework, 606; and UK nuclear energy, 161–2, 236–41; unbundling, 35–6, 490–1, 508 Finland, 141–4 Germany, 129–34, 137–40 global see global governance; international law Greece, 398 and international energy trade, 472–6 Ireland, 202–7, 554–8 Japan, 583 Malta, 495–501 and marketing, 50–3 Middle East, 527–32 and the military, 92–6, 639–42 and network security, 47–8 and nuclear energy, 219–22, 229, 236–41

5053_Delivering Energy Law and Policy_Part 15.indd 691

691 policy acceleration, 135–6 policy mixes, 450–1 and public consultation, 8–9, 326–7, 387, 549–53 and public engagement, 549–53, 554–8 push–pull frameworks, 274–5, 283–7 and renewable energy, 268–72, 283–7, 469, 515–19, 551–2, 597–8 and risk evaluation, 8, 153–8 role of local authorities, 559–61, 599 Romania, 502–6 Russia, 477–8 and self-reflection, 9–10 Spain, 610–18 and state sovereignty, 118–19, 468 and sustainable development, 97–100, 135–40, 381–4, 468 and taxation, 73–8 and technological agnosticism, 10–11 and technological innovation, 62–7, 639–42 Ukraine, 511–14 and uncertainty, 8, 153–8 United Kingdom: at city level, 559–61; and climate change mitigation, 596–600; and community energy projects, 562–5; D3 programme, 450; and devolution, 597; and electricity generation, 163–70, 171–3, 520–6, 597; and electricity market reform, 171–3; and energy demand, 425–6; and energy efficiency, 448–51; and energy security, 470–1; and nuclear energy, 219–22, 229, 236–41; and renewable energy, 515–19, 597–8; role of local authorities, 559–61, 599; and privatisation, 169–70; and smart metering, 452–6, 599 United States: and carbon capture and storage, 654; and climate change mitigation, 61–7; and demand response, 434–5; historical overview, 57–60; and the military, 92–6, 639–42; and national scientific laboratories, 68–72; and neoclassical economics, 61–4; at state level, 278–82; and sustainable development, 97–100; and taxation, 73–8; and technological innovation, 62–7, 639–42; and water management, 97–100 and water management, 97–100 Energy Policy Act (US), 58, 76, 641 Energy Policy and Conservation Act (US), 58, 60

31/05/16 9:54 AM

692

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

energy poverty and affordable sustainable energy technologies, 391–4 and austerity measures, 398–9 China, 393 developing countries, 392–3 and electricity, 393–4 and energy efficiency, 395, 598–9 and energy justice, 382 and energy policy, 395–9 and energy prices, 395, 398 European Union, 395–9 EVALUATE project, 397 Greece, 396, 397–9 health impacts, 405–11 and housing, 396, 397–9, 400–4, 405–11, 598–9 and income levels, 395 India, 393 Ireland, 395 least developed countries, 393 newly industrialised countries, 393 support mechanisms, 397, 398 and sustainable development, 391–4 United Kingdom, 395, 405–11, 598–9 energy prices Argentina, 533, 536 Belgium, 114 and climate change mitigation, 584 coal, 12–13 and competition, 41, 171 Czech Republic, 507 Denmark, 583 dynamic pricing, 176, 433–4 electricity, 81, 113, 165, 168, 175, 176, 202–3, 210–11, 433–4, 528 and energy conservation, 51–2 and energy demand, 175, 176, 529–30 and energy poverty, 395, 398 European Union, 113, 351–2 gas, 81, 113, 146–7, 211, 351–2, 533 hourly pricing, 176 Hungary, 210–11 Ireland, 202–3 Israel, 528 Italy, 114 Japan, 583 low elasticity of, 427 Malta, 496 Middle East, 528–30 oil, 12, 57, 58, 156, 273–7, 329–30, 470, 471, 533, 597 petrol, 528–9 and political participation, 528–9

5053_Delivering Energy Law and Policy_Part 15.indd 692

Qatar, 528 and regulation, 41 Russia, 146–7 Spain, 176, 617 state subsidising of, 528 time-of-use tariffs, 165, 176 transactive pricing, 175 Tunisia, 528 Turkey, 528 United Kingdom, 113, 168 United States, 81, 433–4, 583 energy regulation Arctic, 370–3 Argentina, 533–4, 535, 536 arm’s length, 41–2 Belgium, 114 and benchmarking, 43 and carbon capture and storage, 157, 649, 651–7, 658–63 and competition, 41, 43, 112–15 and competition law, 107–10 and consumer engagement, 112–15, 176 Czech Republic, 507 and energy demand, 176 electricity, 36–7, 105–6, 208–12 European Union, 36–7, 105–6, 107–10, 112–15, 490, 649, 658–63 fracking, 329–32, 334, 336–7, 341 gas, 36–7, 105–6 gathering line regulation, 359–64 Germany, 490–3 Greenland, 370–3 Hungary, 208–12 and incentives, 40, 42–3, 46–7 Italy, 114 Malta, 497 and network security, 46–7 nuclear energy, 157–8, 173, 231, 259–60 oil, 365–9, 370–3 and pricing, 41 safety regulation, 173, 231 shale gas and oil, 329–32, 334, 336–7, 341 small modular reactors, 259–60 transmission network regulation, 46–7, 105–6, 349–53, 359–64, 491–3 Ukraine, 512 and uncertainty, 153–8 United Kingdom, 112–13, 176, 365–9, 660–3 United States, 43, 46, 157–8, 329–32, 334, 336–7, 341, 359–64

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INDEX ways to improve, 40–4 see also deregulation; energy law Energy Saving Trust (UK), 563 energy security and climate change mitigation, 582–6 and climate variability, 184–90 Denmark, 583 electricity, 159–62 and energy independence, 57, 160, 317–18, 334, 470 and energy markets, 467–70 and energy policy, 467–71, 472–6, 582–6 and energy source diversification, 160, 317, 475, 478–9, 584 European Union, 104–5, 146–8, 160–2, 317, 349, 468–9, 472–6, 477–81, 482–6 Finland, 142 gas, 104, 105, 146–8, 317, 349, 477–8, 482–6 and international energy trade, 472–6 and international law, 482–6 Japan, 583 and the military, 93–4 and NATO, 477–81 and renewable energy, 160–1, 469 and sustainable development, 468 transmission network security, 45–9 and the Ukraine, 104, 147, 317, 349, 477–8, 482–6 United Kingdom, 470–1 United States, 57, 93–4, 334, 469–70 Energy Security Act (US), 58 Energy Security Centre of Excellence (NATO), 480–1 Energy Security Section (NATO), 480 energy services and energy justice, 379 and energy policy, 10–11, 459 measurement of, 420 Energy Services Directive (EU), 453 energy source diversification Denmark, 583 and energy security, 160, 317, 475, 478–9, 584 European Union, 126, 130, 148, 317, 475, 478–9 Japan, 583 Malta, 496 Middle East, 530 United States, 58–9, 96 energy storage

5053_Delivering Energy Law and Policy_Part 15.indd 693

693 compressed air energy storage, 665, 670–1, 672 Denmark, 671 electricity, 90, 198–201, 308, 310, 664–8, 669–73 and energy markets, 664–8 and energy policy, 664–8 Finland, 666–7 Germany, 670–1 and hydropower, 308, 310, 665, 670–1 incentives, 671–3 Netherlands, 671 and price arbitrage, 665–7, 670 and renewable energy, 90, 198–201, 310, 664–8, 669–73 research and development, 667, 671 and risk, 671–3 technological innovation, 671 United Kingdom, 667 United States, 200–1, 665, 667 and vehicle-to-grid electric cars, 197–201 Energy Systems Integration Facility (US), 71 energy technology see technological innovation energy trilemma, 171, 559 Energy 2020 strategy (EU), 381–2, 472, 502, 606 Energy Union (EU, proposed), 103–6, 147–50, 240–1, 354–8, 473, 605 England see United Kingdom enhanced oil recovery (EOR), 648, 654 Enron, 82 entropy, 415 Environment Agency (UK), 598 Environment and Development Planning Act (Malta), 498 Environmental Audit Committee (UK), 20, 21 environmental impact assessments, 555, 557, 663 environmental issues see acid rain; carbon and greenhouse gas emissions; climate change mitigation; deforestation; desertification; environmental law; ozone depletion; pollution; sustainable development; water contamination; wildlife protection environmental law and the Arctic, 370–3 and climate change mitigation, 164, 226, 592–5, 596–600

31/05/16 9:54 AM

694

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

environmental law (Cont.) European Union, 554–8, 602–3 Greenland, 370–3 and hydropower, 304–5 Ireland, 554–8 and the law of nuisance, 619–23 and legal scholarship, 601–4 and pollution, 60, 62 and public opposition to energy projects, 554–8 and renewable energy, 597–8 United Kingdom, 164, 226, 596–600, 619–23 United States, 60, 62, 304–5 Environmental Protection Act (UK), 620, 621 Environmental Protection Agency (Ireland), 558 Environmental Protection Agency (US), 331, 346–7 E.ON, 108, 110, 230, 238, 240 EPSA case (US), 434–5 Estonia, 145, 191 ethanol fuel, 58–9, 154–5, 676–7; see also biomass and biofuels EU Emission Trading Scheme (EU ETS), 155, 182, 265–7, 269, 270, 497–9, 593, 596, 606–8, 612, 616–18, 653, 655 Euratom Treaty, 104, 116, 247 European Agency for the Cooperation of Energy Regulators, 112 European Atomic Energy Community see Euratom Treaty European Bank for Reconstruction and Development (EBRD), 274 European Coal and Steel Community, 104, 116 European Commission see European Union (EU) European Competition Commission, 149, 239 European Convention on Human Rights (ECHR), 127 European Council, 103, 195, 552, 606 European Economic Community (EEC) see European Union (EU) European Energy Programme for Recovery (EEPR), 193, 194, 653 European Innovation Union, 472 European Network for Transmission System Operators (ENTSO), 38, 351 European Parliament, 147, 512, 552, 606

5053_Delivering Energy Law and Policy_Part 15.indd 694

European pressurised water reactors (EPRs), 142, 224, 225, 226, 232, 239, 520, 523, 526 European Transmission System Operators (ETSO), 38 European Union (EU) Arctic energy exploration, 385 bargaining power, 106 biomass and biofuels, 552, 585, 642, 674–8 carbon capture and storage, 649, 653–4, 655–6, 658–63 carbon emissions, 581, 593–4, 596, 606–8 climate change mitigation: Covenant of Mayors initiative, 590; emissions trading, 155, 182, 265–7, 269, 270, 497–9, 593, 596, 606–8, 612, 616–18; and energy policy, 589–90, 605–9; goals and targets, 17–18, 21, 39, 182, 582, 596, 606; multi-level approaches, 589–90 competition law, 34–5, 107–10, 119, 146–7, 149, 239, 642 Connecting Europe Facility programme, 105, 355–7 data protection law, 105–6 demand response, 435 deregulation, 160 Directives and Regulations: ACER Regulation, 34, 37; Carbon Capture and Storage Directive, 653–4, 658–60; Climate and Energy Package, 496, 499, 584, 606, 610; Ecodesign Directive, 425; Electricity Acceleration Directive, 489, 490; Electricity Transit Directive, 191; Emissions Trading Directive, 498; Energy Efficiency Directive, 425, 435, 503; Energy Labelling Directive, 425; Energy Performance of Buildings Directive, 425, 512; Energy Services Directive, 453; First Energy Package, 119, 299; Gas Acceleration Directive, 489, 490; Gas Security Regulation, 105; Habitats Directive, 555, 557; Industrial Emissions Directive, 164; New Electricity Regulation, 34, 37; New Gas Regulation, 34, 37; Regulation on Wholesale Energy Market Integrity and Transparency (REMIT), 35; Renewable Energy Directive, 24, 203, 318, 320, 675, 676; Second Electricity Directive,

31/05/16 9:54 AM

INDEX 209; Second Energy Package, 119; Third Electricity Directive, 34, 35, 36, 208–9, 396; Third Energy Package, 34–9, 119, 171, 172, 208–9, 349–50, 395, 508, 509–10, 570, 575; Third Gas Directive, 34, 35, 36, 396 distributed energy resources, 575–7 electricity: consumer engagement, 111–15; cross-border transmission, 191–6, 318–21; deregulation, 160; distributed energy resources, 575–7; market competition, 34–5, 111–15; network cooperation, 37–8, 105–6, 191–6, 318–21; prices, 113; regulation, 36–7, 105–6; Sector Inquiry, 34–5, 109; subsidies, 160–2; susceptibility to climate variability, 184–90; Target Model, 127; transmission network investment incentives, 192–5; unbundling, 35–6, 490–1 emissions trading, 155, 182, 265–7, 269, 270, 497–9, 593, 596, 606–8, 612, 616–18, 653, 655 energy conservation, 425–6 energy consumers, 111–15 energy demand, 424–8, 457 energy efficiency, 425–7 energy law, 1–2, 33–9, 107–10, 119–20, 149, 318, 602–3 energy policy: and biofuels, 674–8; and carbon capture and storage, 653–4; and climate change mitigation, 589–90, 605–9; and the consumer, 111–15; and energy conservation, 425–6; and energy demand, 424–8; and energy efficiency, 425–7; and energy poverty, 395–9; and energy security, 468–9, 472–6; Energy 2020 strategy, 381–2, 472, 502, 606; and free movement provisions, 116–20; and international energy trade, 472–6; network cooperation, 37–8, 105–6, 191–6; proposed Energy Union, 103–6, 147–50, 240–1, 354–8, 473, 605; and public engagement, 551–3; push–pull frameworks, 283–7; regulation, 36–7, 105–6, 490; and relations with Russia, 145–50, 317–21, 477–9, 482–6; and renewable energy, 283–7, 551–2; resource pooling, 104–5; and sustainable development, 135–40; 2030 Energy and Climate Policy Framework, 606; and UK nuclear

5053_Delivering Energy Law and Policy_Part 15.indd 695

695 energy, 161–2, 236–41; unbundling, 35–6, 490–1 energy poverty, 395–9 energy prices, 113, 351–2 energy regulation, 36–7, 105–6, 107–10, 112–15, 490, 649, 658–63 energy security, 104–5, 146–8, 160–2, 317, 349, 468–9, 472–6, 477–81, 482–6 energy source diversification, 126, 130, 148, 317, 475, 478–9 Energy 2020 strategy, 381–2, 472, 502, 606 Energy Union proposal, 103–6, 147–50, 240–1, 354–8, 473, 605 environmental law, 554–8, 602–3 excise duties, 121–4 feed-in tariffs, 24, 126–8, 180, 182–3, 285, 309 fracking, 325–8 free movement law, 116–20 gas: bargaining power, 106; capacity allocation mechanisms, 350–1; congestion management procedures, 352; consumer engagement, 111–15; cross-border transmission, 149, 349–53, 354–8; energy security, 104, 105, 146–8, 317, 349, 477–8, 482–6; imports from Russia, 145–7, 160, 354, 477–9, 482–6; liquefied natural gas, 145–6, 149, 354–5, 356, 479–80; market competition, 34–5, 111–15; network codes, 350–3; network cooperation, 37–8, 105–6, 149, 349–53, 354–8; prices, 113, 351–2; regulation, 36–7, 105–6; reverse gas flow, 149; Sector Inquiry, 34–5, 109; South Stream pipeline, 149; transmissions networks, 35, 145–6, 149, 349–53, 354–8, 478, 479; and the Ukraine, 104, 147, 317, 349, 477–8, 482–6; unbundling, 35–6, 490–1 hydropower, 310–11, 670 Internal Energy Market, 475 and international energy trade, 472–6 liquefied natural gas, 145–6, 149, 354–5, 356, 479–80 network codes, 350–3 nuclear energy: Euratom Treaty, 104, 116, 247; market integration, 239–40; nuclear liability law, 247–8, 254; reduction of, 126, 129–30, 132, 137–8, 240; susceptibility to climate variability, 186–7

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696

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

European Union (EU) (Cont.) oil excise duties, 121–4 Projects of Common Interest, 350, 355–6 relations with Russia, 145–50, 317–21, 477–9, 482–6 renewable energy: biomass and biofuels, 552, 585, 642, 674–8; cooperation with Russia, 317–21; and energy policy, 283–7, 551–2; energy security, 160–1; expansion of, 129–30, 132–3, 137–8, 240, 265–7; feed-in tariffs, 24, 126–8, 180, 182–3, 285, 309; hydropower, 310–11, 670; incentive schemes, 24, 125–8, 179–82, 585; investor–state disputes, 23–8; market circumvention, 182–3; market integration, 179–82; Renewable Energy Directive, 24, 203, 318, 320, 675, 676; research and development, 284–7; solar energy, 283–7; subsidies, 293–4; susceptibility to climate variability, 186, 187–90; targets, 24, 202–3, 596; wind energy, 283–7 research and development, 284–7, 642, 676 Sector Inquiry, 34–5, 109 shale gas and oil, 325–8 solar energy, 283–7 subsidies, 160–2, 293–4 susceptibility to climate variability, 184–90 sustainable development, 135–40 technological innovation, 642, 676 tax breaks, 676 taxation, 121–4 transmission networks, 35–8, 105–6, 145–6, 149, 191–6, 349–53, 354–8, 478, 479 Ukrainian integration, 511–14 water rights, 311 wind energy, 283–7 see also individual countries Eurostat Guidance Note on energy performance contracts, 504–5 EVALUATE project, 397 excise duties see taxation exclusive liability, 252, 254 expropriation risk, 158 Fallon, Michael, 20 Fallow Initiative (UK), 366–7, 369 Faroe Islands, 386; see also Denmark Federal Cartel Office (Germany), 490

5053_Delivering Energy Law and Policy_Part 15.indd 696

Federal Energy Regulatory Commission (US), 46, 79, 80, 304–6, 311, 360, 430, 434–5, 479 Federal Fund for the Management of Real Estate (Germany), 296 Federal Ministry of Economic Affairs and Energy (Germany), 295 Federal Network Agency (Germany), 295, 492–3 Federal Power Act (US), 80, 304 feed-in tariffs and carbon emissions, 268–72 and energy demand reduction, 428 European Union, 24, 126–8, 180, 182–3, 285, 309 Finland, 143 Germany, 133, 268–9, 285, 309 levy-funded, 271 and regulation, 41 Spain, 615, 616–18 United Kingdom, 516, 517–18, 598 United States, 268 FFAV ordinance (Germany), 295–7 field allowances, 17–22 financial crisis, 24, 125, 126–7, 172, 232, 276, 396, 397–9, 606, 616, 617–18 Finger, D., 188 Finland Arctic energy exploration, 386 biomass and biofuels, 141, 142–3 carbon emissions, 141–2, 143–4 climate change mitigation, 142 coal, 141 combined heat and power plants, 141, 142–3 electricity, 141–4, 192, 318 energy cooperation with Russia, 192, 318, 320 energy policy, 141–4 energy security, 142 energy storage, 666–7 feed-in tariffs, 143 gas, 141, 145, 356 hydropower, 141 imported energy, 141 nuclear energy, 141, 142, 215, 217, 221, 224 Olkiluoto power station, 142, 217, 221, 224, 226 peat, 141 renewable energy, 141–3 transmission networks, 192, 318, 356 waste management, 143–4 wind energy, 141, 143

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INDEX Finnmark Kraft AS, 387 First Energy Package (EU), 119, 299 Fish and Wildlife Service (US), 626–9 fish ladders, 304, 309 Fitzgerald, John, 205–6 Flamanville power station (France), 217, 225, 226 flex-fuelled motor vehicles, 154–5, 677 Florida, 644 fluorinated industrial gases, 608 food chain, 415–16 Forest Carbon Partnership Facility (World Bank), 593 forests, 142, 585 fossil fuels field allowances, 17–22 generating plant efficiency, 89–90 influence of lobby for, 172, 583–4 investment in, 14 marketing of, 172 research and development spending, 276 structural role in Middle East, 527–8, 530–2 subsidies, 12–16, 583, 612–13 tax breaks, 14, 17–22, 75 see also coal; gas; lignite; oil; peat; shale gas and oil fracking activism against, 325–8, 330, 547–8, 554 European Union, 325–8 France, 326, 327 Ireland, 554 legacy effects of, 338–43 and methane emissions, 331 Poland, 325, 327–8 public opposition to, 325–8, 330, 547–8, 554 regulation, 329–32, 334, 336–7, 341 United States, 57–8, 326–8, 329–32, 333–7, 338–43, 547–8 and water contamination, 332, 333–7 see also shale gas and oil Framework Convention on Climate Change (UN), 15, 88, 371, 497, 593, 594–5, 596, 606 Framework Programmes for Research and Technological Development (EU), 676 France electricity, 187, 191, 523–4 energy demand, 523–4 energy efficient appliances, 462

5053_Delivering Energy Law and Policy_Part 15.indd 697

697 Flamanville power station, 217, 225, 226 fracking, 326, 327 nuclear energy, 187, 215, 217, 220, 221, 225, 233, 234, 523 shale gas and oil, 326, 327 transmission networks, 191 free energy, 415 free movement law (EU), 116–20 frequency regulation, 167, 200–1 fuel cells, 59, 70 fuel poverty see energy poverty Fukushima reactor disaster, 129, 221, 230, 242, 253 G8 countries, 17–18 G20 countries, 13–14, 249 Galarraga, I., 463 gas Arctic, 370–3, 385–8, 537–41 Argentina, 533, 534, 536 capacity allocation mechanisms, 350–1 congestion management procedures, 352 consumer engagement, 111–15 cross-border transmission, 191–6, 349–53, 354–8 Egypt, 530 and employment, 330 energy security, 104, 105, 146–8, 317, 349, 477–8, 482–6 European Union: bargaining power, 106; capacity allocation mechanisms, 350–1; congestion management procedures, 352; and consumer engagement, 111–15; cross-border transmission, 191–6, 349–53, 354–8; energy security, 104, 105, 146–8, 317, 349, 477–8, 482–6; imports from Russia, 145–7, 160, 354, 477–9, 482–6; liquefied natural gas, 145–6, 149, 354–5, 356, 479–80; market competition, 34–5, 111–15; network codes, 350–3; network cooperation, 37–8, 105–6, 149, 349–53, 354–8; prices, 113, 351–2; regulation, 36–7, 105–6; reverse gas flow, 149; Sector Inquiry, 34–5, 109; South Stream pipeline, 149; transmissions networks, 35, 145–6, 149, 349–53, 354–8, 478, 479; and the Ukraine, 104, 147, 317, 349, 477–8, 482–6; unbundling, 35–6, 490–1

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698

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

gas (Cont.) field allowances, 17–22 Finland, 141, 145 gathering lines, 359–64 Germany, 130, 266, 489–93 Iran, 530 Kuwait, 530 liquefied natural gas, 145–6, 149, 354–5, 356, 479–80, 534 Malta, 496 market competition, 34–5, 111–15 methane content, 633 Middle East, 527–32 military usage, 93 Nabucco project, 479 nationalisation of, 529 network codes, 350–3 network cooperation, 37–8, 105–6, 149, 349–53, 354–8 NordStream project, 479 North Sea gas, 17–22, 229 Oman, 530 power-plant construction, 520–6 prices, 81, 113, 146–7, 211, 351–2, 533 regulation, 36–7, 105–6 reverse gas flow, 149 Russia, 145–7, 160, 354, 477–9, 482–6 from shale see shale gas and oil South Stream pipeline, 149 structural role in Middle East, 527–8, 530–2 tax breaks, 75 transmissions networks, 35, 145–6, 149, 349–53, 354–8, 478, 479, 484 and the Ukraine, 104, 147, 317, 349, 477–8, 482–6 unbundling, 35–6, 490–1 United Arab Emirates, 530 United Kingdom, 17–22, 164, 166, 229, 520–6, 597 United States: domestic production, 57, 340, 347; gathering lines, 359–64; liquefied natural gas, 479–80; military usage, 93; prices, 81; tax breaks, 75 see also fossil fuels Gas Acceleration Directive (EU), 489, 490 Gas Coordination Group (EU), 105 Gas Drilling Awareness Coalition, 326, 328 Gas Security Regulation (EU), 105 Gas Transmission Europe (GTE), 37 gasoline see petrol

5053_Delivering Energy Law and Policy_Part 15.indd 698

Gathering Line Land Acquisition Act (US), 363, 364 gathering lines, 359–64 Gazprom, 14, 110, 145–7, 149, 160, 478, 482–5 GDF Suez, 110, 230 General Agreement on Tariffs and Trade (GATT), 474–5, 634 Generation III+ nuclear reactors, 220–1, 222 geothermal energy, 70; see also renewable energy Germany biomass and biofuels, 130, 133 carbon emissions, 132, 138, 265–7 climate change mitigation, 129, 132, 265–7, 589 coal, 130, 266 community energy projects, 177 Deutsche Bahn case, 121–4 distributed energy resources, 567 electricity, 130, 191, 489–94, 567 employment, 140 Energiewende, 129–34, 137–40, 240 energy conservation, 129, 130–1, 137–8 energy consumption levels, 130 energy efficiency, 129, 130–1, 133–4, 137–8 energy law, 133, 268–9, 293–7, 489–94 energy policy, 129–34, 137–40 energy regulation, 490–3 energy storage, 670–1 excise duty exemption for aviation fuel, 121–4 feed-in tariffs, 133, 268–9, 285, 309 gas, 130, 266, 489–93 housing, 130–1 hydropower, 130 imported energy, 130 market competition, 493 network tariffs, 491–3 nuclear energy, 129–30, 132, 137–8, 230, 234, 240 oil, 130 planning regulations, 295–6 privatisation, 489 proposes Energy OSCE concept, 479 renewable energy: biomass and biofuels, 130, 133; competitive bidding, 292–7; expansion of, 129–30, 132–3, 137–8, 240, 265–7; feed-in tariffs, 133, 268–9, 285, 309; hydropower, 130; incentive schemes, 24; investor–state disputes,

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INDEX 24, 25; and planning regulations, 295–6; solar energy, 130, 133, 285, 292–7; subsidies, 265–7; transmission network integration, 289–90; wind energy, 130, 132, 289–90 smart grids, 494 smart metering, 494 solar energy, 130, 133, 285, 292–7 Spain, 613 subsidies, 265–7 sustainable development, 137–40 taxes on consumption, 613 third-party network access, 491 transmission networks, 191, 289–90, 491–4 unbundling, 490–1 wind energy, 130, 132, 289–90 global climate models (GCMs), 186, 538 global governance, and climate change mitigation, 587–91 global warming see climate change mitigation; climate variability and change Global Wind Energy Council, 535 Goldthau, A., 469 González-Eguino, M., 613 Gordon, L., 407 Görlach, B., 611 Government Pension Fund Global (Norway), 342 Great Green Fleet project, 96 greater sage grouse, 624–7 Greece energy policy, 398 energy poverty, 396, 397–9 gas transmission networks, 356–7 housing, 397–9 impact of financial crisis, 396, 397–9 liquefied natural gas, 354, 356 renewable energy incentive schemes, 126–7 unemployment, 397 green certificates, 299–301 Green Deal (UK), 598–9 Green Energy Fund (UK), 598 green paradox, 136–7, 139 Green Party (Germany), 132 greenhouse gas (GHG) emissions see carbon and greenhouse gas emissions Greenland, 370–3, 386; see also Denmark Greenland Institute of Natural Resources, 373 Greenpeace, 239

5053_Delivering Energy Law and Policy_Part 15.indd 699

699 grid stability, electricity networks, 166–7, 289–90 Gulati, S., 462–3 Habitats Directive (EU), 555, 557 Handke, S., 319 Hawaii, 644, 645 Hayns, M. R., 257 health impacts, cold homes, 405–11 heart conditions, 405, 408 heat networks, 560–1 heat pumps, 403 heating see combined heat and power (CHP) plants; domestic heating; HVAC systems; water heating HeaTmaPPE model, 409–10, 411 hedging instruments, 161 Helsinki Accords, 479 Hinkley Point C power station (UK), 161–2, 166, 226, 228, 231–2, 237–9 Hitachi, 230 Home Energy Conservation Act (UK), 598 Horizon Nuclear Power, 230 horizontal drilling, 329, 333 Houde, S., 463 hourly pricing, 176 housing domestic heating, 398–9, 400–4, 405–11, 560–1 energy efficiency, 70, 76, 89, 130–1, 133–4, 397–8, 400–4, 598–9, 614, 616 and energy poverty, 396, 397–9, 400–4, 405–11, 598–9 future-proofing, 400–4 Germany, 130–1 Greece, 397–9 health impacts of cold homes, 405–11 refurbishment subsidies, 614, 616 Spain, 614, 616 and sustainable development, 89, 401 thermal insulation, 130, 133–4, 397 United Kingdom, 400–4, 405–11, 598–9 water heating, 401–3 see also buildings Hungarian Energy and Public Utility Regulatory Authority (HEA), 209–10, 211 Hungary, 149, 208–12, 356, 357 Hutson, Michael, 326 HVAC systems, 89 hybrid vehicles, 76, 164, 197–201 hydraulic fracturing see fracking

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700

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

hydrocarbons see fossil fuels; gas; oil hydrogenated renewable jet fuels (HRJs), 96 hydrogen fuel cells see fuel cells hydropower Argentina, 534 dam construction, 302, 304–5 and energy markets, 309 and energy storage, 308, 310, 665, 670–1 environmental impacts, 304–5, 308–9 and environmental law, 304–5 European Union, 310–11, 670 Finland, 141 Germany, 141 plant types, 308 pumped-storage plants, 308, 665, 670–1 research and development, 70 and risk, 307–11 run-of-river plants, 308 storage plants, 308 susceptibility to climate variability, 186, 187–8, 310 and uncertainty, 307–11 United Kingdom, 598 United States, 302–6, 310–11, 670 and water rights, 311 see also renewable energy Hydropower Regulatory Efficiency Act (US), 305–6 hypothermia, 406–7, 408 Iberdrola, 230 Iceland, 386 Idaho, 625 Illinois, 344 incentives and carbon capture and storage, 655–6 and climate change mitigation, 65–6, 583 and energy conservation, 51–2 and energy demand reduction, 176–7 and energy efficiency, 460–4 and energy storage, 671–3 and regulation, 40, 42–3, 46–7 and renewable energy, 23–4, 76–7, 79, 81–2, 125–8, 179–82, 274–5, 298–301, 500, 516–17, 585, 598, 615 and transmission network investment, 192–5 see also feed-in tariffs; subsidies; tax breaks

5053_Delivering Energy Law and Policy_Part 15.indd 700

Independent Petroleum Association of America, 332 India carbon emissions, 90–1, 593 climate change mitigation, 589 energy poverty, 393 fossil fuel investment, 14 and the Kyoto Protocol, 89 nuclear energy, 235, 253–4 indigenous peoples, Artic, 386–8, 537, 539 Industrial Emissions Directive (EU), 164 industry development, 42 Industry Growth Forum (US), 71 infrastructure in the Arctic see Arctic: energy infrastructural development coal-fired power plants see coal: power plant construction gas-fired power plants see gas: power plant construction hydroelectric dams see hydropower: dam construction hydropower plants see hydropower: plant types key infrastructure in Europe see Projects of Common Interest (PCIs) nuclear power plants see nuclear energy: power plant construction for ocean thermal energy see plantships opposition to development of see public opposition for transmission see transmission networks wind turbines see wind energy: turbine manufacture and installation Innovation and Entrepreneurship Center (US), 71 Institute for Energy Diversification and Saving (Spain), 615 Institute of Engineering and Technology (UK), 167 Institute of Terrorism Research and Response, 326 insulation, 130, 133–4, 397 insurance see liability insurance; nuclear insurance intangible drilling costs (IDCs), 74, 75 Intergovernmental Panel on Climate Change (IPCC), 442, 582, 590 Internal Energy Market (EU), 475 International Atomic Energy Agency (IAEA) Action Plan on Nuclear Safety, 248

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INDEX emergency planning zone recommendations, 260 Vienna Convention on Nuclear Liability, 243–7, 249–50, 252, 254 International Centre for the Settlement of Investment Disputes, 25 International Civil Aviation Organization (ICAO), 122, 123 International Energy Agency (IEA) on carbon capture and storage, 648, 663 on carbon intensity, 197 definition of energy subsidies, 20 energy access projections, 13 on fracking regulations, 335 on hydropower in the US, 303 on Ireland’s renewable energy pledge, 203 on push–pull policy frameworks, 283–4 on relationship between energy and water, 98, 99 research and development spending, 276 unburnable carbon analysis, 21–2 World Energy Outlook, 21, 98, 99, 460, 468, 664 international energy trade, 472–6; see also energy markets International Finance Corporation (IFC), 14 International Institute for Sustainable Development (IISD), 552 international law and the Arctic, 371, 386, 539–40 and energy security, 482–6 International Maritime Organization, 387 International Monetary Fund (IMF), 19–20 international networks, 589 International Renewable Energy Agency (IRENA), 154 investment risk, 516–17, 671–3 investor–state disputes, 23–8 Israel, 528 Iran, 529, 530, 531 Ireland electricity, 167, 202–7 energy policy, 202–7 energy poverty, 395 energy prices, 202–3, 554–8 environmental law, 554–8 fracking, 554 planning regulations, 557

5053_Delivering Energy Law and Policy_Part 15.indd 701

701 public opposition to energy projects, 554–8 renewable energy, 167, 202–7, 554, 557 transmission networks, 167 wind energy, 167, 202, 203, 554, 557 Italy, 24, 25, 114, 191, 462 Jänicke, Martin, 136 Japan bombing of, Second World War, 68 carbon capture and storage, 654 energy efficiency, 583 energy policy, 583 energy prices, 583 energy security, 583 energy source diversification, 583 fossil fuel investment, 14 Fukushima reactor disaster, 129, 221, 230, 242, 253 methane hydrate production, 633 nuclear energy, 129, 221, 230, 231, 233, 234, 242, 253 Joint Protocol (nuclear liability), 243, 245, 247, 249–50, 252 Jones, Benjamin, 378, 384 Juncker, Jean-Claude, 103, 148, 605 Kansas, 628 Kaufmann, R. K., 420 Kentucky, 344, 345–6 Keskitalo, Aili, 387, 388 Keystone XL pipeline, 547 Kneifel, J., 280, 281 Korea see South Korea Kuwait, 530 Kyoto Protocol, 88–9, 593, 596, 652–3 land use management see planning regulations Latvia, 142, 145, 191 Lawson, Nigel, 169 least developed countries (LDCs), 393; see also developing countries LED lights, 277 Lee, Wendy, 326 legacy reputation, 29–32 legal certainty, 298–301 legislation see competition law; data protection law; energy law; environmental law; free movement law (EU); international law; nuisance law Lehninger, Albert L., 415 lesser prairie chicken, 624–5, 628–9

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702

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

levy funding, 271; see also public benefit funds liability see exclusive liability; liability insurance; nuclear liability; strict liability; tort liability liability insurance, 251–5, 336–7 liberalisation see deregulation Libya, 191, 531, 532 life, and energy, 412–16 lignite, 130, 265; see also coal; fossil fuels Lipschutz, R. D., 469 liquefied natural gas (LNG), 145–6, 149, 354–5, 356, 479–80, 534 Lisbon Summit (NATO), 480 Lisbon Treaty, 33, 104 Lithuania, 145, 149, 191, 354, 480–1 loan guarantees United Kingdom, 159–60, 162, 218, 232 United States, 65, 69, 216–17, 225 local authorities, 559–61, 599 Localism Act (UK), 599 Locatelli, G., 258 London Protocol, 649 Lucas, Robert, 63 Lugar, Richard, 480 Lynch, Michael, 10 Maastricht Treaty, 191 McCollum, D. L., 585 Mackay, D., 550 Macrory, Richard, 601–2 Magyar Gaz Tranzit, 356 Maine, 280–1, 282 Malta carbon emissions, 496, 497–9 climate change mitigation, 497, 499 electricity, 496 energy efficiency, 500 energy law, 497–8 energy markets, 496 energy policy, 495–501 energy prices, 496 energy regulation, 497 energy source diversification, 496 fossil fuels, 496 gas, 496 incentive schemes, 500 renewable energy, 496, 500, 501 sustainable development, 496–7 transmission networks, 496 Malta Resources Authority, 497 Malta Resources Authority Act, 497 Manhattan Project, 68

5053_Delivering Energy Law and Policy_Part 15.indd 702

Marcellus shale basin, 328, 331, 338–9, 347 Marcellus Shale Operators’ Crime Committee, 326, 327 marine and coastal energy see ocean thermal energy; offshore wind farms; renewable energy: marine and coastal; wave energy Markandya, A., 462 market risk, 181, 671–2 marketing, 50–3, 172 markets see energy markets Marrakesh Accords, 88 Mauritania, 528 Mazzucchelli, P., 564 Medina, Debra, 547 Menz, F. C., 280, 281 Merton Rule (UK), 597 metabolism, 415 methane capture, 143 methane emissions, 331, 611 methane hydrates, 632–5 Mexico, 14, 57, 462 Middle East autocratic systems, 531–2 carbon capture and storage, 654 employment, 528 energy demand, 527–32 energy policy, 527–32 energy prices, 528–30 energy source diversification, 530 nationalisation of oil and gas, 529 nuclear energy, 530 petrol prices, 528–9 political participation, 528–9, 531–2 renewable energy, 530 structural role of oil and gas, 527–8, 530–2 subsidies, 528, 531 water, 531 see also individual countries military biomass and biofuels, 95–6, 641, 642 and climate change mitigation, 94–5 and energy policy, 92–6, 639–42 and energy security, 93–4 energy usage, 93, 639–41 renewable energy, 95–6, 641–2 research by, 68, 639–42 solar energy, 641 and technological innovation, 639–42 United States, 68, 92–6, 639–42 see also Department of Defense (US)

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INDEX Millennium Development Goals (UN), 98, 392 Miller, Stanley, 414 Mineral Resources Act (Greenland), 372–3 Ministry for Energy and Health (Malta), 496–7 Ministry for Sustainable Development, Environment and Climate Change (Malta), 497 Ministry of Economic Development and Trade (Ukraine), 513 Ministry of Energy and Coal Industry (Ukraine), 513–14 Ministry of Regional Development (Ukraine), 512–13 Montana, 625 Montes-Sancho, M. J., 280, 281 Montreal Protocol, 62 Morocco, 528 Motherway, Brian, 206 motor vehicles carbon emission standards, 608 electric, 76, 164–5, 197–201, 271 energy efficiency, 89, 614 ethanol-fuelled, 58–9, 154–5 flex-fuelled, 154–5, 677 fuel-cell powered, 59 hybrid, 76, 164, 197–201 replacement subsidies, 614 taxation, 613–14 vehicle-to-grid electric cars, 197–201 multilateral development banks (MDBs), 14 Mulvaney, D., 469 Nabucco project, 479 Naftogaz, 482–5 National Bioenergy Center (US), 70 National Center for Photovoltaics (US), 70 National Commission for State Energy and Public Utilities Regulation (Ukraine), 512 National Development Bank (Brazil), 676–7 National Energy Act (US), 58, 268 National Energy Efficiency Action Plan (Malta), 500 National Energy Efficiency Action Plan (Romania), 503 National Petroleum Agency (Brazil), 156 National Plan of Housing and Refurbishment (Spain), 614

5053_Delivering Energy Law and Policy_Part 15.indd 703

703 National Regulation Authorities (NRAs), 36–7, 350 National Renewable Energy Laboratory (US), 69–72, 667 National Renewable Energy Plan (Ireland), 557 National Strategy for Policy and Abatement Measures (Malta), 499, 500 national scientific laboratories (US), 68–72 National Wind Technology Center (US), 70 natural gas see gas Natural Gas Act (US), 360 Nelson, Richard, 63 neoclassical economic theory, 61–4 NER300, 653 net metering, 279, 281, 568–9 Netherlands, 671 network codes, 350–3 networks see transmission networks Nevada, 625 New Electricity Regulation (EU), 34, 37 New Electricity Trading Arrangements (UK), 168 New Gas Regulation (EU), 34, 37 New Mexico, 99–100, 363, 638 New York, 326, 328, 331, 335, 435, 571–5 newly industrialised countries (NICs), 393; see also developing countries NIMBY response, 546, 547 nitrogen oxide emissions, 62, 585, 613 Nixon, Richard, 91 Nordic Council of Ministers, 370 NordStream project, 479 North American Free Trade Agreement (NAFTA), 25, 28, 468 North Atlantic Treaty Organization (NATO) Allied Command Transformation Act, 481 Bucharest Summit (2008), 480 Chicago Summit Declaration (2012), 480 and energy security, 477–81 Energy Security Centre of Excellence, 480–1 Energy Security Section, 480 Lisbon Summit (2010), 480 Strategic Concept, 480 North Dakota, 343, 362–3, 625 North Dakota Legacy Fund, 343 Northern Ireland see United Kingdom

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704

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

North Sea oil and gas, 17–22, 229; see also United Kingdom Continental Shelf (UKCS) North Seas Countries’ Offshore Grid Initiative, 104 North-South Gas Interconnections in Central Eastern and South Eastern Europe, 356 Northern Sea Route (NSR), 387 Norway, 312–16, 342, 386 Norwegian Water Resources and Energy Directorate (NVE), 314, 315–16 Notre Europe think tank, 104–5, 106 Nuclear Decommissioning Authority (UK), 526 nuclear energy advanced boiling water reactors, 230, 231 advanced gas-cooled reactors, 228, 229, 525–6 AP1000 reactors, 225, 230, 231, 233 APR-1400 reactors, 523 Chernobyl reactor disaster, 129, 132 China, 90, 233, 234 Czech Republic, 509 deregulation, 216 economic performance, 220–1 emergency planning zones, 259–60 and employment, 221 and energy markets, 239–40 and energy policy, 219–22, 236–41 European pressurised water reactors, 142, 224, 225, 226, 232, 239, 520, 523, 526 European Union: Euratom Treaty, 104, 116, 247; market integration, 239–40; nuclear liability law, 247–8, 254; reduction of, 126, 129–30, 132, 137–8, 240; susceptibility to climate variability, 186–7 Finland, 141, 142, 215, 217, 221, 224 France, 187, 215, 217, 220, 221, 225, 233, 234, 523 Fukushima reactor disaster, 129, 221, 230, 242, 253 Generation III+ reactors, 220–1, 222 Germany, 129–30, 132, 137–8, 230, 234, 240 India, 235, 253–4 influence of nuclear lobby, 222 and insurance, 251–5 Japan, 129, 221, 230, 231, 233, 234, 242, 253 and liability, 242–50, 251–5

5053_Delivering Energy Law and Policy_Part 15.indd 704

Middle East, 530 and planning regulations, 237 power plant construction, 90, 142, 215–18, 219–21, 223–7, 228–35, 236–41, 522–3, 526, 597 power plant financing, 223–7, 230, 231–2, 238–9 privatisation, 229–30 regulation, 157–8, 173, 231, 259–60 and risk, 215–16, 223–7, 231, 232 Russia, 129, 132, 234 safety regulation, 173, 231 small modular reactors, 240, 256–61 South Korea, 233, 235 subsidies for, 19, 161–2 susceptibility to climate variability, 186–7 and technological innovation, 233 Three Mile Island accident, 222 transportation of nuclear material, 243, 245 and uncertainty, 157–8 United Kingdom: and energy policy, 219–22, 237; and European energy policy, 161–2, 236–41; Hinkley Point C power station, 161–2, 166, 226, 228, 231–2, 237–9; international comparison of nuclear programme, 228–35; nuclear liability law, 253; and planning regulations, 237; power plant closures, 164, 597; power plant construction, 161–2, 166, 215, 217–18, 219–21, 225–7, 228–35, 236–41, 522–3, 526, 597; power plant financing, 225–7, 230, 231–2, 238–9; privatisation, 229–30; Sizewell B power station, 164, 228, 229, 233; Sizewell C power station, 231, 523; subsidies, 19 United States: Atoms for Peace plan, 68–9; and the Chinese nuclear industry, 90; deregulation, 216; development of, 57, 68–9; international comparison of nuclear programme, 234; nuclear liability law, 253; power plant construction, 215, 216–17, 220–1, 225, 230; reactor technology, 233; regulation, 157–8; small modular reactors, 258; Three Mile Island accident, 222; VC Summer power station, 217, 225; Vogtle power station, 217, 225, 226; Watts Bar II power station, 217 Nuclear Energy Institute (NEI), 157

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INDEX nuclear ice-breaking submarines, 539 Nuclear Installations Act (UK), 253 nuclear insurance, 251–5 nuclear liability, 242–50, 251–5 Nuclear Liability Expert Group (EU), 248 Nuclear Regulatory Commission (US), 260 nuclear weapons, 68 NuGen, 230 nuisance law, 619–23 Nuisance Removal Acts (UK), 619 Nunaoil, 372 Obama, Barack, 22, 30, 89, 91, 95, 547, 642 ocean thermal energy, 643–6 Office for Nuclear Development (UK), 237 Office for Nuclear Regulation (UK), 231, 237 Office of Gas and Electricity Markets (Ofgem) (UK), 112–13, 176, 453, 454–5, 597 Office of Science (US), 69, 70 Offshore Energy Act (Norway), 314, 315–16 offshore wind farms, 143, 166, 289–90, 312, 315–16 Ohio, 360 oil Arctic, 370–3, 385–8, 537–41 Argentina, 533, 534 and employment, 330 excise duties, 121–4 exploration options, 156 expropriation risk, 158 field allowances, 17–22 Germany, 130 Greenland, 370–3 intangible drilling costs, 75 international trade in, 474 Middle East, 527–32 military usage, 93 nationalisation of, 529 North Sea oil, 17–22, 229 OAPEC embargo (1973), 57 OPEC embargo (1979), 276 percentage depletion, 75 prices, 12, 57, 58, 156, 273–7, 329–30, 470, 471, 533, 597 production levels, 330 regulation, 365–9, 370–3 from shale see shale gas and oil shortages, 58

5053_Delivering Energy Law and Policy_Part 15.indd 705

705 storage of crude oil, 330 structural role in Middle East, 527–8, 530–2 tax breaks, 75 taxes on, 77, 613, 616 and uncertainty, 155–6 United Kingdom, 17–22, 77, 229, 365–9 United States: dependence on, 57–8, 94, 96, 643–4; domestic production, 57, 330, 340, 643–4; military usage, 93; OAPEC embargo, 57; shortages, 58; storage of crude oil, 330; tax breaks, 75; taxes on, 77 see also fossil fuels; petrol Oil and Gas Authority (UK), 368–9 Oil Change International, 13 Oklahoma, 100, 628 Öko-Institute (Germany), 131 Olkiluoto power station (Finland), 142, 217, 221, 224, 226 Oman, 530 Oparin, Alexander, 414 Open Working Group (OWG), 394 Oregon, 571–5, 625 Organization for Economic Cooperation and Development (OECD) definition of energy subsidies, 20 Paris Convention, 243–7, 249, 252, 253, 254 report on Czech Republic, 507 Organization of Arab Petroleum Exporting Countries (OAPEC), 57 Organization of Petroleum Exporting Countries (OPEC), 58, 59, 276, 330 Osborne, George, 18 osmosis see wave energy ozone depletion, 62 Parey, S., 187–8 Paris Agreement (UN), 594–5 Paris Convention (nuclear liability), 243–7, 249, 252, 253, 254 peak reduction (energy demand), 164–5, 175, 177, 310, 430, 432 Pennsylvania, 326, 328, 338–43, 344, 361–2 Pentalateral Energy Forum, 105 percentage depletion, 75 petrol prices of, 528–9 taxes on, 77, 613, 616 see also fossil fuels; oil

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706

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

Petroleum and Submarine Pipelines Act (UK), 366 photosynthesis, 413, 414–15 photovoltaic (PV) energy see solar energy Pickles, Eric, 291 Pindyck, R. S., 154 Pipeline and Hazardous Material Safety Administration (US), 360 pipelines see gathering lines; transmission networks Planning and Building Act (Norway), 313–14 planning regulations Germany, 295–6 Ireland, 557 and the law of nuisance, 619–23 Norway, 313–14 United Kingdom, 237, 291, 517, 518, 619–23 plantships, 644–5 Poland energy efficient appliances, 462 fracking, 325, 327–8 gas transmission networks, 149, 356 liquefied natural gas, 149, 354–5, 479 proposes Energy NATO concept, 479 shale gas and oil, 325, 327–8 Polar Code, 387 policy acceleration, 135–6 policy mixes, 450–1 pollution and climate change mitigation, 585 and emissions trading, 42, 43, 62 and environmental law, 60, 62 and fracking, 331, 332, 333–4 legislation relating to, 60 polluter pays principle, 124 reduction of, 42, 60, 62, 585 taxes on, 42, 43, 122–3, 124 United States, 60, 62 of water, 332, 333–7, 340–1 see also carbon and greenhouse gas emissions; methane emissions; sulphur dioxide emissions; water contamination power purchase agreements (PPAs), 126–7 power-to-gas (P2G) technologies, 271 power-to-heat (P2H) technologies, 271 Powers, N., 280, 281 premium schemes, 180–2 Price-Anderson Act (US), 253 price arbitrage, 665–7, 670 price response bidding programmes, 430

5053_Delivering Energy Law and Policy_Part 15.indd 706

price-responsive demand, 430 price risk, 180–1, 216, 224, 225–6, 232, 309, 516–17 pricing see carbon pricing; energy prices Prins, Steve, 11 privatisation Central and Eastern Europe, 208 electricity, 163, 169–70, 208 Germany, 489 nuclear energy, 229–30 Russia, 478 United Kingdom, 163, 169–70, 229–30 procedural justice, 378, 382, 387 Production Sharing Agreements (PSAs), 478 production tax credits (PTCs), 74, 76–7 prohibitive principle of energy justice, 378–80 Projects of Common Interest (PCIs), 350, 355–6 promotion see marketing protests see activism; public opposition public benefit funds, 279, 281, 282 public consultation, 8–9, 326–7, 387, 549–53 public engagement, 111–15, 177, 549–53, 554–8 public information, 7, 52, 112–13, 177, 434, 437–41, 444, 455, 458 public opposition to electricity pylons, 554 and environmental law, 554–8 to fracking, 325–8, 330, 547–8, 554 Ireland, 554–8 and litigation, 554–8 to local energy projects, 545–8, 554–8 NIMBY response, 546, 547 to pipelines, 547 to smart metering, 456 United States, 546–8 to wind farms, 546, 554, 557 see also activism Public Utility Commission of Texas, 79, 80, 82–3 Public Utility Commissions (US), 46, 79, 80, 82–3 Public Utility Regulatory Policies Act (US), 58, 268 pumped-storage hydropower plants, 308, 665, 670–1 push–pull policy frameworks, 274–5, 283–7 Putin, Vladimir, 478

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INDEX Qatar, 528 radiant energy, 413, 414–15 railways, 121–4, 345 Raynor, Gwyn, 11 rebound effects, 421–2, 426, 427, 458–9, 463–4 recognition-based justice, 383, 388 regional climate models (RCMs), 186 Regional Greenhouse Gas Initiative (US), 269, 589 regional transmission organisations (US), 431–2 regulation see energy regulation; planning regulations REMIT Regulation (EU), 35 Renewable Auction Mechanisms (RAMs), 571–7 renewable energy Arctic, 387 Argentina, 534, 535–6 Belgium, 299–301 biomass see biomass and biofuels and community energy projects, 563–4 competitive bidding, 292–7 developing countries, 72, 276–7 and distributed energy resources, 563, 566–9, 570–7 and emissions trading, 265–7, 268–72 and energy demand, 271–2 and energy markets, 179–83, 292–7, 309 and energy policy, 268–72, 283–7, 469, 515–19, 551–2, 597–8 energy security, 160–1, 469 and energy storage, 90, 198–201, 310, 664–8, 669–73 and environmental law, 597–8 European Union: biomass and biofuels, 552, 585, 642, 674–8; cooperation with Russia, 317–21; and energy policy, 283–7, 551–2; energy security, 160–1; expansion of, 129–30, 132–3, 137–8, 240, 265–7; feed-in tariffs, 24, 126–8, 180, 182–3, 285, 309; hydropower, 310–11, 670; incentive schemes, 24, 125–8, 179–82, 585; investor–state disputes, 23–8; market circumvention, 182–3; market integration, 179–82; Renewable Energy Directive, 24, 203, 318, 320, 675, 676; research and development, 284–7; solar energy, 283–7;

5053_Delivering Energy Law and Policy_Part 15.indd 707

707 subsidies, 293–4; susceptibility to climate variability, 186, 187–90; targets, 24, 202–3, 596; wind energy, 283–7 expansion of, 129–30, 132–3, 137–8, 240, 265–7, 582 feed-in tariffs: and carbon emissions, 268–72; European Union, 24, 126–8, 180, 182–3, 285, 309; Finland, 143; Germany, 133, 268–9, 285, 309; levy-funded, 271; and regulation, 41; Spain, 615, 616–18; United Kingdom, 516, 517–18, 598; United States, 268 Finland, 141–3 geothermal see geothermal energy Germany: biomass and biofuels, 130, 133; competitive bidding, 292–7; expansion of, 129–30, 132–3, 137–8, 240, 265–7; feed-in tariffs, 133, 268–9, 285, 309; hydropower, 130; incentive schemes, 24; investor– state disputes, 24, 25; and planning regulations, 295–6; solar energy, 130, 133, 285, 292–7; subsidies, 265–7; transmission network integration, 289–90; wind energy, 130, 132, 289–90 and green certificates, 299–301 and grid stability, 167, 289–90 hydro see hydropower impact upon carbon emissions, 265–7, 268–72 incentive schemes, 23–4, 76–7, 79, 81–2, 125–8, 179–82, 274–5, 298–301, 500, 516–17, 585, 598, 615 investor–state disputes, 23–8 Ireland, 167, 202–7, 554, 557 Latvia, 142 and legal certainty, 298–301 Malta, 496, 500, 501 marginal costs, 181 marine and coastal, 143, 166, 289–90, 312–16, 643–6 marketing of, 53, 172 Middle East, 530 military use of, 95–6, 641–2 and net metering, 279, 281 Norway, 312–16 ocean thermal see ocean thermal energy and oil prices, 273–7, 470 output variability, 168, 169, 182, 199, 310, 664, 669

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708

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

renewable energy (Cont.) and planning regulations, 291, 295–6, 313–14, 517, 518 premium schemes, 180–2 and public benefit funds, 279, 281, 282 renewable portfolio standards, 157, 268, 278–82, 571 research and development, 69–72, 273–7, 284–7, 615 and risk, 154, 157, 307–11, 516–19 Russia, 317–21 solar see solar energy Spain, 24, 25, 28, 126–7, 611, 615, 616–18 subsidies, 14–15, 265–7, 268–9, 293–4, 298–301, 615, 644–6 susceptibility to climate variability, 186, 187–90 Sweden, 142 targets, 24, 202–3, 596, 598 tax breaks, 76–7, 81–2 technological innovation, 273–7 transmission network integration, 79–83, 167, 289–90, 644, 645 and uncertainty, 154, 157, 180–2, 307–11 United Kingdom: biomass and biofuels, 522, 598; and community energy projects, 563–4; contribution to electricity generation, 164, 166; and energy policy, 515–19, 597–8; and environmental law, 597–8; feed-in tariffs, 516, 517–18, 598; hydropower, 598; incentive schemes, 24, 516–17, 598; and planning regulations, 291, 517, 518; solar energy, 166, 564; susceptibility to climate variability, 190; targets, 598; wave energy, 190, 522; wind energy, 166, 290–1, 564, 598 United States: biomass and biofuels, 58–9, 95–6, 282, 585, 641, 642, 675, 677–8; feed-in tariffs, 268; fuel cells, 59; hydropower, 302–6, 310–11, 670; incentive schemes, 76–7, 79, 81–2, 585; and the military, 95–6, 641; net metering, 279, 281; ocean thermal energy, 643–6; public benefit funds, 279, 281, 282; renewable portfolio standards, 157, 278–82, 571; research and development, 69–72; solar energy, 59, 84–7, 641; state-level initiatives, 278–82; subsidies, 644–67; tax breaks,

5053_Delivering Energy Law and Policy_Part 15.indd 708

76–7, 81–2; transmission network integration, 79–83, 644, 645; wind energy, 76–7, 79–83, 546 waves see wave energy wind see wind energy Renewable Energy Directive (EU), 24, 203, 318, 320, 675, 676 Renewable Energy Sources Act (EEG) (Germany), 133, 268–9, 293–7 renewable portfolio standards (RPSs), 157, 268, 278–82, 571 Report on Projections, Policies and Measures (Malta), 499, 500 reputation see corporate reputation; legacy reputation Request for Proposals (RFP) procurement, 571–7 research and development (R&D) biomass and biofuels, 70, 676, 677 Brazil, 677 and climate change mitigation, 583 developing countries, 276 energy conservation, 70 energy efficiency, 70 energy storage, 667, 671 European Union, 284–7, 642, 676 fossil fuels, 276 fuel cells, 70 funding for, 171, 172, 274–6, 284–7 hydropower, 70 by the military, 68, 639–42 and oil prices, 273–7 renewable energy, 69–72, 273–7, 284–7, 615 solar energy, 70, 274–5, 284–7 Spain, 615 United States, 68–72, 276, 639–42, 667, 677 wind energy, 70, 284–7 see also technological innovation respiratory conditions, 405, 409 Revelt, D., 462 revenue risk see price risk risk balancing risk, 182 and carbon capture and storage, 656 construction risk, 216, 223–7, 232 and energy policy, 8, 153–8 and energy storage, 671–3 expropriation risk, 158 and hedging, 161 and hydropower, 307–11 investment risk, 516–17, 671–3 market risk, 181, 671–2

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INDEX and nuclear energy, 215–16, 223–7, 231, 232 price risk, 180–1, 216, 224, 225–6, 232, 309, 516–17 and renewable energy, 154, 157, 307–11, 516–19 see also uncertainty Rocha, K., 155–6 Romania, 356, 357, 502–6 Romer, Paul, 63 Roosevelt, Franklin D., 68 Rosneft, 386, 478 Rothstein, B., 187–8 run-of-river hydropower plants, 308 Russia Arctic energy exploration, 386 carbon emissions, 319–20 Chernobyl reactor disaster, 129, 132 electricity, 191–2, 318–21 energy policy, 477–8 energy prices, 146–7 fossil fuel subsidies, 14, 146 gas, 145–7, 160, 354, 477–9, 482–6 nuclear energy, 129, 132, 234 privatisation, 478 Production Sharing Agreements, 478 relations with the EU, 145–50, 317–21, 477–9, 482–6 renewable energy, 317–21 shipping routes, 387 subsidies, 14, 146 transmission networks, 191–2, 318, 484 and the Ukraine, 104, 147, 317, 349, 477–8, 482–6 Unified Energy System, 318 RWE, 110, 230, 238, 240, 490 safety regulation, 173, 231 Sainati, T., 259 Sami people, 387–8 Saudi Arabia, 14, 475, 530 Schlör, H., 140 Schrödinger, Erwin, 414 Schwartz, E. S., 158 Science without Borders, 676 Scotland see United Kingdom Second Electricity Directive (EU), 209 Second Energy Package (EU), 119 second-generation biofuels, 674–8 Second World War, 68, 345 Sector Inquiry (EU), 34–5, 109 security see energy security Šefčovič, Maroš, 39, 103, 148

5053_Delivering Energy Law and Policy_Part 15.indd 709

709 self-sufficiency see energy independence severance taxes, 346 shale gas and oil Argentina, 534, 535–6 Canada, 547 and climate change mitigation, 585 and employment, 334 environmental impacts, 332, 333–4 European Union, 325–8 France, 326, 327 horizontal drilling, 329, 333 legacy effects of, 338–43 Poland, 325, 327–8 regulation, 329–32, 334, 336–7, 341 United Kingdom, 597 United States, 99, 149, 326–8, 329–32, 333–7, 338–43, 347, 547–8 see also fracking Shaw, S., 564 Shell, 22 Shepherd, J., 257 shipping, 93, 96, 387, 539, 607, 642 short-circuit level, electricity networks, 167 short term operating reserves (STOR), 670 Shove, Elizabeth, 458, 459 Shrimali, G., 280, 281 Shropshire, D., 257 Sidortsov, Roman, 378, 384 Siemens, 240, 288–9, 290 Sitter, N., 469 Sizewell B power station (UK), 164, 228, 229, 233 Sizewell C power station (UK), 231, 523 skills development, 42 Slovakia, 149, 356 Slovenia, 356 Slurry Biodigestion Plan (Spain), 615 small modular reactors (SMRs), 240, 256–61 smart appliances, 175 smart devices, 433 smart efficiency, 177 smart grids, 429–30, 494, 669–73 smart metering, 89, 106, 111, 168, 175, 176, 430, 433, 444, 452–6, 494, 599 Smart Metering Working Group (UK), 452, 453 Smitherman, Barry, 82 Social Democratic Party (Germany), 132 socio-technical transition theory, 449, 450–1

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710

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

solar energy competitive bidding, 292–7 developing countries, 72 European Union, 283–7 funding for, 59 Germany, 130, 133, 285, 292–7 incentive schemes, 274–5 and LED lights, 277 Malta, 501 marginal costs, 181 military use of, 641 output variability, 310 and planning regulations, 295–6 research and development, 70, 274–5, 284–7 and solar rights, 84–7 susceptibility to climate variability, 189–90 United Kingdom, 166, 564 United States, 59, 84–7, 641 see also renewable energy solar rights, 84–7 Solow, Robert, 63 South Dakota, 625 South Korea, 14, 233, 235, 654 South Stream gas pipeline, 149 Southern Gas Corridor (SGC), 356 Sovacool, Benjamin, 378, 384 sovereign wealth funds, 342–3 Soviet Union see Russia Soyuzgazexport, 483 Spain carbon emissions, 612–14, 616 carbon pricing, 611, 612–14 climate change mitigation, 610–18 coal, 612–13 electricity, 176, 187, 613 emissions trading, 612, 616–18 energy efficiency, 463, 611, 614, 616 energy labelling, 614, 616 energy policy, 610–18 energy prices, 176, 617 feed-in tariffs, 615, 616–18 gas, 613 housing, 614, 616 motor vehicle taxation, 613–14 non-carbon greenhouse gas emissions, 611, 615 petrol taxes, 613, 616 renewable energy, 24, 25, 28, 126–7, 611, 615, 616–18 research and development, 615 subsidies, 612–13, 614, 616 taxation, 613–14, 616 wind energy, 616

5053_Delivering Energy Law and Policy_Part 15.indd 710

spinning reserves, 200, 258, 432–3 sponsorship, 51 stakeholder analysis, 9 State Agency on Energy Efficiency and Energy Saving (Ukraine), 513 state aid see contracts for difference; feedin tariffs; incentives; loan guarantees; subsidies; tax breaks state sovereignty, 26, 118–19, 468 Stavins, Robert, 265–7 Stewardship Initiative (UK), 366–7, 369 Stiesdal, Henrik, 289 Stockholm Chamber of Commerce, 25, 484–5 Stonington, J., 140 Stop Smart Meters UK, 456 storage see carbon capture and storage; energy storage storage hydropower plants, 308 Strategic Concept (NATO), 480 Strategy for Renewable Electicity Exploitation (Malta), 500 strict liability, 252, 337, 372 strokes, 405, 408 subsidies Australia, 13 Belgium, 299–301 biodigestion equipment, 615 carbon capture and storage, 650 defining, 19–21 electricity generation, 160–2 energy efficient appliances, 460–4 and energy prices, 528–9 European Union, 160–2, 293–4 and field allowances, 17–22 fossil fuels, 12–16, 583, 612–13 gas, 146 Germany, 265–7 housing refurbishment, 614, 616 Israel, 528 Middle East, 528–9, 531 motor vehicle replacement, 614 nuclear energy, 19, 161–2 renewable energy, 14–15, 265–7, 268–9, 293–4, 298–301, 615, 644–6 Russia, 14, 146 Spain, 612–13, 614, 615, 616 Tunisia, 528 Turkey, 528 United Kingdom, 14, 19, 161–2, 650 United States, 13, 644–6 water, 531 see also feed-in tariffs; incentives; tax breaks

31/05/16 9:54 AM

INDEX Sudan, 528 sulphur dioxide emissions, 62, 155, 613 SunShot Initiative (US), 65 supply networks see transmission networks sustainable development affordable sustainable energy technologies, 391–4 and Agenda 21, 98, 587–8 and the Energiewende, 137–40 and energy justice, 381–4 and energy policy, 97–100, 135–40, 381–4, 468 and energy poverty, 391–4 and energy security, 468 European Union, 135–40 Germany, 137–40 and housing, 89, 401 Malta, 496–7 sustainability boundaries, 136, 139 UN Sustainable Energy for All initiative, 393, 584–5 United States, 97–100 and water management, 97–100 Sustainable Development Goals (UN), 98–9 Sustainable Energy and Water Conservation Unit (Malta), 496–7 Sustainable Energy for All initiative (UN), 393, 584–5 Sweden, 122–3, 142, 386 Switzerland, 191 synthetic fuels, 58–9, 95–6 system inertia, electricity networks, 167 Target Model for Electricity (EU), 127 tax breaks biofuels, 676 climate change mitigation, 65 for consumers, 76, 462 energy efficiency, 599 European Union, 676 fossil fuels, 14, 17–22, 75 renewable energy, 76–7, 81–2 United Kingdom, 17–22, 599 United States, 65, 73–7, 81–2 see also incentives; subsidies; taxation taxation of aviation fuel, 121–4 carbon taxes, 78, 583, 612–14, 649–50 coal production taxes, 77, 346 and energy demand, 427 and energy efficiency, 462, 463 and energy policy, 73–8 energy taxes, 77, 613

5053_Delivering Energy Law and Policy_Part 15.indd 711

711 and the environment, 42, 43, 122–3, 124 European Union, 121–4 and incentivisation see tax breaks motor vehicles, 613–14 oil production taxes, 77 petrol taxes, 77, 613, 616 pollution taxes, 42, 43, 122–3, 124 Spain, 613–14, 616 Sweden, 122–3 tax expenditures, 73–5 tax filtering, 28 United Kingdom, 77 United States, 73–8, 346 Technical Code of Buildings (Spain), 614, 616 technological agnosticism, 10–11 technological innovation and biofuels, 676 and climate change mitigation, 62–7 and competition law, 642 and desertification, 631–2 and energy policy, 62–7, 639–42 and energy storage, 671 European Union, 642, 676 funding for, 274–6 and methane hydrate production, 633 and the military, 639–42 and neoclassical economic theory, 63 and nuclear reactor design, 233 and pollution reduction, 42 and public engagement, 551 and regulation, 42, 43 and renewable energy, 273–7 United States, 62–7, 639–42 and water management, 631–2 see also research and development Technology Partnership Agreements (US), 71 Temelin nuclear power plant (Czech Republic), 509 Tennyson, Alfred, Lord, 680 Teollisuuden Voima Oyj (TVO), 142, 217 Tetlock, Philip, 10 Texas, 79–83, 330–1, 338, 360–1, 547, 628 thermal insulation, 130, 133–4, 397 thermal stores, 402–3 third country clause (TEP, EU), 36 Third Electricity Directive (EU), 34, 35, 36, 208–9, 396 Third Energy Package (EU), 34–9, 119, 171, 172, 208–9, 349–50, 395, 508, 509–10, 570, 575 Third Gas Directive (EU), 34, 35, 36, 396

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712

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

Three Mile Island nuclear accident, 222 time-of-use tariffs, 165, 176 tort liability, 252, 336–7 Toshiba, 230, 233 Town and Country Planning Acts (UK), 619–20 Train, K., 462 transactive pricing, 175 Transatlantic Trade and Investment Partnership (TTIP), 25 transition management, 551, 552–3 transmission networks capacity allocation mechanisms, 350–1 and carbon capture and storage, 655 congestion management procedures, 352 cooperation between, 37–8, 105–6, 149, 191–6, 318–21, 349–53, 354–8 cost-effective design of, 649 cross-border transmission, 149, 191–6, 318–21, 349–53 and distributed energy resources, 433, 435, 566–9, 570–7 European Union, 35–8, 105–6, 145–6, 149, 191–6, 349–53, 354–8, 478, 379 frequency regulation, 167, 200–1 gas, 35, 145–6, 149, 349–53, 354–8, 478, 479, 484 gathering lines, 359–64 Germany, 191, 289–90, 491–4 grid stability, 166–7, 289–90 investment in, 105–6, 192–5 investment incentive schemes, 192–5 Ireland, 167 liquefied natural gas, 145–6, 149, 354–5, 356, 479 Malta, 496 network codes, 350–3 network tariffs, 491–3 regulation, 46–7, 105–6, 349–53, 359–64, 491–3 renewable energy integration, 79–83, 167, 289–90, 644, 645 Russia, 191–2, 318, 484 security of, 45–9 short-circuit level, 167 smart grids, 429–30, 494, 669–73 supply disruptions, 48 system inertia, 167 third-party access, 491 Ukraine, 478, 484 unbundling from suppliers, 35–6, 80, 490–1, 507–10

5053_Delivering Energy Law and Policy_Part 15.indd 712

United Kingdom, 166–7 United States, 46, 79–83, 547, 644, 645 Trans-Pacific Partnership (TPP), 25 transport see aircraft; motor vehicles; railways; shipping Treasury Department (US), 348 Treaty of Paris, 116 Treaty of the European Union (TEU), 26 Treaty on the Functioning of the European Union (TFEU), 108, 117–19 Trigeorgis, L., 154 Trolle, A. B., 158 Troubled Asset Relief Program (US), 347–8 Tunisia, 528 Turkey, 356, 528 Tusk, Donald, 103, 106, 147 2030 Energy and Climate Policy Framework (EU), 606 Ukraine energy efficiency, 512–13 energy law, 511–14 energy policy, 511–14 energy regulation, 512 European integration, 511–14 public administration, 511–14 and supply of Russian gas, 104, 147, 317, 349, 477–8, 482–6 transmission networks, 478, 484 unbundling Czech Republic, 507–10 European Union, 35–6, 490–1 Germany, 490–1 United States, 80 unburnable carbon, 12, 15, 21–2 uncertainty and energy policy, 8, 153–8 and energy regulation, 153–8 and expropriation risk, 158 and hedging, 161 and hydropower, 307–11 and nuclear energy, 157–8 and the oil industry, 155–6 and renewable energy, 154, 157, 180–2, 307–11 see also risk underfloor heating, 403 unemployment see employment Unified Energy System (Russia), 318 United Arab Emirates (UAE), 530 United Kingdom (UK) biomass and biofuels, 522, 598

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INDEX carbon capture and storage, 229, 650, 660–3 climate change mitigation, 17–18, 21589, 596–600 coal, 164, 166, 520–6 community energy projects, 177, 562–5 contracts for difference, 159–60, 162, 232, 237, 239, 516, 517–18, 650 deregulation, 163–4, 169–70, 229 distributed energy resources, 450, 563 electricity: demand reduction incentives, 176–7; demand levels, 164–5; deregulation, 163–4, 169–70; distributed energy resources, 450, 563; generated by community energy projects, 563–4; generation policy, 163–70, 171–3, 520–6, 597; grid stability, 166–7; lowcarbon generation, 163–70, 171–3; power plant construction, 520–6; privatisation, 163, 169–70; sector reform, 171–3; smart metering, 452–6, 599; susceptibility to climate variability, 190 energy conservation, 425–6 energy consumers, 112–13, 176–7 energy demand, 164–5, 176–7, 425–6 energy efficiency, 400–4, 425–6, 448–51, 598–9 energy law, 365–9, 596–600 energy policy: at city level, 559–61; and climate change mitigation, 596–600; and community energy projects, 562–5; D3 programme, 450; and devolution, 597; and electricity generation, 163–70, 171–3, 520–6, 597; and electricity market reform, 171–3; and energy demand, 425–6; and energy efficiency, 448–51; and energy security, 470–1; and nuclear energy, 219–22, 229, 236–41; and privatisation, 169–70; and renewable energy, 515–19, 597–8; role of local authorities, 559–61, 599; and smart metering, 452–6, 599 energy poverty, 395, 405–11, 598–9 energy prices, 112–13, 168 energy regulation, 112–13, 176, 365–9, 660–3 energy security, 470–1 energy storage, 667 environmental law, 164, 226, 596–600, 619–23 feed-in tariffs, 516, 517–18, 598

5053_Delivering Energy Law and Policy_Part 15.indd 713

713 fossil fuel subsidies, 14, 17–22 gas, 17–22, 164, 166, 229, 520–6, 597 health, 405–11 housing, 400–4, 405–11, 598–9 hydropower, 598 loan guarantees, 159–60, 162, 218, 232 local authorities, 559–61, 599 North Sea oil and gas, 17–22, 229 nuclear energy: and energy policy, 219–22, 237; and European energy policy, 161–2, 236–41; Hinkley Point C power station, 161–2, 166, 226, 228, 231–2, 237–9; nuclear liability law, 253; and planning regulations, 237; power plant closures, 164, 597; power plant construction, 161–2, 166, 215, 217–18, 219–21, 225–7, 228–35, 236–41, 522–3, 526, 597; power plant financing, 225–7, 230, 231–2, 238–9; privatisation, 229–30; Sizewell B power station, 164, 228, 229, 233; Sizewell C power station, 231; subsidies, 19 nuisance law, 619–23 oil, 17–22, 77, 229, 365–9 petrol taxes, 77 planning regulations, 237, 291, 517, 518, 619–23 privatisation, 163, 169–70, 229–30 renewable energy: biomass and biofuels, 522, 598; and community energy projects, 563–4; contribution to electricity generation, 164, 166; and energy policy, 515–19, 597–8; and environmental law, 597–8; feed-in tariffs, 516, 517–18, 598; hydropower, 598; incentive schemes, 24, 516–17, 598; and planning regulations, 291, 517, 518; solar energy, 166, 564; susceptibility to climate variability, 190; targets, 598; wave energy, 190, 522; wind energy, 166, 290–1, 564, 598 shale gas and oil, 597 smart metering, 452–6, 599 solar energy, 166, 564 subsidies, 14, 19, 161–2, 650 tax breaks, 17–22, 598 taxation, 77 transmission networks, 166–7 wave energy, 190, 522 wind energy, 166, 290–1, 564, 598

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714

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

United Kingdom Continental Shelf (UKCS), 18, 365–9; see also North Sea oil and gas United Nations (UN) Agenda 21, 98, 587–8, 597 climate change mitigation goals, 21 Commission on International Trade Law, 25 Conference on Sustainable Development 2012, 394 Convention on the Law of the Sea (UNCLOS), 371, 386, 539–40 Convention to Combat Desertification (UNCCD), 630–5 Development Programme (UNDP), 393, 634 Earth Summit (1992), 587–8, 597 Educational, Scientific and Cultural Organization (UNESCO), 98 Environmental Program (UNEP), 72, 537 Framework Convention on Climate Change, 15, 88, 371, 497, 593, 594–5, 596, 606 Industrial Development Organization (UNIDO), 662 Kyoto Protocol, 88–9, 593, 596, 652–3 Millennium Development Goals, 98, 392 Open Working Group (OWG), 394 Paris Agreement, 594–5 Sustainable Development Goals, 98–9 Sustainable Energy for All initiative, 393, 584–5 United States (US) Arctic ecosystem research, 541 Arctic energy exploration, 385, 386 biomass and biofuels, 58–9, 95–6, 282, 585, 641, 642, 675, 677–8 carbon capture and storage, 62, 157, 654 carbon emissions, 90–1, 157, 346, 442–3, 581, 589 carbon taxes, 78 climate change mitigation: carbon taxes, 78; climate agreement with China, 88–91; emissions trading, 61–2, 66, 78, 269, 589; and energy policy, 61–7; incentive schemes, 65–6; and the military, 94–5; regional initiatives, 589; and technological innovation, 62–7 coal, 77, 340–1, 344–8 competition law, 107

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demand response, 431–5 deregulation, 79, 80–1, 160, 216 distributed energy resources, 435, 567, 570–5 dynamic pricing, 433–4 electricity: deregulation, 79, 80–1, 160; distributed energy resources, 435, 567, 570–5; energy storage, 200–1, 665; market competition, 81; military usage, 93; net metering, 279, 281; prices, 81; provision to hinterlands, 57; transmission networks, 79–83; unbundling, 80 eminent domain authority, 359–64 emissions trading, 61–2, 66, 78, 269, 589 employment, 70, 278, 330, 334, 345–6 energy consumers, 76 energy demand, 421, 431–5 energy efficiency, 421, 462, 463 energy independence, 57, 334, 470 energy law, 57, 58, 60, 84–7, 304–6 energy policy: and carbon capture and storage, 654; and climate change mitigation, 61–7; and demand response, 434–5; historical overview, 57–60; and the military, 92–6, 639–42; and national scientific laboratories, 68–72; and neoclassical economics, 61–4; at state level, 278–82; and sustainable development, 97–100; and taxation, 73–8; and technological innovation, 62–7, 639–42; and water management, 97–100 energy prices, 81, 433–4, 583 energy regulation, 43, 46, 157–8, 329–32, 334, 336–7, 341, 359–64 energy security, 57, 93–4, 334, 469–70 energy source diversification, 58–9, 96 energy storage, 201, 665, 667 environmental law, 60, 62, 304–5 EPSA case, 434–5 ethanol fuel, 58–9 feed-in tariffs, 268 fossil fuel subsidies, 13 fracking, 57–8, 326–8, 329–32, 333–7, 338–43, 547–8 fuel cells, 59 gas: domestic production, 57, 340, 347; gathering lines, 359–64; liquefied natural gas, 479–80; military usage, 93; prices, 81; tax breaks, 75 hydropower, 302–6, 310–11, 670 liquefied natural gas, 479–80

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INDEX loan guarantees, 65, 69, 216–17, 225 military, 68, 92–6, 639–42 national scientific laboratories, 68–72 net metering, 279, 281 nuclear energy: Atoms for Peace plan, 68–9; and the Chinese nuclear industry, 90; deregulation, 216; development of, 57, 68–9; international comparison of nuclear programme, 234; nuclear liability law, 253; power plant construction, 215, 216–17, 220–1, 225, 230; reactor technology, 233; regulation, 157–8; small modular reactors, 258; Three Mile Island accident, 222; VC Summer power station, 217, 225; Vogtle power station, 217, 225, 226; Watts Bar II power station, 217 nuclear weapons, 68 ocean thermal energy, 643–6 oil: dependence on, 57–8, 94, 96, 643–4; domestic production, 57, 330, 340, 643–4; intangible drilling costs, 74, 75; military usage, 93; OAPEC embargo, 57; percentage depletion, 75; shortages, 58; storage of crude oil, 330; tax breaks, 75; taxes on, 77 petrol taxes, 77 pollution, 60, 62 public benefit funds, 279, 281, 282 public opposition to energy projects, 546–8 renewable energy: biomass and biofuels, 58–9, 95–6, 282, 585, 641, 642, 675, 677–8; feed-in tariffs, 268; fuel cells, 59; hydropower, 302–6, 310–11, 670; incentive schemes, 76–7, 79, 81–2, 585; military use of, 95–6, 641–2; and net metering, 279, 281; ocean thermal energy, 643; public benefit funds, 279, 281, 282; renewable portfolio standards, 157, 278–82, 571; research and development, 69–72, 276; solar energy, 59, 84–7, 641; state-level initiatives, 278–82; subsidies, 644–6; tax breaks, 76–7, 81–2; transmission network integration, 79–83, 644, 645; wind energy, 76–7, 79–83, 546 research and development, 68–72, 276, 639–42, 667, 677 shale gas and oil, 99, 149, 326–8, 329–32, 333–7, 338–43, 347, 547–8 solar energy, 59, 84–7, 641

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715 solar rights, 84–7 sovereign wealth funds, 342–3 subsidies, 13, 644–6 sustainable development, 97–100 synthetic fuels, 58–9, 95–6 tax breaks, 65, 73–7, 81–2 taxation, 73–8, 346 technological innovation, 62–7, 639–42 Three Mile Island accident, 222 tobacco, 348 transmission networks, 46, 79–83, 547, 644, 645 water management, 97–100 water rights, 311 wildlife protection, 304, 305, 624–9 wind energy, 76–7, 79–83, 546 United States Chamber of Commerce, 89 United States Geological Survey (USGS), 341, 537–8 United States Outer Continental Shelf, 643–4 Utah, 362, 625 Vachon, S., 280, 281 VC Summer power station (US), 217, 225 Veba, 490 vehicle-to-grid (V2G) cars, 197–201 vertical integration see unbundling Vestas, 288–9, 291 VEW, 490 Viag, 490 Vienna Convention on Nuclear Liability, 243–7, 249–50, 252, 254 virtual emission reductions (VER), 272 Vogtle power station (US), 217, 225, 226 vulnerable consumers, 115, 396–9; see also energy poverty Wales see United Kingdom Walker, Gordon, 459 Washington, 625 waste energy from, 141, 143–4, 598 management of, 143–4 water contamination, 332, 333–7, 340–1 water heating, 401–3 water management, 97–100, 630–5 water power see hydropower; wave energy water rights, 311 water scarcity, 98, 630–5 water subsidies, 531 Watts Bar II power station (US), 217 wave energy, 190, 312, 522

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716

DELIVERING ENERGY LAW AND POLICY IN THE EU AND THE US

Weimann, Joachim, 265–7 West Virginia, 343, 344, 347 West Virginia Future Fund, 343 Western Energy Alliance, 332 Westinghouse, 225, 230, 233, 523 Whitmarsh, Lorraine, 458 Wholesale Electricity Market Administration Company (Argentina), 534 wholesale markets, 429–36 Wild and Scenic Rivers Act (US), 304 wildlife protection, 304, 305, 624–9 wind energy Arctic, 387 Argentina, 535 cooperative investment, 6 Denmark, 6 developing countries, 72 European Union, 283–7 Finland, 141, 143 Germany, 130, 132, 289–90 transmission network integration, 79–83, 167 Ireland, 167, 202, 203, 554, 557 marginal costs, 181 Norway, 315–16 offshore wind farms, 143, 166, 289–90, 312, 315–16 output variability, 168, 169, 310 and planning regulations, 291 production tax credits, 74, 76–7 public opposition to projects, 546, 554, 557

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research and development, 70, 284–7 Russia, 319 Spain, 616 susceptibility to climate variability, 189 tax breaks, 76–7, 81–2 turbine manufacture and installation, 288–91 United Kingdom, 166, 290–1, 564, 598 United States, 76–7, 79–83, 546 see also renewable energy Winzer, C., 469 Wood, Sir Ian, 367–8 Woolgar, Steve, 10 World Bank, 14, 274, 510, 593 World Energy Outlook (IEA), 21, 98, 99, 460, 468, 664 World Health Organization (WHO), 393, 406 World Nuclear Association (WNA), 215, 216, 239–40 World Trade Organization (WTO), 148, 474–5, 476 World War II see Second World War Wyoming, 332, 344, 362, 625, 627, 629 Xi Jinping, 89, 91 Yeltsin, Boris, 478 Yin, H, 280, 281 Zhou Enina, 91

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