Handbook of Energy Politics 1784712299, 9781784712297

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HANDBOOK OF ENERGY POLITICS

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This book is dedicated to Miranda Considine, Melvin A. Conant, William A. Kerr and Alex Kemp, whose commitment, dedication and support have been invaluable throughout the years.

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Handbook of Energy Politics

Edited by

Jennifer I. Considine University of Dundee, UK

Keun-Wook Paik Oxford Institute for Energy Studies, UK

Cheltenham, UK • Northampton, MA, USA

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© Jennifer I. Considine and Keun-Wook Paik 2018 All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, ­mechanical or photocopying, recording, or otherwise without the prior ­permission of the publisher. Published by Edward Elgar Publishing Limited The Lypiatts 15 Lansdown Road Cheltenham Glos GL50 2JA UK Edward Elgar Publishing, Inc. William Pratt House 9 Dewey Court Northampton Massachusetts 01060 USA

A catalogue record for this book is available from the British Library Library of Congress Control Number: 2017960002 This book is available electronically in the Social and Political Science subject collection DOI 10.4337/9781784712303

ISBN 978 1 78471 229 7 (cased) ISBN 978 1 78471 230 3 (eBook)

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Typeset by Servis Filmsetting Ltd, Stockport, Cheshire

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Contents List of contributors Foreword Jennifer I. Considine and Mary Lashley Barcella Acknowledgements Introduction Jennifer I. Considine

vii ix xxviii xxix

PART I THE FUNDAMENTALS OF THE GLOBAL ENERGY INDUSTRY: THE SUPPLY SIDE   1 Environmental and Indigenous issues associated with natural gas development in British Columbia Anna Vypovska, Laura Johnson, Dinara Millington and Allan Fogwill

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  2 Oil on the waters of RIC energy relations Nina Poussenkova

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  3 Energy transition and natural gas development in China Liu Xiaoli and Tian Lei

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  4 Institutions and the supply of oil Douglas B. Reynolds

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  5 Low oil prices impact on Latin American non-conventionals Alberto Cisneros Lavaller

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PART II THE FUNDAMENTALS OF THE GLOBAL ENERGY INDUSTRY: THE DEMAND SIDE   6 The role of Sino-Russian gas cooperation in China’s natural gas expansion Keun-Wook Paik

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  7 Republic of Korea’s energy security conundrum: the problems of energy mix and energy diplomacy deadlock Se Hyun Ahn

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  8 China’s evolving energy policy: the case of electricity Philip Andrews-Speed and Sufang Zhang

179

v

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vi   Handbook of energy politics   9 Natural resource-led development in Sub-Saharan Africa: a role for local content and small, medium enterprises Rene Roger Tissot

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PART III  MAIN INFLUENCES IN GEOPOLITICS 10 Will there ever be a post-oil era? Mamdouh G. Salameh

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11 The Oil Age Colin J. Campbell

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12 New energy and the geopolitics of the future Michael Lynch

276

13 The economic case for staged development and providing appropriate incentives for good behaviour in the context of ‘resource curse’ Paul Stevens and Jennifer I. Considine

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PART IV THE EVOLUTION OF TECHNOLOGY, CAPITAL AND FINANCIAL MARKETS IN THE ENERGY INDUSTRY 14  Deepening green finance Hazel Henderson

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15 Middle East and Asia: the oil trade and pricing nexus Tilak Doshi

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16 The economics of the smart grid technological innovation Luciano de Castro, Joisa Dutra and Vivian Figer

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PART V ENVIRONMENTAL ISSUES AND RENEWABLE ENERGY POLICY 17 Policy risk, politics and low carbon energy Geoffrey Wood 18 Governing the geopolitics of climate action after the Paris Agreement Lara Lázaro-Touza

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Index

483

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Contributors Se Hyun Ahn, Professor of International Relations at the University of Seoul, South Korea. Philip Andrews-Speed, Energy Studies Institute, National University of Singapore, Singapore. Mary Lashley Barcella, former Director North American Natural Gas, IHS CERA, USA. Colin J. Campbell, the originator of the concept of ‘peak oil’ with the article that he wrote in 1998 in Scientific American, together with Jean Laherrere. He was the founder of the Association for the Study of Peak Oil (ASPO) and is now retired and living in Ireland. Luciano de Castro, Department of Economics, University of Iowa, USA. Jennifer I. Considine, Senior Research Fellow, CEPMLP, University of Dundee, Scotland. Tilak Doshi, Managing Consultant at Muse, Stancil and Co. (Asia) based in Singapore. Joisa Dutra, Centro de Regulação e Infraesturtura, Fundação Getúlio Vargas (FGV), Brazil. Vivian Figer, Researcher at the Center for Regulation in Infrastructure in Fundação Getúlio Vargas, Rio de Janeiro, Brazil. Allan Fogwill, President and CEO, Canadian Energy Research Institute, Calgary, Alberta, Canada. Hazel Henderson, DSc Hon, FRSA, President, Ethical Markets Media, St. Augustine, Florida, USA. Laura Johnson, former Researcher, Canadian Energy Research Institute, Calgary, Alberta, Canada. Alberto Cisneros Lavaller, CEO/President Global Business Consultants, Member Geopolitics of Energy Editorial Committee, Caracas, Venezuela. Lara Lázaro-Touza, PhD, Senior Analyst, Energy and Climate Change Programme. Elcano Royal Institute Lecturer of Economic Theory at CES Cardenal Cisneros. vii

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viii   Handbook of energy politics Liu Xiaoli, Research Professor, Energy Research Institute (ERI), National Development and Reform Commission (NDRC), China. Michael Lynch, President at Strategic Energy and Economic Research Strategic Energy and Economic Research, Massachusetts Institute of Technology, Springfield, Massachusetts, NY, USA. Dinara Millington, Vice President, Research, Canadian Energy Research Institute, Calgary, Alberta, Canada. Keun-Wook Paik, Senior Research Fellow, Oxford Institute for Energy Studies and Associate Fellow, Chatham House, London, UK. Nina Poussenkova, Senior  Researcher, Primakov Institute of World Economy and International Relations, Russian Academy of Sciences; Researcher, ENERPO Center of the European University in St. Petersburg. Douglas B. Reynolds, Professor of Economics, University of Alaska, Fairbanks, Alaska, USA. Mamdouh G. Salameh, Visiting Professor of Energy Economics at the ESCP Europe Business School, London, UK. Paul Stevens, Distinguished Fellow, Chatham House, London. Tian Lei, Research Associate, Energy Research Institute (ERI), National Development and Reform Commission (NDRC), China. Rene Roger Tissot, Senior Consultant, Rene Roger Tissot Consultant, CMA British Columbia, Canada. Anna Vypovska, Researcher, Canadian Energy Research Institute, Calgary, Alberta, Canada. Geoffrey Wood, Teaching Fellow in International Energy Law and Policy, Stirling Law School, Stirling, UK. Sufang Zhang, School of Economics and Management, North China Electric Power University, Beijing.

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Foreword

Jennifer I. Considine and Mary Lashley Barcella1

In a tribute and memorial to Melvin A. Conant, the authors reprint below two articles from his publication, Geopolitics of Energy. The first article, “The geopolitics of oil” (Conant, 1994), was written as he retired from his position as editor of the publication. In it he defines the term “geopolitics” and gives a general outline of the factors affecting the primary energy sources that are vital for the well-being and security of developed and developing nations around the globe. These factors include the location of energy sources and strategic reserves; domestic and foreign government policies affecting energy supply and distribution; price; anticipated demand and supply and the geopolitics of choice for importers and exporters alike; and a host of other important considerations listed in detail further on. Although the articles were written well over 20 years ago – and did not foresee the emergence of technologies such as hydraulic fracturing that have enabled a renaissance in US tight oil and natural gas production – they nevertheless have significant relevance to contemporary issues in the geopolitics of energy, drawing the reader’s attention to the global supply and demand balance, US special relationship with Saudi Arabia, East Asian supply prospects, tension in the Gulf and the role of Russia. The second article, from 1979, is an insightful analysis of US energy politics that shows how little has changed in US energy and environmental policymaking in the last 40 years.

THE GEOPOLITICS OF OIL2 MELVIN A. CONANT3 Oil is high profile stuff, for it fuels much more than automobiles and airplanes. Oil fuels military power, national treasuries, and international politics. Because of this it is no longer a commodity to be bought and sold within the confines of traditional supply and demand balances. Rather, it has been transformed into a determinant of well-being, of national security and international power for those who possess this vital resource, and the converse for those who do not. Robert E. Ebel4

ix

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x   Handbook of energy politics This is the opportunity for your retiring Editor to reassess the importance of the geopolitics of energy – most particularly of oil – in light of changes in international politics and the oil system over the past 20 years. Most important is the peaceful ending of the Cold War. Next is the resurrection of private oil companies’ investing internationally, and then the proliferation of “privatization” commitments when only two decades ago, OPEC members had ousted private international oil companies everywhere from their upstream sector as they had earlier from their downstream. Then, one has to recognize the changes in how oil is priced and the expanded influence of international financial markets on oil trades. The number of “dry” barrels sold/bought can be misleading for it is the number of “wet” barrels exchanged which count in terms of oil geopolitics. The concept of oil “geopolitics” embraces a host of considerations: location; sovereignty; domestic and foreign government policies affecting exploration, development, and access to oil itself; price, and therefore such considerations as revenue to the state and return on investments to private enterprise; a government’s objectives in relations with other countries and companies; and, in a larger sense, anticipated demand and supply and the geopolitics of choice for importers between sources of oil and alternative fuels whenever available. Politics becomes a factor whenever and however a government chooses to act with respect to its own assets or intervenes in those of another state. While oil geopolitics is often referred to in terms of suppliers, it should never be forgotten that whatever the policies and actions of oil import dependent consumer states – especially OECD countries – insuring their access to oil remain of highest importance. The key example is, of course, the U.S. special relationship with Saudi Arabia. Nor can it be forgotten that increasing oil demand, almost everywhere but especially in East Asia, has stark implications for the Middle East Gulf countries and Venezuela, which are destined to play an even larger role in providing oil to the world. The IEA foresees such “an explosive growth in import dependence by the industrialized nations and by the rapidly growing Asian economies . . . that by 2010 these countries may require 27 MMB/D more oil from the Middle East and Venezuela than they do today.”5 China is now assumed to be among those countries certain to become dependent on the Gulf and the time is rapidly approaching when India will be on the list as well. Herein lies the continuing relevance of geopolitics. There is no reasonable expectation that huge discoveries, greater expenditures on alternative fuels, or much greater efforts at conservation or environmental controls will profoundly alter this prospect within the next decade and a half. Accordingly, given the rivalries between key Gulf producers, the United

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Foreword  ­xi States will have to perform as the “policeman of the Gulf,” to defend both its own interests in the region’s oil and the interests of its allies – such as Europe and Japan – in assuring their own supplies from the Gulf. With this outlook, producers have concerns about the motives and tactics of neighboring states; some of them are suspected of territorial ambitions including seizure of oil fields and pipelines. Against such threats a producer may want to forge political and security alliances with other states, most notably with the United States, which today is virtually alone in being able to provide the force needed to keep the peace. It is likely there will be a continuing U.S. presence in the Gulf; what is certain is continuing change in relations among the key producers, and between key producers and the United States. As a practical matter, the United States will be the “policeman of the Gulf” for as long as the American public is willing to perform that role – a crucial qualification. Each of these factors has long-term importance. From time to time, any one of them can become more or less important depending on changing circumstances. Still, the fundamentals of geopolitics remain constant and should never be assumed to have disappeared. In short, “geo” refers to the location of oil reserves; “politics” reflects the decisions of importing and producing governments affecting access to supplies. The basic ingredients will always be a mix of politics, economics, and security objectives. All of the factors have to be kept in mind since overlooking one or more may invite serious trouble. The most basic of geopolitical factors rest on judgments as to present and future sources and volumes of oil production. Every few years, Joseph P. Riva, Jr. has provided readers of Geopolitics of Energy with his expert appraisal of likely trends in the finding of oil and, with larger sources in mind, how long a producer is likely to remain a major actor. (See his “Current World Oil Status” in Geopolitics of Energy, May 1, 1994.) Table I.1 illustrates the foreseen change in the roster of suppliers. The basic facts about the geopolitics of oil are on this list. The oil importing nations know their reliance on imported oil will include the largest producers over the next 50 to 100 years, and longer, with the greatest concentration in the Middle East. Very few of the producers, if any, will put their trust in simple “market forces,” hence the continuing importance of political decisions and relationships affecting the availability of exporters’ oil in times of peace or of emergency. Most larger oil exporters will seek to affect oil price through some form of cartel action, particularly if the number of OPEC members shrinks. How these producers interact will vary from time to time: how key importers deal with the larger oil producers will also vary. But in most cases, oil exporters’ strategies will aim for higher oil prices and/or reserved market shares, and they will not be

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xii   Handbook of energy politics Table I.1 Sustainability of current oil production 1994 The Next 10 Years

The Next 50 Years

The Next 100 Years

Longer

United States Canada United Kingdom Australia Trinidad Angola Indonesia• Colombia Egypt Argentina Norway Ecuador Oman

Brazil Russia Malaysia Qatar• Algeria• Nigeria• India China Ukraine Libya• Brunei Romania

Azerbaijan Yemen Mexico WORLD Iran•

Turkmenistan Uzbekistan Kazakhstan Venezuela Saudi Arabia UAE Iraq• Tunisia Kuwait

Note: • OPEC Members Aggregate sustainability of total current world oil production, assuming continuous effi production

above using statecraft to achieve that objective when reliance on “market forces” is not seen to satisfy their needs and political ideologies. Yet even here conflicts are ever-present. The needs of a heavily populated Iran, for example, will not be satisfied by tactics which could meet the requirements of thinly populated Saudi Arabia. Well beyond the end of the twentieth century the Middle East Gulf will be the largest repository of conventional crudes, with the natural gas reserves of Iran and the Arab Gulf second only to those of the former Soviet Union. Supplies of both fuels are far beyond the capacity of most producing countries to consume. The Gulf will thus remain the largest source of internationally traded oil (and perhaps of natural gas) and, at the same time, an area of politically troubled inter-governmental relations, even wars – the essence of geopolitical concerns over unimpeded access to cheap and ample petroleum. From 1960 to 1980, the OPEC challenge to the pivotal role of large international oil companies was surely dramatic, but only some 15 years later the imperative of lower oil prices and consequent economic and political changes began to reintroduce to producing governments the value and utility of the technology and money of foreign private oil enterprises. In itself, this has begun to alter oil geopolitics. It remains uncertain how

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Foreword  ­xiii this new situation might be affected if oil prices should reach a sustainable level of $22/B or higher. The Impact of U.S. Policy The outstanding example among oil importers of geopolitical factors affecting oil is the political failure of the United States to address the issue of its dependence on imported oil. That failure has led the United States to be continuously involved in Gulf politics and security issues involving variously Iran, the countries of the former Soviet Union, Egypt, Israel, Lebanon, Iraq, Kuwait, and Saudi Arabia. The civil war and continuing instability in Yemen will be of growing concern to Saudi Arabia, and Yemen’s location at the southern entrance to the Red Sea will be of concern to international oil trade from the Gulf to the Mediterranean. Were there less need for the region’s oil, the United States might never be so deeply implicated. But because the U.S. government has not more actively encouraged other sources of supply – in the western hemisphere, for example – its dependence, and that of its allies, on the Gulf seems likely to be unaltered, with consequent heavy demands on U.S. military readiness (which serve to limit the freedom of its actions elsewhere). How likely is it that the United States will deal with the consequences of its dependence on oil imports? Not very likely at all. There is no comprehension by U.S. citizens of the risks and costs of its situation. With the real price of gasoline lower than in 1980, with no interest in higher taxes on energy consumption and no sufficient interest in energy alternatives, the President must have been advised to put his mind on other matters. Not even the war with Iraq was seen to have politically unacceptable costs. Consequently, current estimates of U.S. oil imports warn of a need for 12.8 MMB/D by 2010 (compared to 8.1 MMB/D currently). If the United States were to move more actively to develop oil sources to replace its dependence on the Gulf, Venezuela and Canada would be the leading candidates. These countries’ increasing extraction of unconventional crudes for export to the United States as well as to Europe and to the Far East (in the case of Venezuela) could make a crucial difference. The United States has for years avoided any clear special relationship with either producer largely because it saw no need to tie itself to “preferential” sources and partly, at least in Canada’s case, because the United States has assumed their conventional and unconventional crudes may have no other market. On the other hand, Japan has shown interest in both Canadian and Venezuelan unconventional crudes as a potentially important further diversification of its crude supplies.

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xiv   Handbook of energy politics East Asian Supply Prospects Geopolitical oil issues remain important to Japan and are becoming increasingly so to China as it faces the prospect of securing growing oil imports from the same Middle East Gulf on which other nations now depend. Furthermore, competition among countries of East Asia for dwindling exports from Southeast Asia will bring geopolitical factors onto the scene as happened before World War II. The further diversification of energy sources will remain among Japan’s highest priorities with geopolitics dictating sources away from the Gulf (e.g., East Siberia and the western hemisphere) and out of China’s reach. As for China, the oil potential said to underlie the South China Sea could likely be of increasing importance in a future conflict with Vietnam. (The latter has already made clear that its claim to these prospective reserves is “non-negotiable.”) Or will the Tarim Basin of western China prove to be hugely prolific? It is too soon to count on this new source of urgently needed oil but its location along inner-Asian frontiers will be of special geopolitical importance to Russia and China alike. The Role of Russia As various proposals are reviewed to link Russian-controlled oil and gas pipelines to East Asia, the web of pipelines now under consideration for moving supplies eastward suggests a renewed Russian influence across EurAsia, long a goal of the previous Soviet Union. Moreover, the question of transporting oil and gas from the southern republics of the former Soviet Union through Iran and/or Turkey is patently of long-standing security and political importance to Russia. Oil and gas from the former Soviet Union is also of singular importance to Europe, despite Russia’s current difficulties in maintaining production and the attendant risk that exports could yet be curtailed. Some countries – notably the United States – once anticipated that a growing European dependence on Soviet exports could give rise to serious security risks. Yet, in less than a decade, the industrial importing nations seek ways to shore up Russian production and exports. And there are serious difficulties in that respect. Robert Ebel warns: A weakened Russian oil industry cannot begin to offer any alternative to Middle East oil. Nor can it lead to economic reform in that country. Economic rejuvenation generally is not thought likely unless and until the health of the oil sector has been reasonably restored. A time of trouble would await if Russia, by virtue of continued oil production declines, would be forced to cut back on exports to hard currency markets. Not only would it be deprived of its leading

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Foreword  ­xv source of hard currency earnings, but more importantly the loss of a major world oil supplier, as Russia is and has been, carries particular political and economic implications for all.

The Problem of Stability Lies in the Gulf Still, the fundamental geopolitical factors inherent in Russian oil (and gas) remain unchanged: Russia is a major source of oil and gas away from the Gulf, it has often been a source of less expensive oil than OPEC, and it has for the most part been a reliable supplier. Had the OPEC cartel been able to pursue single-mindedly the goal of either higher prices or of higher market shares, world oil importers (indeed consumers everywhere) would have had an additional and urgent geopolitical goal: to crack the cartel itself through the discovery and development of very large reserves elsewhere. As it is, the difficulty confronting key producing-exporting nations of the Gulf – now the heart of OPEC – is (1) how to accommodate their geopolitical rivalries, especially in the case of Iran, Saudi Arabia, and Iraq, whose antagonisms have deep historical roots; and (2) how each country can enlist in its defense the support of the United States or counter the influence of the United States if it backs a rival. (Today, the United States confronts both Iran and Iraq, while it is supportive of Kuwait and Saudi Arabia.) While each of these producers is in favor of higher oil income, their political and security actions continue to frustrate the linking of their otherwise common interests. They can probably not resolve their other basic division: the difference between members with large low-cost oil reserves and those with higher costs and shrinking reserves. Moreover, a key factor in the Iraq-Kuwait confrontation was the latter’s continuing to produce at high volume in disregard of the impact upon the oil revenue of the former. None of these geopolitical aspects of world oil demand can be masked, or eclipsed altogether, by “market forces,” although the United States has for many years urged producers and importers to consider market forces as the most basic determinant of supply and demand. Yet the United States has often led in adopting domestic political policies aimed at shielding its producers from foreign competition – still another form in which politics affects international oil trade. Throughout this century there have been at least 20 occasions on which the nation has adopted restrictive policies and legislation which affected the terms of oil trade. While these interventions were most often labeled political acts in the interest of “national security,” their true intent was to shore up the domestic oil price (often with similar effects on prices everywhere, given the scale of U.S. oil demand). For reasons referred to earlier, it is unlikely that the United States will

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xvi   Handbook of energy politics address its import dependence. It will rather remain vulnerable to overseas crises. The situation is different for Russia, whose range of options is considerably wider due to its totally different energy situation. This difference is summarized succinctly by Robert Ebel: The US, the world’s most powerful nation, must import 48% of the oil it consumes. Russia, arguably the number two power in the world, despite its travails, in 1993 was able to send 52% of the oil it produced to buyers beyond its boundaries.

The geopolitical implications of Russia’s oil situation loom very large and have significant historic precedence. During World War II, oil geopolitics quickly became a major force behind German moves into southern Russia, as it did in Russian determination to keep German forces out of the Caucasus. Scarcely had that war ended when Russia moved to solidify control over Azerbaijan. Russian forces on the Iranian border threatened incursions from the north toward the oil wealth of Iran and the Gulf. U.S. action was the key factor in limiting Russia’s moves southward. Until the 1980s, Russia had no need for access to Middle East oil, though it did develop tactics designed to destabilize relations between oil producers and importers, and in particular with the United States, against a background of historic interest in securing access to the Gulf and the Indian Ocean. Countering US influence in the region, the Russians turned Iraq, a leading oil exporter, into their ally in the Gulf. Changes in the top leadership in both countries in the late 1980s enabled the United States and the then-Soviet Union to reach a private understanding that neither of the superpowers would challenge the other’s vital interests in the Middle East. For a time at least, access to Gulf oil was not at risk. While Russia has continued to observe that understanding, political change within the Kremlin could alter its policies toward the Gulf and the United States. Moreover, oil importing nations are currently watching Russian moves toward former Soviet republics whose geographical location and expectations of oil and gas reserves are clearly of interest to the Kremlin, and several of these new republics will have contacts in the Gulf. Realistically there is for the near term little prospect that Russia will have the military capabilities to threaten an industrial oil importer’s access to Middle East oil. However, Russian forces could again impress upon the Caucasus and Central Asia its historic imperative to be in control of these borderlands. Russian tactics in the Middle East may again be troubling to the United States and other key importers. In April of this year, for example, Russia concluded a “defensive” arms deal with Syria citing the arms deliveries of the United States to Israel. The geopolitics of the Gulf are like a shadowy presence in world affairs, never absent.

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Foreword  ­xvii Regional Trouble Spots There appears to be a growing consensus that future wars are likely to be regional in scope. However, regional wars can implicate oil supplies in the same way as larger wars. The case of Iraq’s attack on Kuwait is an example. In the event of another regional war in the Gulf, it cannot be assumed the United States would always deploy its forces on a similar scale as it did to push Iraqi forces back. And if the United States did not do so, there may be no other military power which could, particularly with Russia believed to be presently incapable of moving to the defense of a regional state under attack. Similarly, in the case of a divided Yemen, Saudi Arabia may consider an intervention to remove the risk that troubles on any Saudi border could escalate, leading to vulnerabilities for the Kingdom. Since it has appeared likely that new-found oil revenues for Yemen would pay for weapons with which to confront the Kingdom, geopolitical concerns could move Riyadh to attack. In a similar situation, border warfare in Central Asia has to be anticipated if prolific reserves are found in the Tarim Basin. Similarly, geopolitical factors – a mix of history, imperialism, and a desire for additional oil revenue on the part of Britain and Argentina – could lead again to a repeat emergency in the Falkland Islands if oil in large quantities is actually found in the vicinity. These examples are of varying risk to oil interests but cannot be ruled out. The Evolving Picture of Oil Geopolitics In many places access to oil can be greatly complicated by the domestic and international political acts of governments. The ability of smaller oil enterprises to affect these actions is normally not very great. Yet the work of companies can be seriously compromised or delayed by government actions. Large oil companies, with “deep pockets,” have a greater capability to sit out some of these situations. But oil companies usually have exploration possibilities elsewhere and may act on them to the eventual detriment of countries that play the geopolitical “game.” If one should want to see the evolving picture of oil geopolitics one cannot do better than look at the implication easily drawn from the IEA report referred to in Table I.2. From this table, we are told that in the decade between 2000 and 2010, oil supplies from the Middle East Gulf and Venezuela are forecast to rise from 31 MMB/D to 43.4 MMB/D; while OECD production declines from 15.2 MMB/D to 14.2 MMB/D, and while demand in the rest of the world increases from 22.1 MMB/D to 32.8 MMB/D. This forecast puts the geopolitics of oil in the clearest light: the

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xviii   Handbook of energy politics Table I.2  IEA oil demand and supply forecast 2000 ln MMB/D OECD Ex-USSR/East Europe Mideast & Venezuela Rest of World Total•

Demand•

Chg. vs. ‘91

Supply

Chg. vs. ‘91

42.8 7.7 4.4 22.1 77.3

+4.5 −1.9 +1.0 +6.6 +10.2

15.2 8.3 31.0 21.1 77.3

−1.0 −2.4 +12.4 +1.0 +10.0

Note:  Total demand includes stockbuilds of 300,000 B/D. Total supply includes processing gains of 1.7 MMB/D in 2000 and 1.9 MMB/D in 2010

Middle East Gulf is even more certain to be the cockpit of oil rivalry which will not be resolved through free market practices. If it is manageable at all, it will be through durable agreements reached at long last by key OPEC and non-OPEC suppliers. To achieve that, one has to assume a far more successful effort than we have known to date at a producers’ system of quotas or a managed parcelling out of market shares. Furthermore, such would require cooperation between producer and consumer governments which Hermann Eilts tells us in his accompanying article (“Petroleum and the New World Order”) is improbable. Otherwise, we must assume a consistent, long-term, and successful effort on the part of OECD, South, and East Asian nations to reduce sharply their rate of growth of oil consumption which appears unlikely. The significance of this transcends all other considerations. OECD states, Russia and its borderland republics, East Asia, and India will all be implicated, and undoubtedly will still be dependent on some nation – perhaps, but not assuredly, the United States – to be the “policeman of the Gulf.”

THE US ENERGY SCENE MELVIN A. CONANT6 There was a time, not so long ago, when the making of energy policy in Washington was a simple process. If a problem arose, small delegations came to town for discreet conversations with LBJ, Sam Rayburn and Bob Kerr, which usually took care of it. Under this regime, depletion allowances flourished, pro-rationing thrived, and oil imports were restricted. The old order was beginning to change even before its guardians were

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Foreword  ­xix departing the Washington scene. But energy policy has never been the same since the decline of domestic production, the rise of the OPEC cartel and, finally, the Arab embargo. No longer are energy decisions dictated by a handful of men operating on Capitol Hill or from the White House. To the outside observer, the energy policy process today appears to be a wild free-for-all, a gigantic floating crap game with increasingly high stakes. Behind these policy struggles lies an enormous diversity of interests and fundamental differences in economic, political, and philosophical outlooks. These include basic disagreements about the success of the free enterprise system, the merits of Federal intervention in the marketplace, and the virtues of undisciplined economic growth. On closer analysis, there is also a large measure of geography and politics at the root of every policy debate. In essence, notwithstanding a common nationality, a common language and a common government, we see within the U.S.A. a replay of the geopolitical conflicts of interests which take place between producers and importers within the community of nations. No Unity on Energy The conflicts in energy interests stem from the different situations of the fifty states. Some states are rich in energy sources, others are not. Some have oil but no coal, others coal but no oil. Some have high sulphur coal, some low sulphur coal. Some rely heavily on hydro-power, others on nuclear power. Some are import dependent, others not. Some have unique natural resources which stimulate environmental concerns, others do not. These are some of the factors which are having a major influence on national energy policy. These differences are clearly reflected in Presidential energy messages offering tax exemptions for gasohol for the farm belt, coal cleaning projects for Appalachia, solar projects for the Sunbelt, and tax credits on wood stoves for frugal New Englanders. Politics of Energy The nation’s diverse energy needs show up increasingly in Congressional debates. For example, Congressmen from Eastern coal producing states were greatly concerned that tough environmental regulation would put their coal at a competitive disadvantage with lower-sulphur Western coal. This concern finally led to the statutory requirement that all coal-burning power plants install costly scrubbers, no matter what the sulphur content of the coal involved. A refinement of this approach was developed by Ohio’s Senator Metzenbaum in a further effort to protect Ohio’s high-sulphur coal. He

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xx   Handbook of energy politics inserted an innocuous amendment in the Clean Air Act authorizing EPA intervention to avoid economic disruption which might be caused by using coal which was not “locally or regionally available.” This may now be interpreted to force Ohio utilities to use Ohio coal, instead of buying low-sulphur coal from neighboring or Western states, to comply with the Clean Air Act. These concerns are not always focused on fostering the use of state or regional resources. In the Northwest, for example, the obvious desire is to protect low-cost hydro-power from exports to other states. In California, environmental interests have dominated energy development, as recent energy facility siting decisions make clear. United New England New England is best organized to deal with energy. Lacking any resources, highly dependent on costly imports, New Englanders became aware of energy problems even before the embargo. Their Congressional delegation has organized into an effective bipartisan coalition pushing hard for programs like small-scale hydro-power and regional strategic oil reserves. The New England delegation has been instrumental in fighting representatives of producing states on critical issues of oil and natural gas pricing policy. It was not surprising that New Englanders, resource poor and import dependent, would fight for the benefits of low-cost, pricecontrolled domestic oil and gas. Much of this battle has centered on the entitlements program which was designed to equalize costs between those refiners who had access to more low-cost U.S. oil and those who were more dependent on high-cost imports. During the Ford Administration, the New England delegation succeeded in securing 30 percent entitlements treatment for importers of residual fuel oil on which the region is heavily dependent. This meant that New England importers of “resid” were in effect paid a subsidy by the rest of the country. In 1977 the delegation sought to increase this subsidy to 100 percent and a major confrontation took place. After the Senate Energy Committee voted 17–1 against increases in entitlements for “resid,” the New Englanders were forced to back down and compromise. No National Unity on Energy All of this maneuvering may be grist for the pundits, but it has done little to encourage the development of sound energy policies. An inordinate amount of time and talent – both Congressional and Executive – has been devoted to catering to regional energy interests. Attention has been diverted from broader policy questions while debate has focused on

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Foreword  ­xxi the merits of entitlements and other tangential issues. In addition, the statutory product of energy confrontation and compromise has greatly complicated the regulatory process – the Natural Gas Policy Act of 1978 being only the latest example. Obviously, these political conflicts over energy have also adversely affected the process of achieving consensus on energy issues. In the absence of strong Presidential leadership, these conflicts have flourished at the expense of broad agreement on what should be done to meet national energy needs. Perhaps this helps to explain why domestic energy production has remained essentially static since the Arab embargo while U.S. dependence on costly imports continues to increase.

TWENTY YEARS AND COUNTING Twenty years after Mel Conant wrote his path-breaking article, “The geopolitics of oil” and over 38 years after his short note on the “US energy scene,” the historic and geopolitical forces outlined by these discussions are still relevant. As noted by Conant, in the mid-1990s the Middle East was the predominant source of oil for the United States. While the Middle Eastern producing nations had the potential to lose ground to Canada and Venezuela – even Africa – that was considered to be unlikely given the political environment at the time. In his own words: China is now assumed to be among those countries certain to become dependent on the Gulf and the time is rapidly approaching when India will be on the list as well. Herein lies the continuing relevance of geopolitics. There is no reasonable expectation that huge discoveries, greater expenditures on alternative fuels, or much greater efforts at conservation or environmental controls will profoundly alter this prospect within the next decade and a half.

Many of these predictions have been proven true, and moving forward geopolitical concerns remain. To cite only a few examples: estimates of US oil imports warned of a need for 12.8 MMB/D by 2010. This was a surprisingly accurate prediction, well over 15 years later US gross oil imports were estimated at approximately 11.8 MMB/d in 2010 a difference of only 1 MMB/d.7 Since that time, the share of OPEC imports to the United States has declined gradually, with the US moving to develop its own oil reserves. At the time of writing, gross imports are approximately 10.06 MMB/d, with net imports accounting for approximately 25 percent of US crude oil consumption (see Table I.3).8

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xxii   Handbook of energy politics Table I.3  US petroleum imports 2016 Top sources and amounts of US petroleum imports (percent share of total), respective exports, and net imports, 2016 million barrels per day Import sources Total, all countries OPEC countries Persian Gulf countries Top five countriesa Canada Saudi Arabia Venezuela Mexico Colombia Note: 

Gross imports

Exports

Net imports

10.06 3.45 (34%) 1.76 (18%)

5.19 0.22 0.02

4.87 3.23 1.74

3.80 (38%) 1.11 (11%) 0.80 (8%) 0.67 (7%) 0.48 (5%)

0.87 0.00 0.08 0.88 0.15

2.93 1.10 0.72 −0.21 0.34

Based on gross imports by country of origin

a 

Source:  FAQ – US Energy Information Administration (EIA)9

In 2016, Canada was the largest source of US petroleum imports at 38 percent, followed by Saudi Arabia at 11 percent, Venezuela at 8 percent, Mexico at 7 percent and Colombia at 5 percent.10 Saudi Arabia is listed among the top three suppliers of crude oil to China, India, the United States and Japan. Last but by no means least, the United States has made some progress in the diversification of its oil imports but maintains its special relationship with Saudi Arabia for the longer term. According to IEA analysts, the Middle East share in global oil production in 2016 reached its highest level in 40 years.11 At the same time, despite significant gains in renewable energy supply the demand for oil continues to grow, albeit at a slower pace, with increased demand for oil to fuel petrochemicals, aviation, freight and maritime industries outpacing declines in oil consumption for power generation, buildings and passenger cars. Approvals for new conventional crude oil projects have fallen to the lowest level since the 1950s. In the United States, tight oil is not expected to cover an impending “major shortfall in the ‘baseload’” of oil supply. In fact, the boom-and-bust cycle for crude oil supply continues to be a fact of life, although the situation has been complicated by the switch to renewable energy supplies and efficiency improvements in the electricity industry, and by major technological changes and speculation in the futures and financial markets (see Figure I.1). Once again the basic facts about the geopolitics of oil are illustrated by

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Foreword  ­xxiii 20

United States

European Union

China

India

MMB/D

15

10

5

2014

2040

2014

2040

2014

2040

2014

2040

Net oil imports Reduction in net oil imports due to: Switch to electric and natural gas vehicles Efficiency improvements

Switch to renewables

Increase in oil production 2014–2040

Source:  IEA (International Energy Agency) (2016b) “World energy outlook 2016”

Figure I.1  Net oil imports Table I.4. While the number of producing companies with over 50 years of sustainable production has declined with the passage of time, global proved oil reserves have risen from 1,126.2 thousand million barrels in 1995, to 1,697.6 thousand million barrels in 2015 (see Figure I.2). OPEC countries continue to hold the largest share of global proved oil reserves at over 70 percent, 47.3 percent are located in the Middle East. As pointed out by Mel Conant in “The geopolitics of oil”: The significance of this transcends all other considerations. OECD states, Russia and its borderland republics, East Asia, and India will all be implicated, and undoubtedly will still be dependent on some nation – perhaps, but not assuredly, the United States – to be the “policeman of the Gulf.”

The following chapters provide an update to the historical perspective questions and scenarios envisioned by Mel Conant more than 20 years ago.

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xxiv   Handbook of energy politics Table I.4 Sustainability of current oil production calculated as reservesto-production ratios 2016 The Next 10 Years

The Next 50 Years

The Next 100 Years Longer

United States Mexico Argentina Brazil Ecuador Peru Trinidad and Tobago Azerbaijan Italy Norway Romania Russian Federation Uzbekistan Oman Qatar Algeria Angola Republic of Congo Egypt Equatorial Guinea Gabon Nigeria Tunisia Australia Brunei China India Indonesia Malaysia Thailand Vietnam

Kazakhstan Canada Iraq Iran Kuwait Yemen Saudi Arabia United Arab Emirates Chad South Sudan

Venezuela Syria Libya

Notes:  Total proved reserves of oil – Generally taken to be those quantities that geological and engineering information indicates with reasonable certainty can be recovered in the future from known reservoirs under existing economic and operating conditions. The data series for total proved oil does not necessarily meet the definitions, guidelines and practices used for determining proved reserves at company level, for instance as published by the US Securities and Exchange Commission, nor does it necessarily represent BP’s view of proved reserves by country. Reserves-to-production (R/P) ratio – if the reserves remaining at the end of any year are divided by the production in that year, the result is the length of time that those remaining reserves would last if production were to continue at that rate. Source of data – The estimates in this table have been compiled using a combination of primary official sources, third-party data from the OPEC Secretariat, World Oil, Oil & Gas

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Foreword  ­xxv Table I.4  (continued) Journal and independent estimates of Russian reserves based on official data and Chinese reserves based on information in the public domain. Canadian oil sands “under active development” are an official estimate. Venezuelan Orinoco Belt reserves are based on the OPEC Secretariat and government announcements. Reserves include gas condensate and natural gas liquids (NGLs) as well as crude oil. Shares of total and R/P ratios are calculated using thousand million barrels figures. Source:  BP Global (2016a) “Statistical review of world energy, energy economics”

NOTES   1. Jennifer Irene Considine is a Senior Research Fellow at the University of Dundee, Scotland, and a Research Fellow at the King Abdullah Petroleum Studies and Research Center, Riyadh, Saudi Arabia. During her career as an energy economist, Dr Considine held positions at the Canadian Energy Research Institute, TransCanada Pipelines, Westcoast Energy, Coastal Corporation and ANR Pipeline Company. Dr Considine holds a PhD in resource economics from the University of Aberdeen, Scotland, and a MA in International Finance from the University of Chicago. In her career as an energy economist, Mary Lashley Barcella held positions at the American Petroleum Institute, American Gas Association, Conant and Associates and IHS CERA. She was privileged to work for many years with Melvin Conant, serving on the editorial board of Geopolitics of Energy. Most recently, she spent ten years as Director, North American Natural Gas at IHS CERA, publishing seminal studies on the economics and environmental effects of the unconventional oil and gas revolutions in the United States. Dr Barcella holds degrees in mathematics and economics from Vanderbilt University and the University of Maryland.   2. M.A. Conant (1994) “The geopolitics of oil,” Geopolitics of Energy, 16 (7), July 1, Washington DC: Canadian Energy Research Institute.   3. Melvin A. Conant worked for Standard Oil (Exxon Corporation) from 1961 to 1973 as a regional political advisor for the firm’s interests in East Africa, Asia, the Far East and Australia. He later served as senior government relations counselor for Europe, the Middle East and Asia. He was a US oil advisor at Law of the Sea Conferences in 1972, 1973 and 1977, and subsequently helped found the Council on Ocean Law. In 1973, Mel Conant was invited to help create the International Energy Affairs branch of the Federal Energy Administration. He was nominated by President Ford to be Assistant Administrator of the International Energy Affairs branch of the FEA. From 1976 until his death on December 11, 2003 he served as President and Director of Conant and Associates, Ltd. In that role he advised government and industry on the political aspects of international energy issues and was editor and publisher of the monthly international report Geopolitics of Energy. He also served as executive staff member of the Council on Foreign Relations and was Professor of International Security Affairs at the National War College. He was a member of the Institute for Strategic Studies, the Royal United Services Institution for Defense Studies in London, the Council on Foreign Relations and the Harvard University Visiting Committee for Astronomy and Astrophysics. He was Chairman of the Advisory Committee of the School of Advanced International Studies International Energy Program at The Johns Hopkins University. He was an Honorary Trustee of the Woods Hole Oceanographic Institute.   4. Mr Ebel – a leading oil analyst of the former Soviet Union and Russia – was a frequent contributor to Geopolitics of Energy. Paragraph extracted from his manuscript entitled Energy Choices in the Soviet Successor States published in the summer of 1994 by the Center for Strategic and International Studies, Washington, DC, subsequently published. R.E. Ebel (2004) “Russia – King of the oil hill?” CSIS, July 21.

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7.4

1995 Total 1,126.2 thousand million barrels

3.5

58.9

Europe & Eurasia Africa Asia Pacific

16.3

10.1

7.5

8.1

2005 Total 1,374.4 thousand million barrels

3.0

55.0

Figure I.2  Distribution of proved reserves in 1995, 2005 and 2015

Source:  IEA (International Energy Agency) (2016b) “World energy outlook 2016”

11.3

12.5

6.4

Middle East S. & Cent.America North America

Percentage

14.0

9.1

2015 Total 1,697.6 thousand million barrels

19.4

7.6

2.5

47.3

Foreword  ­xxvii   5. US Energy Information Administration (1994) “Annual energy outlook 1994,” DOE/ EIA 0383(94).   6. M.A. Conant (1979) “The US energy scene,” Geopolitics of Energy, 1 (3), 1–3, May, published monthly for the clients of Conant and Associates Ltd, Washington DC.   7. N. Nerurkar (2011) “US oil imports: Context and considerations.” Congressional Research Service, Library of Congress.   8. EIA (US Energy Information Administration) (2016a) “How much oil consumed by the United States comes from foreign countries? – FAQ.”   9 EIA (US Energy Information Administration) (2016b) “How much petroleum does the United States import and export? – FAQ.” 10. EIA (US Energy Information Administration) (2016c) “Oil imports and exports – Energy explained, your guide to understanding energy.” 11. IEA (International Energy Agency) (2016b) “World energy outlook 2016.”

REFERENCES BP Global (2016a) “Statistical review of world energy, energy economics.” Accessed May 27, 2017. http://www.bp.com/en/global/corporate/energy-economics/statistical-review-ofworld-energy.html. BP Global (2016b) “Bp-Statistical-Review-of-World-Energy-2016-Full-Report.pdf.” Accessed May 27, 2017. https://www.bp.com/content/dam/bp/pdf/energy-economics/statistical-review​ -​2​0​16/bp-statistical-re​view-of-world-energy-2016-full-report.pdf. Conant, M.A. (1994) “The geopolitics of oil,” Geopolitics of Energy, 16 (7), July 1, Washington, DC. Conant, M.A. (1979) “The US energy scene,” Geopolitics of Energy, 1 (3), 1–3, May, published monthly for the clients of Conant and Associates Ltd, Washington, DC. Ebel, R.E. (2004) “Russia – King of the oil hill?” Paper presented to a “Conference on Russian energy” at the Meridian International Center, Washington, DC. Accessed May 27, 2017 https://www.csis.org/analysis/russia-king-oil-hill. EIA (US Energy Information Administration) (1994) “Annual energy outlook 1994,” DOE/ EIA 0383(94). EIA (US Energy Information Administration) (2016a) “How much oil consumed by the United States comes from foreign countries? – FAQ.” Accessed May 27, 2017. https://www.​ eia.gov/tools/faqs/faq.php?id=32&t=6. EIA (US Energy Information Administration) (2016b) “How much petroleum does the United States import and export? – FAQ.” Accessed May 27, 2017. https://www.eia.gov/too​ ls/faqs/faq.php?id=727&t=6. EIA (US Energy Information Administration) (2016c) “Oil imports and exports – Energy explained, your guide to understanding energy – Energy information administration.” Accessed June 3, 2017. https://www.eia.gov/Energyexplained/index.cfm?page=oil_imports. IEA (International Energy Agency) (2016a) “Bookshop – World energy outlook 2016.” Accessed June 3, 2017. http://www.iea.org/bookshop/720-World_Energy_Outlook_2016. IEA (International Energy Agency) (2016b) “World energy outlook 2016.” London, November 16. Accessed June 3, 2017. http://www.iea.org/media/publications/weo/WEO2016Pr​esenta​ tion.pdf. Nerurkar, N. (2011) “US oil imports: Context and considerations.” Congressional Research Service, Library of Congress, 2011. Accessed July 20, 2017. http://www.ourenergypolicy. org/wp-content/uploads/2013/08/R41765.pdf. Woods Hole Oceanographic Institution (2003) “In memoriam: Melvin A. Conant.” Accessed May 27, 2017. http://www.whoi.edu/mr/obit/viewArticle.do?id=731&pid=731. Workman, D. (2017) “Crude oil imports by country.” World’s Top Exports, May 29, 2017. Accessed July 20, 2017. http://www.worldstopexports.com/crude-oil-imports-by-country/

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Acknowledgements The editors would like to acknowledge the editorial committee of the Geopolitics of Energy for their wisdom, encouragement and advice throughout the years. John A. Hill, Dr Joseph J. Malone, Max K. Morris, Rear Admiral, U.S.N., ret’d., Charles K. Ebinger, G. Henry M. Schuler, Ian Smart, Grenville Garside, Christa G. Conant, Robert E. Ebel, Adam Sieminski, John Devlin, John Roberts, Alex Kemp, Peter Adam, Paul Tempest, Michael Lynch, Alberto Cisneros Lavaller, Napier Collyns, Murray Gart, Elena Turner, Campbell Watkins and Anthony Reinsch. We would also like to thank Diamond Gas for their generous support and encouragement.

xxviii

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Introduction

Jennifer I. Considine

The Handbook of Energy Politics is concerned primarily with the ­geopolitics of energy in a changing landscape. As we are reminded by Mel Conant, who aptly defined the term geopolitics in the early 1970s: “geo” refers to the location of oil reserves; “politics” reflects the decisions of importing and producing governments affecting access to supplies. The basic ingredients will always be a mix of politics, economics, and security objectives. All of the factors have to be kept in mind since overlooking one or more may invite serious trouble.1

The scope and complexity of these issues increases with the rise of technology, cybersecurity and environmental concerns. The book is divided into five parts: “The Fundamentals of the Global Energy Industry: The Supply Side”; “The Fundamentals of the Global Energy Industry: The Demand Side”; “Main Influences in Geopolitics”; “The Evolution of Technology, Capital and Financial Markets in the Energy Industry” and “Environmental Issues and Renewable Energy Policy.” The first part, “The Fundamentals of the Global Energy Industry: The Supply Side” contains five chapters on geopolitical factors affecting the supply of crude oil and natural gas in the major global producing regions. In Chapter 1, Anna Vypovska, Laura Johnson, Dinara Millington and Allan Fogwill review the complex legislative and environmental issues associated with the development of natural gas reserves in British Columbia. We are reminded of the importance of achieving and maintaining positive relationships, effective consultation and engagement with potentially affected Indigenous groups, all factors which remain critical for sustainable development, and the success of projects around the globe. Nina Poussenkova’s chapter, “Oil on the waters of the RIC energy relations” asks whether the emergence of a “third player” completing the RIC triangle will pour oil on troubled waters of Russia–China petroleum relations, or make Russia’s partnership with its European and Asian energy counterparts even more stormy. Liu Xiaoli and Tian Lei addresses the exciting field of energy transitions and natural gas developments in China, advocating policies that support xxix

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xxx   Handbook of energy politics the development of natural gas and ensure the safety of supply so that natural gas becomes a bridge in the process of energy transition. In Chapter 4, Douglas B. Reynolds explores the effects of institutions on the supply of oil, concluding that the “oil market is likely to be highly volatile in the future due to scarcity, the lack of oil-supply expansion capacity and market reinforcing institutional changes.” Alberto Cisneros Lavaller examines the implications of plummeting oil prices on Latin American producing companies, and concludes that the greatest impact has been on a number of junior oil companies in the region and in certain countries like Colombia. There is a light at the end of the tunnel for the regions conventional and non-conventional oil industry. The second part on “The Fundamentals of the Global Energy Industry: The Demand Side” contains a number of chapters exploring the geopolitical factors affecting the demand for crude oil and natural gas in the major global producing regions. Chapter 6, “The role of Sino-Russian gas cooperation in China’s natural gas expansion,” contributed by Keun-Wook Paik, reminds us of the geopolitical importance of LNG and pipeline gas imports to China, and the role that these will play in the coming years in parallel with China’s gas expansion. In Chapter 7, Se Hyun Ahn draws the reader’s attention to the harsh political turmoil and divided national public opinion in the Republic of Korea (ROK), that presides over virtually every issue in the history of the ROK. Perhaps not surprisingly, given the 2013 nuclear scandals, the issue of energy security has become one of the most sensitive in the ROK’s domestic politics. In Chapter 8, Philip Andrews-Speed and Sufang Zhang examine the evolution of China’s energy policy since 1949 using the electricity industry as an example. The analysis illustrates the complex interplay between domestic and external events, and how these factors contribute to the establishment of policy and agenda. The chapter helps identify the factors that render policy design and decision-making highly path-dependent and to illustrate the ability of policymakers to learn from experience. This chapter provides an indication of the potential evolution of energy policy at the international, regional, national and local levels. Chapter 9 presents a brief historical perspective on natural resource development in Sub-Saharan Africa (SSA). Rene Roger Tissot explains how SSA has the potential to achieve rapid industrialization through the exploitation of natural resources if proper local content policies are adopted. While local content policies are a necessary condition, they are not a sufficient one. Historically, it can be shown that it is the “missing middle,” referring to the lack of formal small and medium firms in SSA, that presents an effective barrier to industrialization.

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Introduction  ­xxxi The next part, “Main Influences in Geopolitics,” discusses recent trends in the energy industry, and the primary factors that are driving the future development of global resources. The section addresses questions concerning the physical limitations to natural energy supplies, geopolitical forces such as political tensions, corruption, growing populations and demands, and the rise of renewables and non-conventional supply sources. Mamdouh G. Salameh examines the future of oil, questioning whether there will ever be a post-oil era, and what that might look like given significant changes in some aspects of the multi-uses of oil in transport, electricity generation and water desalination which will eventually be mostly powered by solar energy. In Chapter 11, Colin J. Campbell warns of constraints on conventional resources, growing population and demands, resulting in the evolution of the Oil Age to another stage in its development. “It is not solely an issue of petroleum supply as such, as the modern world is also destroying its environment, depleting water supplies, cutting down forests and causing soil erosion.” The chapter examines the potential geopolitical implications of impending constraints on energy resources, suggesting a number of policy prescriptions to meet the challenges that lie ahead. Michael Lynch examines recent trends in the energy industry, noting that new sources of power, whether renewables or nuclear, will play a modest but significant role in changing global geopolitics, primarily reducing coal use. Perhaps more importantly, the development of shale oil and gas has the potential to reduce energy imports and increase security of supply while at the same time making markets more transparent. Declining petroleum revenues have the potential to increase political instability in exporting nations. Chapter 13 examines the problems of corruption and resource curse encountered by a number of host companies engaged in the development of large-scale extractive resource projects. Paul Stevens and Jennifer I. Considine examine a number of possible solution to the “resource curse” including the staged development of projects, and the development of appropriate incentive schemes for host countries. In Part IV, Chapter 14 addresses the financing of renewable energy, suggesting that a lag in financial markets might be creating a “log jam to the expansion of green investing.” In Chapter 15, Tilak Doshi examines the pricing nexus that has developed between the Middle East oil producers and their oil-importing neighbors “East of Suez” over the past half century. This complex and dynamic relationship is among the most fundamental variables of any global model of energy politics, and faces a number of challenges, including the development of a dependable solid Asian futures contract for

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xxxii   Handbook of energy politics crude oil which can serve as a widely used pricing benchmark for sour crude. In Chapter 16, Luciano de Castro, Joisa Dutra and Vivian Figer investigate increasing demands on the power system, which is rapidly evolving from a one-way power flow (from power plants to end users) to two-way power flows on transmission lines and local distribution networks. The move to smart grid technologies “increases digital complexity and attack surfaces,” raising data security, cybersecurity and privacy-related issues. As services become more digital and automated, power disruption has greater consequences. Problems of jurisdiction and rapidly evolving technologies suggest that cybersecurity regulations require a degree of flexibility to keep pace with evolving threats, and the valuation of the DERs will have to account for the costs of cybersecurity. The final part, “Environmental Issues and Renewable Energy Policy,” examines the pace of the transition to a low carbon environment, suggesting a number of policies that might be adopted to help aid the transition. Geoffrey Wood examines the progress to date of the low carbon energy center. While “on the face of it, the low carbon energy sector appears overall to be doing well: capacity is up, records are being broken, novel technologies are reaching market maturity and costs are falling,” policy risk and the lack of consensus on basic definitions and clear long-term goals on the climate and energy are hampering the sector’s ability to invest in low carbon growth. Finally, Lara Lázaro-Touza reminds us that there is still work to be done on the issue of climate change. In order to meet the 2ºC targets as defined by the Paris Accord, the international community will require increasing certainty regarding the effects of climate change, specifically the establishment of direct links between extreme weather events and changing climate and the effectiveness of international policy and diplomacy.

NOTE 1. M.A. Conant (1994) “The geopolitics of oil,” Geopolitics of Energy, 16 (7), July 1, Washington, DC: Canadian Energy Research Institute.

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PART I THE FUNDAMENTALS OF THE GLOBAL ENERGY INDUSTRY: THE SUPPLY SIDE

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1.  Environmental and Indigenous issues associated with natural gas development in British Columbia Anna Vypovska, Laura Johnson, Dinara Millington and Allan Fogwill

1  INTRODUCTION Currently, the Province of British Columbia (BC) is the second largest producer of marketable natural gas amongst the Canadian provinces, with the most economically viable natural gas wells, both vertical and horizontal (BC OGC 2015a; CAPP 2016). The estimated reserves in the Province at the end of 2014 were 51 000 billion (a thousand million) cubic feet (Bcf) of raw natural gas (BC OGC 2015a). Since 2013 approximately 65 percent of the wells drilled in BC have been in its unconventional Montney Formation, with the remainder of split fairly evenly between the rest of the Province’s formations (CERI 2016). As shale gas has increased North American supply of natural gas, investor focus is moving to exports, specifically of liquefied natural gas (LNG). In 2012 the Province issued a Natural Gas Strategy which recognizes natural gas, particularly LNG exports, as a provincial priority and lists a series of actions the Province will undertake to promote the industry (BC MEM 2012). Since 2012 20 LNG projects have been proposed in BC, 18 export licenses have been issued by the National Energy Board (NEB) and nine  environmental assessments (EAs) have been completed by the BC Environmental Assessment Office (BC EAO) and the Canadian Environmental Assessment Agency (CEA Agency), with a few more underway (Province of BC 2016a). Notwithstanding the fact that natural gas is the world’s cleanest burning fossil fuel, potential adverse environmental impacts associated with the natural gas development in BC are being debated by stakeholders, Indigenous groups and the general public. Potential impacts of the natural gas and LNG projects in BC on Indigenous peoples’ interests have been another concern of critical importance, since the Province is characterized by the greatest diversity of Indigenous population in Canada and presents a unique landscape of Aboriginal rights and interests. This chapter* examines major environmental and Indigenous peoples’ 3

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4   Handbook of energy politics issues facing development of the natural gas and LNG industry in BC and provides examples of the key approaches to mitigate, manage and monitor the issues effectively. It focuses on the following areas: ●

Understanding the current legal framework and regulatory requirements associated with the environmental assessment process for natural gas and LNG activities in BC. ● Analyzing the most important environmental issues associated with the development and operation of natural gas pipelines and LNG facilities in BC. ● Defining Indigenous rights and legal issues as they affect natural gas development in BC and understanding the context of how Indigenous peoples are affected by natural gas and LNG development. ● Providing suggestions on key approaches to address the identified environmental and Indigenous peoples issues and best practices for proponents of natural gas pipelines and LNG projects.

2 BASELINE INVENTORY OF ENVIRONMENTAL ASSESSMENT APPLICATIONS FOR MAJOR NATURAL GAS AND LNG PROJECTS IN BC A discussion of existing and proposed natural gas and LNG projects within the region is fundamental to the analysis of the current state of this industry in British Columbia. We reviewed EA applications and assessment reports for 29 major natural gas, natural gas liquids (NGLs) and LNG projects in BC (including upstream, midstream and downstream developments) that have undergone a typical EA process (active and/or complete) with the provincial (BC EAO) or the federal (CEA Agency or NEB) responsible authority since 2010. Main regulatory requirements to the provincial and federal EA processes for natural gas and LNG projects are briefly outlined in Box 1.1. Detailed information regarding the 29 reviewed projects is presented in Table 1.1. The projects selected for this relevant and representative sample of the past, present and anticipated future natural gas projects included those that have entered the EA process (pre-application stage); the projects currently under review with the regulatory authorities; and the projects with an EAC, CPCN or EADS (see Box 1.1) issued, amended or extended since 1 January 2010. Analysis of the information presented in Table 1.1 by the project type shows that natural gas pipelines and LNG facilities constitute the

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Natural gas development in British Columbia  ­5 BOX 1.1 REGULATORY REQUIREMENTS TO THE ENVIRONMENTAL ASSESSMENT PROCESS FOR NATURAL GAS AND LNG PROJECTS IN BRITISH COLUMBIA Environmental assessments at the provincial level, and often at the federal level as well, are typically required for all major natural gas pipeline and LNG projects developed in BC, in order to determine whether proposed projects should proceed and what are the terms and conditions for their approval (BC EAO 2015a). A legal framework for provincial EAs includes three major sources: the BC Environmental Assessment Act, 2002 (BC EAA 2002) as the primary EA legislation; regulations under the BC EAA; and common law regarding Indigenous peoples’ consultation (BC EAO 2015a). All natural gas pipeline and LNG projects that are considered as “reviewable” under the BC EAA Reviewable Projects Regulation (Province of BC 2002) are subject to the provincial EA process, with BC EAO as the main regulator and the provincial responsible authority. BC EAO also enforces compliance with the conditions of provincial Environmental Assessment Certificates (EACs) issued by two ministers responsible for the decision-making for a project undergoing a provincial EA (BC EAO 2015a, 2016a). Projects that do not require an EA under the BC EAA (for example, seismic exploration, well production, well drilling and well testing projects) may still require other permits or approvals. The majority of provincial permits are provided through the BC Oil and Gas Commission (BC OGC), the primary operational regulator of oil and gas activities in the Province acting under the BC Oil and Gas Activities Act (BC OGC 2015c). A federal EA may be required for a proposed natural gas pipeline or an LNG facility that meets the thresholds set out in the Regulations Designating Physical Activities (Canada 2012) under the Canadian Environmental Assessment Act, 2012 (CEAA 2012). The CEAA 2012 provides the framework for the federal EA process, with the CEA Agency as the main regulator for intra-provincial pipelines and related facilities and the NEB as the regulator for pipelines that cross provincial and international boundaries (CEAA 2016a). Authorization or approval from the NEB is also required for the export of NGLs and export or import of natural gas (Government of Canada and NEB 2016). When the CEA Agency is the responsible authority, the federal Minister of the Environment issues an Environmental Assessment Decision Statement (EADS) that concludes whether the proposed project is likely to cause significant adverse environmental effects. If this is the case, the Governor in Council (GIC) has to determine whether the significant adverse environmental effects are justified in the circumstances (CEAA 2016a). When the NEB is the responsible authority, it makes recommendations to the GIC on whether the reviewed project meets a threshold for public convenience and necessity. The GIC is responsible for the decision on whether to issue a Certificate of Public Convenience and Necessity (CPCN) or not, and this decision takes the form of an order to be implemented by the NEB (Government of Canada and NEB 2016). Federal and provincial EA regulatory processes can overlap due to their nature. In 2004 the federal and provincial governments signed the Agreement on Environmental

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6   Handbook of energy politics Assessment Cooperation, and later in 2013 BC EAO and the CEA Agency signed a Memorandum of Understanding (MOU) on the Substitution of Environmental Assessments to help facilitate a single review process (BC EAO 2013a). Under substitution, where both federal and provincial EAs are required, there can be a single EA that meets both provincial and federal standards, and a single provincial review process conducted by BC EAO, with two decisions – federal and provincial (BC EAO 2015c; McCarthy Tétrault LLP 2016). A substitution process differs from equivalency. Under the equivalency provisions of the CEAA 2012, only a single provincial EA is conducted and a single provincial decision is made about whether the proposed project should be granted approval; no federal approval is required. Substitution and equivalency provisions do not apply if a project is being assessed by the NEB or if the project has been referred to a review panel (BC EAO 2015c). In 2016 the Federal Government launched an interim approach to review major projects under federal EA processes, five main principles of which include: 1) reviewing projects within the current legislative framework and treaty provisions; 2) making decisions based on science and traditional knowledge of Indigenous peoples; 3) considering the views of the public and affected communities; 4) meaningful consulting with Indigenous peoples and 5) assessing direct and upstream greenhouse gas (GHG) emissions linked to the proposed projects (Government of Canada 2016a).

two largest categories of the reviewed projects (which include 12 and eight  projects, correspondingly). Other categories include natural gas processing facilities (five  projects), NGL facilities (two  projects), NGL pipelines (one project) and LNG transportation (one project). As shown in Table 1.1, the reviewed projects involve a wide range of output capacities, with the projected average daily production 0.15– 0.40 Bcfpd for natural gas processing facilities, 0.23–2.2 Bcfpd for natural gas pipelines, and 0.32–3.47  Bcfpd for LNG facilities. The anticipated daily productions of these projects at full build-out range are even higher, up to 0.6 Bcfpd for natural gas processing facilities (Fortune Creek Gas project), up to 8.4 Bcfpd for natural gas pipelines (Westcoast Connector Gas Transmission project) and up to 4.0 Bcfpd for LNG facilities (WCC LNG project). Analysis of the reviewed EA applications by the provincial EA status demonstrates that for the 12 projects the EA process was completed (that is, an EAC was issued, amended or extended); nine projects are currently at the pre-application stage with BC EAO; and for the remaining applications, a provincial EAC is not required either due to an equivalency process with the federal regulatory agency (five projects) or because an exemption from obtaining the EAC was granted by BC EAO (three projects). Distribution of the reviewed EA applications by the federal EA status,

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7

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LNG export facility

Aurora LNG   Digby Island Cabin Gas Plant

Natural gas processing facility Coastal GasLink Natural gas pipeline   Pipeline and facilities Dawson Liquids Natural gas liquids   Extractions (NGLs) extraction facility Eagle Mountain Natural gas pipeline  – Woodfibre Gas and facilities Pipeline Fort Nelson North Natural gas processing  Gas Processing facility Facility Fortune Creek Gas Natural gas processing facility Grassy Point LNG LNG export facility and associated marine terminal Natural gas pipeline Groundbirch  Pipeline and facilities Horn River Gas Natural gas pipeline and facilities

Project type

Project title

EAC issued (2013)

Initial: 0.15 Bcfpd; projected: up to 0.60 Bcfpd 20 MMtpa (~2.7 Bcfpd)

Initial: 0.7 Bcfpd; projected: up to 1.04 Bcfpd

1.66 Bcfpd

EA not required (equivalency process)

0.25 Bcfpd

EA not required (equivalency process) EA not required (equivalency process)

Pre-application (started 2014)

EAC issued (2016)

EAC not required (exemption)

Pre-application (started 2014) EAC issued (2010); amended (2011, 2012) EAC issued (2014)

Provincial EA status

0.23 Bcfpd

Initial: 2.1 Bcfpd; projected: up to 5 Bcfpd 0.4 Bcfpd

0.8 Bcfpd

24 MMtpa, or 3.2 Bcfpd

Average production, storage or transmission capacity

CPCN issued by NEB (2010) CPCN issued by NEB (2011)

CPCN not required; exemption granted by NEB (2010) EA not required (not designated project) EA under substitution process

EA not required (not designated project)

EA under substitution process EA not required (not designated project) EA terminated (not designated project) Reviewed by NEB (2011)

Federal EA status

Table 1.1 Inventory of major British Columbia natural gas and LNG projects that have undergone a typical environmental assessment process since 2010

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Natural gas pipeline (Chinchaga section in AB and Komie North section in BC) and facilities LNG Canada LNG plant and  Export Terminal associated marine terminal facilities North Montney Natural gas pipeline  Mainline and associated facilities Pipeline Transmission pipeline Northeast  British Columbia facility to transport Expansion NGLs Northwest Natural gas pipeline  Mainline and facilities Expansion Pacific Northern Natural gas pipeline  Gas Looping Pacific NorthWest LNG export facility  LNG

LNG terminal and associated facilities

Kitimat LNG  Terminal

Komie North  Extension

Project type

Project title

Table 1.1  (continued)

CPCN issued (2012) May be subject to federal EA EADS issued (2016)

Under review (started 2016) EAC issued (2016) EA not required (equivalency process) Pre-application (started 2013) EAC issued (2014)

NA Transmission capacity 75 Mbpd, or 12 Mm3/d Increasing capability of existing system by 0.49 Bcfpd (to 1.26 Bcfpd) 0.6 Bcfpd 18 MMtpa (~2.4 Bcfpd)/ storage capacity 540 000 m3

EADS issued (2015) under substitution process CPCN issued by NEB (2015); EADS issued (2015) EA not required (not designated project)

Komie North section denied by NEB as not economically feasible (2013)

EAC issued (2015); amended (2016)

NA

3.47 Bcfpd (26 MMtpa)

Comprehensive study review (2006)

Federal EA status

EAC issued (2006); amended (2010); extended (2011) EA not required (equivalency process)

Provincial EA status

NA

Average production, storage or transmission capacity

9

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Natural gas pipeline and facilities LNG export facility

Prince Rupert Gas   Transmission Prince Rupert   LNG Progress Town   North Gas

Natural gas processing facility

Natural gas pipelines and facilities

LNG export facility

Towerbirch  Expansion

WCC LNG

Propane export terminal

Ridley Island  Propane Export Terminal Saturn 15-27  Sweet Gas Plant

Natural gas processing facility

Natural gas pipeline and facilities

Pacific Trail  Pipelines1

Initial: 15.0 MMtpa (2.0 Bcfpd); projected: up to ~30.0 MMtpa (4.0 Bcfpd)

NA

Shipping up to 1.2 MMtpa of propane/ storage capacity 98 000 m3 0.4 Bcfpd

Initial: ~2 Bcfpd; projected: up to 3.6 Bcfpd 21 MMtpa (~2.8 Bcfpd)/ storage capacity 540 000 m3 0.35 Bcfpd

NA

Pre-application (started 2015)

Pre-application (started 2015). EAC not required (exemption) Pre-application (started 2016)

EAC issued (2008); amended (2012–16); extended (2013) EAC issued (2014); amended (2015, 2016) Pre-application (started 2013) Pre-application (started 2014). EAC not required (exemption) EA not required

NEB recommended approval of the project (2016) EA under substitution process

EA not required (not designated project)

EA in progress (started 2016)

EA not required (not designated project)

EA not required (not designated project) EA in progress

EADS issued (2009)

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LNG export facility

2.4 MMtpa (~0.32 Bcfpd)/ EAC issued (2015) storage capacity 250 000 m3

EAC issued (2014)

Pre-application (started 2015)

Provincial EA status

EADS issued (2016) under substitution process

EA not required (not designated project)

EA under substitution process

Federal EA status

Sources:  AltaGas Ltd. 2016; BC EAO 2008, 2009, 2011, 2013b, 2014a,b,c,d, 2015b,d,e, 2016b,d,e; BC EAO et al. 2006; BC MOE and BC MEMPR 2006, 2008, 2010; BC MOE and BC MNGD 2013b, 2014a,b,c,d,e,f,h, 2015a,c,d, 2016a,b,c,d; Canada and NEB 2010, 2012, 2013, 2016; CEAA 2015b; Government of Canada 2016b; NEB 2010, 2015a.

Note:  Bcfpd = billion (a thousand million) cubic feet per day; MMtpa = million metric tons per year; Mbpd = thousand barrels per day; Mm3/d = thousand cubic meters per day.

Westcoast  Connector Gas Transmission Woodfibre LNG

NA Marine jetty, LNG infrastructure for transfer LNG to marine vessels Natural gas Initial: 2.2 Bcfpd; transmission pipelines projected: up to 8.4 Bcfpd

WesPac Tilbury  Marine Jetty

Average production, storage or transmission capacity

Project type

Project title

Table 1.1  (continued)

Natural gas development in British Columbia  ­11 as presented in Table 1.1, shows there are 12 projects with the completed EA process (a CPCN or an EADS issued or denied); three projects with the federal EA process currently underway; and four projects where the federal EA will be conducted under a substitution process with the provincial regulator. For the remaining EA applications, a federal approval is not required either because the projects do not trigger a federal review under the CEAA 2012 (nine  projects) or because an exemption from obtaining the CPCN was granted by the NEB (one project).

3 MAJOR ENVIRONMENTAL ISSUES ASSOCIATED WITH NATURAL GAS AND LNG DEVELOPMENT IN BC The key potential environmental issues discussed in this section were selected based on the typical content of EA documents for natural gas pipeline and LNG projects which is determined by the practice of EA assessment in BC (see Box 1.2 for details). Table 1.2 includes a list of terrestrial and marine valued components (VCs) that may be impacted by the project, with potential effects on these VCs that may result from the construction, operation and/or decommissioning of the proposed projects, as identified by the proponents. Potential adverse effects on the terrestrial VCs were identified from the review of EA applications for all 29 natural gas pipeline and LNG projects that have entered a typical EA process with the provincial and/or federal responsible authority since 2010, as summarized in Table 1.1. Potential adverse effects on the marine VCs were mostly identified on the proposed LNG projects, as well as on a few natural gas pipeline projects that include a marine portion of the pipeline route. In total, the potential of the project to impact marine VCs was discussed by the proponents in 12 out of the 29 reviewed EA applications. Since the EA process for a number of the reviewed projects has not been completed yet, and therefore, corresponding EA reports from the regulators were not available, other documents submitted by the proponent (including Application Information Requirements or Valued Components Selection documents) have been considered for this analysis. It is important to remember that the adverse effects presented in Table 1.2 are potential interactions between the project activities and the VCs before implementation of mitigation, and they do not necessarily result in residual adverse effects remaining after the implementation of all mitigation measures. Residual adverse effects on environmental VCs identified by the ­proponents in the EA applications for the proposed projects were

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12   Handbook of energy politics BOX 1.2 THE PRACTICE OF ENVIRONMENTAL ASSESSMENT IN BRITISH COLUMBIA The provincial EA process consists of three stages: 1) pre-application, where a project description is reviewed; scope, procedures and methods for the EA process are specified; an application for an EAC is submitted by the proponent and evaluated by BC EAO for completeness; 2) application review by the working group composed of representatives of various government agencies and Indigenous groups, with public input provided, where an assessment report is prepared by BC EAO and 3) EAC decision stage, where the responsible Ministers make a decision as to whether to certify the project based on the recommendations from BC EAO (BC EAO 2016a). The federal EA process is conducted within the framework provided by the CEAA 2012 and is focused on assessing potential adverse environmental effects that are within federal jurisdiction, including fish and fish habitat, other aquatic species, migratory birds, federal lands, effects that cross provincial or international boundaries and impacts on Indigenous peoples (CEAA 2016a; McCarthy Tétrault LLP 2016). An EA application is typically organized around the valued components (VCs) which the project has the potential to impact. For the purposes of the EA process in British Columbia, valued components are defined as “aspects of the natural and human environment that are considered to have scientific, ecological, economic, social, cultural, archaeological, historical or other importance” (BC EAO 2015a). VCs represent the foundation of environmental assessments in British Columbia and many other jurisdictions as well. Selected VCs will vary for each project depending on the characteristics of the project and the region and context within which it is located and should be identified as early in the assessment process as possible (BC EAO 2013d). The EA application typically includes the proponent’s baseline data of the study areas, as well as the analysis of the potential environmental, social, health, heritage and economic effects of the project on the selected VCs. The application must describe the technically and economically feasible mitigation measures to prevent or reduce to an acceptable level any potential adverse effects of the project on selected VCs (BC EAO 2013d, 2015a). A critical step in the EA process is to determine if the residual adverse effects (that is, effects remaining after the implementation of all mitigation measures) are significant, based on the defined criteria (BC EAO 2013d). The potential for significant residual adverse effects is a “key consideration in determining whether or not an Environmental Assessment Certificate is issued for a proposed project” (BC EAO 2013d). Another major objective of an EA application is to measure the impacts of the project and all other past, present and reasonably foreseeable projects and activities in the region (that is, a cumulative effects assessment). The cumulative effects assessment is required if a reviewable project is expected to result in any residual adverse effects on the selected VCs (not only those predicted to be significant). The significance of any cumulative effects must also be evaluated (BC EAO 2013d, 2015a; CEAA 2015a).

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Natural gas development in British Columbia  ­13 Planning and execution of post-construction monitoring and follow-up studies is the last and one of the most important steps for the EA application. They are intended to monitor adverse project effects and mitigation measures throughout the construction and operations phase and beyond (often including decommissioning and abandonment). It is important to confirm that project impacts are not higher than predicted and that mitigation measures are working as proposed.

reviewed by the provincial or federal responsible authorities to determine their ­significance. For the majority of the projects with the EA process completed, the regulators’ assessment reports concluded that practical means have been identified to prevent or reduce any potential negative environmental impacts of the proposed projects such that no direct or indirect significant adverse effect is predicted or expected. Significant residual adverse effects to the GHG emissions VC and the wildlife VC (specifically, to caribou, grizzly bear and harbour porpoise) reported for a number of projects will be discussed in detail further on. Potential Cumulative Effects from Natural Gas and LNG Development Cumulative effects are changes to environmental, social and economic values caused by the combined effect of past, present and potential future activities and natural processes (BC MFLNRO and BC MEM 2016). They can be classified into a number of types, including habitat alteration, loss and fragmentation; barriers to movement; direct and indirect mortality and disturbance (Salmo Consulting Inc. and Diversified Environmental Services 2003). Exceedance of thresholds (due to overlapping in time and space) and induced effects should also be taken into consideration. Key challenges in the completion of an adequate cumulative effects assessment were discussed in a number of studies (Salmo Consulting Inc. and Diversified Environmental Services 2003; WWF-Canada and UNBCCIRC 2015) and include: ● ● ● ● ● ●

Extending the analysis of project level impacts to a regional level. Inadequate baseline that does not adequately consider pre-­ development conditions. Lack of standardized methodological approach, consistency and transparency in defining significance. Lack of incorporation of traditional ecological knowledge and Indigenous peoples considerations. Lack of acceptance and implementation of thresholds. Dealing with uncertainty (for example, imperfect knowledge of

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14

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Marine valued components Marine surface water

Terrestrial wildlife and   wildlife habitat

Terrestrial vegetation

Wetland function

Terrestrial valued components Acoustics Air quality Greenhouse gas emissions Soil/terrain Surface water/ groundwater Fish and fish habitat

Valued component

Changes in water quality from discharges from the LNG facility, dredging and pile driving Contaminant concentrations in sediment and water

Increase in ambient noise levels Increase in elevated concentrations of criteria air contaminants Increase in GHG emissions during construction and operation Reduced slope stability, increased erosion, soil chemistry changes Change in surface water quality due to increased total suspended solids Potential alteration and loss of instream and riparian habitat Potential fish mortality and injury Loss or alteration of wetland hydrologic, biogeochemical and habitat functions Loss or alteration of native vegetation, plant species and/or vegetation communities of concern Introduction and spread of invasive plant species Changes in habitat availability resulting from habitat loss/alteration Changes in movement and increased mortality risk

Potential adverse effect

12/12

12/12

26/29 28/29 28/29

27/29

29/29 29/29 29/29 21/29 26/29 23/29 23/29 24/29

Projects with potential adverse effects identified

Table 1.2  E  xamples of potential adverse effects on the terrestrial and marine valued components as identified by the proponents

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11/12 10/12

11/12

12/12

5/12 12/12

12/12

Sources:  AltaGas Ltd. 2016; BC EAO 2008, 2009, 2013c,f, 2014a,b,c,d, 2015b,d,e, 2016d,e; BC EAO et al. 2006; Canada and NEB 2010, 2012, 2013, 2016; NEB 2010, 2011, 2015a; Nexen Energy ULC 2015; Pacific Northern Gas Ltd. 2014; Prince Rupert LNG Limited 2014; Stantec Consulting Ltd. 2014; WCC LNG Project Ltd. 2016; WesPac Midstream 2016; Woodside Energy Holdings Pty Ltd. 2016.

Intertidal and subtidal marine Changes in marine habitat type, quantity and quality and marine   habitat biodiversity Effects of introduction of invasive species Marine fish and shellfish and Removal and alteration of estuarine and marine fish habitat, including   their habitats marine plants Changes in habitat availability, productivity and the use of habitat; effects of introduction of invasive species Marine mammals Direct and indirect effects on areas occupied by marine mammals and their types of use Risk of LNG carriers and support vessels colliding with marine mammals Behavioral changes that may occur as a consequence of project interactions

16   Handbook of energy politics baseline conditions and activities, limited understanding of the indirect impacts of activities and uncertainties about future development scenarios). ● Different interpretation of cumulative effects data. It is important to remember that small, non-reviewable projects are not currently assessed for cumulative effects, so unintended impacts can accumulate. However, the demand for natural gas infrastructure is growing rapidly, with the context for new development becoming more complex, that results in a need to efficiently and consistently assess the impact of both small and large projects (Province of BC 2014a). The analysis of cumulative effects from the 18 natural gas pipeline and LNG projects where the provincial or federal EA process has been completed shows that the majority of the proposed projects will not likely result in significant cumulative adverse effects to identified VCs taking into account practical means of preventing or reducing to an acceptable level, any potential adverse effects. However, for the wildlife VC, the cumulative effects were rated as significant for three threatened and endangered species (specifically, caribou, grizzly bear and harbour porpoise) on a number of the assessed projects (BC EAO 2013c, 2014a,b,d, 2016e; CEAA 2016b). These findings can be mostly attributed to the results of long-term habitat fragmentation and ongoing loss and alteration of the natural landscape in the region. Significant Residual and Cumulative Adverse Effects on the Environmental Valued Components Increase in greenhouse gas emissions Significant residual adverse effects related to GHG emissions have been one of the major environmental issues identified by the regulators on seven out of the 18 natural gas pipeline and LNG projects where the provincial and/or federal EA process has been completed (BC EAO 2009, 2013c, 2014a,b,d, 2015b; CEAA 2016b). GHGs would be released during the construction, operation and decommissioning of the proposed projects. It should be noted that BC EAO did not require the proponents to include a cumulative effects assessment for GHG emissions, since they are a global issue. Both the federal and provincial governments have created strategiclevel plans to address GHG emissions. A target set by the Government of Canada under the Copenhagen Accord (2009) was reducing Canada’s total GHG emissions by 17  percent from 2005  levels by 2020. In 2015 the Government of Canada announced its commitment to reducing Canada’s GHG emissions by 30 percent below 2005 levels by 2030, which would require cutting current emissions by about 200 million tonnes

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Natural gas development in British Columbia  ­17 (Mt) (Government of Canada 2015). The BC Greenhouse Gas Reduction Act (2007) establishes provincial GHG reduction targets of 33  percent below 2007 emission levels by 2020 and 80 percent below by 2050. Interim reduction targets of 6 percent by 2012 and 18 percent by 2016 have been set in policy to guide and measure progress (Province of BC 2008). In 2014 the Province’s carbon dioxide equivalent (CO2e) emission levels were reported at 62 700 kilotonnes (kt), which is 5.5 percent below 2007 levels (Province of BC 2016b). In order to achieve the GHG reduction goals across the Province, British Columbia has designed and implemented a number of policy, regulatory and legislative measures. The BC Greenhouse Gas Industrial Reporting and Control Act (2014) establishes a GHG emissions intensity benchmark for LNG facilities of 0.16 tonnes of CO2e per tonne of LNG produced (t CO2e/t LNG). The BC Climate Leadership Plan released in 2016 contains new actions to reduce GHG emissions across the six main action areas, including natural gas, where annual emissions are expected to be reduced by up to 5000 kt by 2050 (Province of BC 2016b). Table 1.3 shows estimated GHG emissions (Mt of CO2e per year) at the full operational capacity (full build-out) of the seven natural gas pipeline Table 1.3 Estimated greenhouse gas emissions at full operational capacity for the proposed natural gas and LNG projects with the significant residual adverse effects identified by the regulators Project title

Cabin Gas Plant Coastal GasLink Pipeline Fortune Creek Gas LNG Canada Export Terminal Pacific NorthWest LNG Prince Rupert Gas   Transmission Westcoast Connector Gas   Transmission

Estimated GHG emissions, Mt CO2e/year

Contribution to increase in GHG Emissions, %

2.166 3.517 2.435 3.958 4.5 1.918

3.27a 6.0c 3.9d 6.6c 7.2e 3.2f

0.29b 0.50c 0.35d 0.57c 0.62e 0.30f

NA 0.012 NA NA 0.015 0.004d

4.4

7.0c

0.60c

0.010d

Notes:  Contribution of the reviewed projects to increase in GHG emissions (%), as estimated by the regulator or the proponent, is based on the following data: a – 2006 inventory; b – 2007 inventory; c – 2011 inventory; d – 2010 inventory; e – 2014 inventory; f – 2012 inventory (Government of Canada 2013). Sources:  BC EAO 2009, 2013c, 2014a,b,d, 2015b; CEAA 2016b.

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18   Handbook of energy politics or LNG projects with the significant residual adverse effects identified. The table also provides information on the estimated contribution (percent) of each project to increase provincial, national and global GHG emissions. As stated by the proponents, the anticipated GHG emissions are conservative estimates that represent a worst case scenario, meaning that the estimates presented in Table 1.3 are most likely higher than actual emissions at the projects’ full build-out. As shown in Table 1.3, the Pacific NorthWest LNG project would result in approximately 4.5 Mt CO2e per year (approximately 0.22 t CO2e/t LNG), which would represent a marked increase in GHG emissions both at the provincial and national level. In addition to the assessment of the direct GHG emissions, Environment and Climate Change Canada (ECCC) has also assessed the upstream GHG emissions associated with the proposed project, as required in accordance with the Government of Canada’s interim approach for EAs announced in 2016 (Government of Canada 2016a). Upstream emissions were estimated for the stages preceding the liquefaction process and included natural gas production, processing and pipeline transmission. According to the ECCC, the upstream GHG emissions associated with the Pacific NorthWest LNG project would represent 14.0–14.7 percent of provincial emissions and 1.2–1.3 percent of national emissions (based on 2014 levels) and would be high in magnitude, continuous, irreversible and global in extent (CEAA 2016b). As assessed by the ECCC, the proposed project would be amongst the largest single point sources of GHG emissions in the country and would rank third among emitters in the oil and gas sector in Canada. As a result of the federal EA, the Government of Canada approved the Pacific NorthWest LNG project with the imposing of, for the first time ever, a maximum cap on annual project direct GHG emissions (4.3 Mt of CO2e per year, 900 000 tonnes less than what had initially been proposed by the proponent) (Government of Canada 2016b). Impacts on caribou and caribou habitat Impacts on caribou and caribou habitat were determined by BC EAO as a significant residual adverse effect on three major natural gas pipeline projects (out of 18 with the EA process completed) and were also determined by the NEB as a key issue that should be considered and fully compensated for on two other natural gas pipeline projects in northeast British Columbia (BC EAO 2014a,b,d; Canada and NEB 2015; NEB 2012). According to BC EAO’s assessment reports, four natural gas pipeline projects will contribute to significant cumulative effects on caribou (BC EAO 2013c, 2014a,b,d). For two other natural gas pipeline projects, the NEB concluded that the cumulative adverse effects of the proposed

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Natural gas development in British Columbia  ­19 projects on caribou and caribou habitat are not likely to be significant, with the implementation of mitigation to offset unavoidable and residual impacts to caribou habitat (Canada and NEB 2015; NEB 2011). Certain populations of woodland caribou (Rangifer tarandus caribou) in Canada are listed as Threatened under the federal Species at Risk Act (SARA). In British Columbia, certain populations of northern caribou and all populations of mountain and boreal caribou that represent three ecotypes of woodland caribou are provincially listed as Threatened. Conserving caribou in British Columbia is a priority for the government, with the BC Ministry of Environment (BC MOE) supporting the management of all three ecotypes (BC MOE 2016a). Woodland caribou in British Columbia are believed to be in decline that may be attributed to habitat loss, fragmentation of the herd, alteration of their habitat and increased predation, resulting from forestry and petroleum and natural gas activities (BC MEM 2012). Any additional residual loss of habitat, increase in mortality or increase in displacement/disturbance from critical habitat or important connections to critical habitat in the area of the proposed projects will have a serious impact on the potential for recovery of caribou subpopulations. Caribou are likely to alter their movement to avoid noise, activity and disturbance associated with construction activities, as well as noise from permanent facilities. The pipeline right-of-way and additional linear development could provide a travel route for predators. Available mitigation to reduce impacts of increased predation are still unproven and cannot be relied upon to completely reduce those effects (BC EAO 2014a,b,d; Canada and NEB 2015; NEB 2015c). For the three projects (Westcoast Connector Gas Transmission, Prince Rupert Gas Transmission and Coastal GasLink Pipeline) where the significant adverse effect on caribou was identified, the primary factors leading to the BC EAO’s rating of significance were the long-term potential impacts from the proposed projects of enhanced predator access to caribou (BC EAO 2014a,b,d). For the four reviewed projects (Westcoast Connector Gas Transmission, Prince Rupert Gas Transmission, Coastal GasLink Pipeline and Fortune Creek Gas Project), BC EAO concluded that the residual effects of habitat disturbance, sensory disturbance and creation of access from the proposed projects would likely interact with reasonably foreseeable future projects to create cumulative effects. Taking into account the significant project effects and the sensitivity of caribou to further disturbances, the cumulative effects to caribou were considered to be significant (BC EAO 2013c, 2014a,b,d). In the NEB’s reports for the North Montney Mainline, Northwest Mainline Expansion and the Horn River Gas projects, the Board ­concluded

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20   Handbook of energy politics that all residual effects on caribou habitat should be considered and fully compensated for, given the conservation status of caribou, the presence of critical habitat in the projects’ area and the already substantial ongoing cumulative effects on the landscape and caribou in the region (Canada and NEB 2015; NEB 2011, 2015c). Cumulative impacts on grizzly bear Cumulative adverse effects on the grizzly bear population were considered to be significant on one natural gas project out of the 18 where an EAC, EADS or CPCN were issued (BC EAO 2016e). Grizzly bear (Ursus arctos) is a Blue-listed species (Special Concern) by the BC Conservation Data Centre and is designated as a Special Concern by the Committee on the Status of Endangered Wildlife in Canada (COSEWIC). Grizzly bears are sensitive to human disturbance, with the cumulative effects of human disturbance being the largest threat to bear populations. As identified by the BC MOE, this impacts bears in three main ways (which can often be overlapping): 1) increase in frequency of conflicts between bears and humans; 2) isolation of bear populations because of human settlements, utility corridors or agriculture, and 3) degradation, loss, fragmentation or alienation of habitat due to developments. In particular, roads are known to have a negative effect on grizzly bear. At the regional scale, open road density higher than 0.6 km/km2 is known to adversely affect habitat use and these effects are magnified when road density increases over approximately 1 km/km2 (Environmental Reporting BC and BC MOE 2012). The existing average motorized access density within the area that would be intersected by the proposed Eagle Mountain – Woodfibre Gas Pipeline project currently exceeds the minimum threshold for high risk of mortality and displacement for two grizzly bear population units (GBPUs) transected by the proposed project. Both units are provincially considered threatened, with core grizzly bear habitat currently remaining well below the recommended minimum target levels (although the habitat loss that would be attributed to the proposed project is negligible). Disturbance from noise created by roads and linear corridors was found to adversely affect grizzly bear habitat effectiveness, to fragment habitat by creating barriers or filters to movement and alienating bears from suitable habitat and to increase mortality risk. It has also been identified that any impacts to the reproductive potential of breeding females could significantly affect the ability for recovery of grizzly bears in these two units traversed by the proposed project. Based on the information summarized here, BC EAO has concluded that while the proposed project alone does not have significant adverse effects to grizzly bears, cumulative effects to this spe-

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Natural gas development in British Columbia  ­21 cies are considered to be significant, taking into account the effects from past and existing projects and activities on grizzly bears, the threatened status of these GBPUs and reasonably foreseeable projects and activities (BC EAO 2016e). Impacts on harbour porpoise An analysis of EA reports for six provincially and/or federally approved natural gas pipeline and LNG projects that include the marine resources VCs was conducted. While it revealed impacts to marine mammals to be a concern for several projects, only one project has considered residual adverse environmental effects (including cumulative adverse effects) on marine mammals (particularly on harbour porpoise) to be significant (CEAA 2016b). Harbour porpoise (Phocoena phocoena) listed as a Special Concern by the COSEWIC and SARA, is highly sensitive to acoustic disturbance (particularly underwater noise), shows strong site fidelity and a higher degree of behavioral response to similar disturbances compared to other marine mammals (CEAA 2016b; DFO 2009). The CEA Agency concluded that the proposed Pacific NorthWest LNG project is likely to cause significant adverse environmental effects to harbour porpoise, given its susceptibility to behavioral effects from underwater noise, its current at-risk status, its extensive use of the project area year-round and the uncertainty of suitable alternative habitat. The regulator also concluded that the proposed project is likely to result in significant adverse cumulative environmental effects to harbour porpoise, given the number of large industrial projects proposed in the Prince Rupert area that could increase underwater noise and considering that behavioral effects of overlapping projects are expected to occur over a larger area and for a longer period of time. (CEAA 2016b; MOE 2016).

4 MAJOR INDIGENOUS PEOPLES’ ISSUES INFLUENCING NATURAL GAS AND LNG DEVELOPMENT IN BC Indigenous Peoples in BC The Indigenous,2 or Aboriginal peoples, are the descendants of the original inhabitants of North America. Section  35 of the Constitution Act (1982) recognizes three distinct groups of Aboriginal peoples: First Nations people (previously known as Indians3), Métis and Inuit. BC’s Indigenous population, based on Statistics Canada 2011 census data,

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22   Handbook of energy politics consists of 232 280 people, which represented 5.3 percent of the total BC population (Statistics Canada 2013). There are 198 First Nations in British Columbia that represent about one-third of all First Nations in Canada. First Nations population in BC, as per Statistics Canada 2011 census data, consists of 155 015 people, or 67 percent of the total Indigenous population in BC (Statistics Canada 2013). With a total population in BC of 4 400 057 in 2011, First Nations represented 3.5 percent of the total population. Indigenous peoples in BC represented 17  percent of Canada’s Indigenous population, while First Nations people in BC represented 19 percent of Canada’s First Nations people. While BC has fewer than one-fifth of Canada’s Indigenous and First Nations people, it is characterized by the greatest diversity of Indigenous cultures in Canada, including seven of Canada’s 11 unique language families that are located exclusively in BC and represent more than 60 percent of the First Nations languages in Canada (INAC 2010a). The Métis are originally the people of mixed First Nations-European ancestry, the descendants of eighteenth-century unions between European men (explorers, fur traders and pioneers) and First Nations women. Within a few generations the descendants of these unions developed a culture distinct from their European and First Nations forebears (RCAP 1996). Métis population in BC, as per Statistics Canada 2011 census data, consists of 69 470 people, or 30 percent of the total Indigenous population in BC (Statistics Canada 2013). Inuit are the Aboriginal people of Arctic Canada that live primarily in Nunavut, the Northwest Territories, Labrador and Northern Quebec. Inuit population in BC, as per Statistics Canada 2011 census data, consists of 1570 people, or 1 percent of the total Indigenous population in BC (Statistics Canada 2013). Aboriginal and Treaty Rights and Canadian Aboriginal Law Indigenous peoples struggled for recognition of their rights and fair treatment in their relations with European settlers long before establishing the Canadian Confederation in 1867. Canadian Aboriginal law has developed as a response to the actions of government and/or as a tool used by Indigenous peoples in their struggle. Box 1.3 provides a succinct summary of main documents defining the legal relationship between the Crown and Indigenous peoples and major legal cases with landmark judgments clarifying the nature of Aboriginal rights and titles. It is important to understand that Aboriginal rights differ from treaty rights. Aboriginal rights are not clearly defined and must be established

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Natural gas development in British Columbia  ­23 BOX 1.3 CANADIAN ABORIGINAL LAW AND MAJOR LEGAL CASES CLARIFYING THE NATURE OF ABORIGINAL RIGHTS AND TITLE ●

●

●

●

●

●

●

●

Royal Proclamation (1763) was the first important step toward the recognition of existing Aboriginal rights and title, including the right to self-determination. It is also set a foundation for the process of establishing treaties (UBC First Nations and Indigenous Studies 2009). Section  35 of the Constitution Act (1982) recognizes and affirms existing Aboriginal and treaty rights; however, the nature, scope or extent of these rights were not defined in the Act. Calder v. Attorney-General of British Columbia (1973). The Supreme Court of Canada’s (SCC) decision was the first of a series of landmark judgments to deal with Aboriginal rights. For the first time, the existence of Aboriginal title to land was acknowledged that would later lead to the BC Treaty Process and the settling of the first modern-day land claim in BC’s history, the Nisga’a Final Agreement in 1998 (BC Treaty Commission 2008; SCC 1973). R. v. Sparrow (1990). The SCC made a precedent-setting decision that establishes a list of criteria to determine whether an Aboriginal right is existing, and if so, how a government may be justified to infringe upon it (BC Treaty Commission 2008; SCC 1990). Delgamuukw v. British Columbia (1997). The SCC’s decision in the Delgamuukw case confirmed that Aboriginal title does exist in BC and that it’s a right to the land itself, not just the right to hunt, fish or gather. When dealing with the Crown land, the Government must consult with, and may have to compensate, First Nations whose rights may be affected (BC Treaty Commission 1999, 2008; SCC 1997). R. v. Powley (2003) was the first major Aboriginal rights case concerning Métis peoples. The SCC’s decision resulted in the Powley test, which laid out a set of criteria to not only define what might constitute a Métis right, but also establishes who can legally qualify for Métis rights (INAC 2016b; SCC 2003). Haida Nation v. British Columbia (Minister of Forests) (2004). The SCC established that the Crown is required to consult with Aboriginal groups with respect to Crown-authorized activities that might affect Aboriginal interests, and that the extent of the consultation is proportionate to 1) preliminary assessments of strength of the case for the claimed Aboriginal rights and title; and 2) seriousness of the potential impact of Crown action or activity on Aboriginal interests (BC EAO 2015b; BC Treaty Commission 2008; SCC 2004a). The court strongly urges the parties to negotiate rather than litigate, noting that “while Aboriginal claims can be and are pursued through litigation, negotiation is a preferable way of reconciling state and Aboriginal interests” (SCC 2004a). Taku River Tlingit First Nation v. British Columbia (Project Assessment Director) (2004). Similar to the Haida case, the SCC ruled that the Province should have consulted with the First Nations about the decisions, and possibly accommodated Aboriginal interests, even though the First Nations had not legally proved the existence of their Aboriginal rights and title (Olynyk 2005; SCC 2004b).

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24   Handbook of energy politics ●

Mikisew Cree First Nation v. Canada (Minister of Canadian Heritage) (2005). The SCC extended the Crown’s obligation to consult and accommodate Aboriginal interests (established earlier in the Haida and Taku cases) in order to include existing treaty rights (BC Treaty Commission 2008; SCC 2005). These general principles were later reaffirmed in the Grassy Narrows First Nations v. Ontario (Natural Resources) case (SCC 2014b). ● Tsilhqot’in Nation v. British Columbia (2014). The SCC’s Tsilhqot’in decision (2014) clarified the test for Aboriginal title relating to the elements of sufficient and exclusive occupation at the time of assertion of European sovereignty in 1846 (SCC 2014a). This is the first time that any court has formally declared that Aboriginal title exists to a particular tract of land outside of a reserve. The SCC’s decision also stated that without consent from First Nations which hold Aboriginal title to land, the government cannot approve developments on that land unless this infringement can be justified (SCC 2014a; Tsilhqot’in National Government 2014). ● Coastal First Nations v. British Columbia (Environment) (2016). The BC Supreme Court held that a portion of the Equivalency Agreement between BC EAO and the NEB was invalid and ruled that the Province cannot rely on Canada to discharge its constitutional duties of consultation and accommodation due to jurisdictional overlap (BCSC 2016; Robe and Dean 2016).

on a case-by-case basis, whereas treaty rights are negotiated and can be exhaustively set out and described in detail. The history of treaty making in British Columbia has been substantially different than it has been for the rest of Canada. In the past, the majority of BC’s Indigenous groups did not sign treaties, except for eight First Nations in the northeast quarter of BC, the signatories to Treaty 8 in 1899 (BC MARR 2016f). Until the negotiation of the Nisga’a Final Agreement (1998), almost all of the Province remained subject to outstanding Aboriginal land claims (INAC 2010b). The courts have confirmed that Aboriginal title still exists in BC, but they have not indicated where it exists. To resolve this situation, in 1993 the British Columbia Treaty Commission was established to facilitate the negotiation of treaties (BC Treaty Commission 2008). Currently, the Government of Canada, along with the Province, is negotiating with approximately 70 percent of BC’s First Nations through the BC Treaty Process (INAC 2010a). There are 65 First Nations that are participating in or have completed treaties through this negotiation process (BC Treaty Commission 2016). There are four First Nations that have already completed the six-stage BC Treaty Process and have their treaty final agreements ratified and implemented (BC MARR 2016b; INAC 2016a).

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Natural gas development in British Columbia  ­25 The Crown’s Duty to Consult with Indigenous Peoples Within the Environmental Assessment Process In accordance with Section 35 of the Constitution Act (1982), the Crown is legally obligated to consult on and, if necessary, accommodate asserted or established Aboriginal rights including Aboriginal title or treaty rights that may be impacted by Government decisions. This duty also stems from Canadian common law as expressed in court decisions. In the case of asserted Aboriginal rights and title, the scope of consultation is based on an assessment of the strength of claim and the seriousness of potential impacts upon the asserted rights. In the case of proven Aboriginal rights or treaty rights, the scope of consultation is based on the seriousness of the potential impact on the right (BC EAO 2013e; Province of BC 2010). BC EAO as the provincial responsible authority is obliged to consult and accommodate Aboriginal groups, in keeping with the Supreme Court of Canada’s direction in the Haida (SCC 2004a) and Tsilhqot’in (SCC 2014a) decisions (see Box 1.3 for details). The extent of the Crown’s obligation to consult is described in the Haida case as lying on a spectrum from notification to deep consultation, primarily regarding on the proximity of the proposed project to an Aboriginal group’s asserted traditional territory. BC EAO also considers the Tsilhqot’in decision in the EA process, and the BC EAO’s assessment of whether Aboriginal groups may have a prima facie claim to Aboriginal rights or title is intended to inform the level of consultation required for each Aboriginal group for the proposed project that can be potentially affected by the Crown’s activities. Consultations with Aboriginal groups at the higher end of the consultation spectrum include notification of key milestones, opportunities to review and comment on key documents, participation in the working group and procedural consultations. Consultations with Aboriginal groups at the lower end of the spectrum include notification of key milestones, invitation to meet with BC EAO to discuss any Aboriginal interests in the proposed project area and invitation to review and comment on the EAO’s draft assessment report (BC EAO 2013e). Announced by the Federal Government in 2016 interim principles for projects currently undergoing an EA process (see Box 1.1 for details), ­stipulating that Indigenous peoples will be meaningfully consulted and where appropriate, impacts on their rights and interests will be accommodated, have been recently applied to two projects: Pacific NorthWest LNG and Towerbirch Expansion (Government of Canada 2016a,b; NEB 2016). The former is an example of the successful application of these interim principles, including extensive consultations with Indigenous ­communities with funding of over $480 000 provided to support their ­participation in the

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26   Handbook of energy politics EA and establishing environmental monitoring committees comprised of Indigenous peoples and federal and provincial representatives, for the first time ever (Government of Canada 2016b). Potential Impacts on Indigenous Peoples’ Interests Identified in the Environmental Assessment Process A summary of the most common potential adverse impacts from the reviewed natural gas pipeline and LNG projects on Indigenous peoples’ interests is provided in Table 1.4. Data in the table are based on the review of EA reports prepared by BC EAO, the NEB or CEA Agency for the 18 projects where the provincial or federal EA process has been completed since 2010. Some other common concerns raised by Indigenous groups throughout the provincial or federal EA process for the natural gas pipeline and LNG projects included: ● ● ● ● ●

● ● ● ●

Economic development, business and employment opportunities and training. Economic effects including labor availability and wage inflation. Social effects, including housing availability and affordability. Impacts to community infrastructure, healthcare and emergency response. Accidents or malfunctions (for example, LNG vessel spills leading to contamination of shellfish; spill response plan; accidents at the facility). Environmental management plans, follow-up, monitoring and reporting. EA methodology regarding baseline information and VCs selection. Inadequate consideration of traditional land use/traditional ecological knowledge studies. Consultation (adequacy; determining who to consult; what constitutes consultation).

For several LNG projects where the provincial and/or federal EA processes are currently underway (including projects at pre-application stage with BC EAO), proponents anticipate that the following concerns may be raised by Aboriginal groups specifically with regard to potential impacts of the projects on the marine VCs (AltaGas Ltd. 2016; Nexen Energy ULC 2015; Prince Rupert LNG Limited 2014; Woodside Energy Holdings Pty Ltd. 2016):

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Natural gas development in British Columbia  ­27 Table 1.4  E  xamples of potential adverse impacts on Indigenous peoples’ interests identified in the environmental assessment process Valued component/ key indicator

Potential adverse impact

Health and socio-economic conditions

Change in human health – harvested foods, water quality, air emissions, noise Reduction in visual quality and change to the acoustic environment in areas of identified concern to Aboriginal owned or operated businesses Change in the availability of harvested foods for use by Aboriginal owned or operated businesses Alteration or loss of site-specific traditional land use Change in cultural practices Changes to intangible heritage resources/ expression of cultural values or ways of knowing Alteration of traditional subsistence activities, such as hunting, fishing, gathering and trapping Depletion of resources within Aboriginal traditional territories due to an increase in access Changes in preferred harvested species and traditional use sites Alteration/removal of archaeological/ cultural heritage sites, sacred sites, trails and culturally/spiritually important sites and culturally modified trees

Physical and cultural heritage

Current use of lands and resources for traditional purposes

Structure/site of historical or archeological significance

Projects with potential adverse impact identified 18/18 9/18

17/18 18/18 17/18 17/18 18/18 18/18 15/18 18/18

Sources:  BC EAO 2008, 2009, 2013c, 2014a,b,c,d, 2015b,e, 2016e; BC EAO et al. 2006; Canada and NEB 2015, 2016; CEAA 2013, 2016b; NEB 2015b,d.

●

Change in area available and/or accessible for marine fisheries and shoreline harvesting. ● Interference with Aboriginal fishing vessels and activities by vessel traffic and/or LNG shipping. ● Inhibiting Aboriginal groups’ access to preferred fishing locations due to LNG shipping.

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28   Handbook of energy politics ●

Marine surface water quality (potential issues from vessel propeller turbidity, disposal at sea, dredging, including toxicity of disturbed sediments). ● Marine fish and shellfish and their habitat (impacts of vessel wake on fish and fish habitat; potential affect to fish habitat due to ambient lighting issues and/or as a result of shadowing at the berth facility). ● Marine mammals (changes to behavior of marine mammals from LNG carriers and tugs, due to pressure waves and underwater noise; and direct mortality to marine mammals from ship strikes). ● Cumulative effects to marine use and resources. Cumulative effects remain a matter of critical importance for various Aboriginal groups potentially impacted by proposed natural gas pipeline and LNG projects. Many of them expressed concerns about the inadequacy of the cumulative effects assessment of past, present and reasonably foreseeable industrial activity in their traditional territory. Specifically, cumulative effects in northeast BC at a regional scale have been a concern of the Treaty  8 First Nations, including Blueberry, Saulteau, West Moberly and Fort Nelson First Nations, who are of the view that industrial development in the Western Canadian Sedimentary Basin and northeast BC has already and will continue to result in a reduced ability to exercise their treaty rights (Canada and NEB 2016). Significance of Potential Impacts to Aboriginal Interests The general BC EAO conclusion for the vast majority of the reviewed projects is that although there could be potential impacts to resources or values of importance to Aboriginal groups, the majority of this disturbance and impact would be expected to be short- to medium-term, during and following construction, and would be reversible shortly after construction. Assessment reports provided by BC EAO for each project with the completed provincial EA process concluded that the potential for adverse effects on the Aboriginal rights and Treaty 8 rights of Aboriginal groups has been avoided, minimized or otherwise accommodated to an acceptable level, and the provincial Crown has fulfilled its obligations for consultation and accommodation to Aboriginal groups relating to the issuance of an EAC for the proposed projects. For 17 of the 18 projects discussed in this section, with the provincial or federal EA processes completed, both BC EAO or NEB have been of the view that no significant adverse effects on the Aboriginal interests will occur as a result of the proposed projects, with the implementation

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Natural gas development in British Columbia  ­29 of impacts and benefits and other agreements (including follow-up environmental management and monitoring program agreements) established by the proponents with Aboriginal groups to address Aboriginal interests in relation to the proposed projects. The majority of issues raised during the review processes by Aboriginal groups were satisfactorily addressed through existing, revised or new commitments and project design changes made by the proponents, who have made efforts to avoid high value areas for Aboriginal groups (for example, by building on existing industrial lands, minimizing clearing wherever possible and providing appropriate mitigation measures to reduce the potential effects of project shipping). Aboriginal Consultation and Engagement Issues In 2015 Squamish Nation entered into separate agreements with the proponents of the Eagle Mountain – Woodfibre Gas Pipeline Project and the Woodfibre LNG Project that set out a process between the parties to discuss Squamish Nation’s EA of the two projects. This included an assessment of the potential effects of those projects on Squamish Nation’s asserted Aboriginal rights and title (the “Squamish Process”). As identified by Squamish Nation, there was a number of environmental issues of concern that may potentially affect their Aboriginal interests (BC EAO 2015e, 2016e). As a result of the Squamish Process, Squamish Nation approved the Woodfibre LNG EA Agreement and issued an EAC to the proponent (subject to the 13 conditions) and an EA Agreement in support of the Eagle Mountain Project (subject to the nine conditions). The negotiating team made it clear that the proponents and the Province must meet all of the Squamish Nation’s legally binding conditions, otherwise, Squamish Nation can either revoke the EA Agreements or pursue legal remedies in court to force the proponents to comply with the conditions (Squamish Nation Chiefs and Council 2016; Woodfibre LNG 2016). The Nak’azdli Whut’en First Nation announced in 2016 it would not proceed with any of agreements at this time involving the Coastal GasLink and Prince Rupert Gas Transmission Projects (Pynn 2016). The Luutkudziiwus, a Gitxsan Nation House Group, was strongly opposed to the Prince Rupert Gas Transmission Project, which crosses 34 km of their traditional territory. As of 2016 this Gitxsan Group was raising funds to launch a court challenge to overturn provincial approval and permits for the project on the basis they were not consulted (Hoekstra 2016). In January 2017 Gitxsan Nation Hereditary Chiefs announced a fourth federal lawsuit against the federal approval of the Pacific Northwest LNG project claiming the project would infringe their Aboriginal fishing rights (Jang 2017).

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30   Handbook of energy politics The Tsawwassen First Nation’s rejection to an LNG export facility on their territory near Delta, BC, represents an example of the difference of opinions within an Aboriginal community. While the leadership of the Tsawwassen First Nation had initially been supportive of the project, in 2015 53  percent of the band members voted to reject plans to build the proposed LNG facility on their traditional lands. As a result of the vote, the Tsawwassen First Nation said it would not be moving forward with any additional discussion regarding this proposed LNG concept (Canadian Press 2015).

5 KEY APPROACHES TO ADDRESS ENVIRONMENTAL AND INDIGENOUS PEOPLES’ ISSUES IDENTIFIED ON NATURAL GAS AND LNG PROJECTS Mitigation Measures to Avoid or Reduce Potential Adverse Effects When the provincial or federal EA process for a major natural gas pipeline or an LNG project is completed and approval is granted, an EAC, a CPCN or an EADS is issued, subject to the terms and conditions, including project design restrictions. The specified conditions form a part of the certificate or the decision statement and represent legally binding requirements that the proponent must meet to be in compliance with the certificate for the proposed project. It is not uncommon for an EA certificate to have over 100 commitments. For the 12 reviewed projects that have been approved by the provincial regulator (BC EAO), the amount of legally binding conditions for each project ranges from eight (Pacific NorthWest LNG) to 243 (Kitimat LNG Terminal). For the 11 reviewed projects that have been approved by the federal regulators (the NEB or the CEAA Agency) the amount of commitments for each project varies from 28 (Northwest Mainline Expansion) to over 190 (Pacific NorthWest LNG). Mitigation conditions proposed by the provincial and federal regulatory authorities do not necessarily overlap, and the federal agency may propose additional mitigation for consideration by the federal Minister of Environment as legally binding conditions in an EADS under the CEA 2012 (as it can be seen in the Pacific NorthWest LNG’s case). Certificate conditions are generally based on the results of consultation and input from Indigenous peoples, government agencies, communities and the public. To avoid or decrease potential adverse effects, proponents can also propose a number of pipeline route changes implemented as

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Natural gas development in British Columbia  ­31 project design restrictions based on feedback and input from Indigenous groups and the technical working groups during the EA process. Box 1.4 summarizes various types of mitigation to avoid or reduce potential adverse environmental effects of designated projects. Table 1.5 provides examples of some common mitigation measures split by the type of mitigation (a priority level in the mitigation hierarchy) based on the analysis of the legally binding conditions in the EACs, CPCNs or EADSs for the 18 reviewed natural gas pipeline and LNG projects  where  the provincial and/or the federal EA process has been completed. Environmental Management Plans and Follow-up Programs Environmental management plans (EMPs) would be required for all phases of proposed projects to implement mitigation measures and best management practices. EMPs and follow-up programs are usually developed in consultation with appropriate regulatory agencies, Indigenous groups and key stakeholders. Some of the EMPs and follow-up programs would be required by the provincial and/or federal agencies or authorities, while others would be incorporated into the EAC conditions as commitments made by the proponent. Examples of the most common EMPs identified through the analysis of the EA applications in relation to the environmental effects from the reviewed projects include plans for: an emergency response; erosion and sediment control; fish habitat offsetting; GHG management; invasive plant management; marine activities; noise management; waste management; wetland compensation; and so on (BC EAO 2015b,e; CEAA 2016b). Examples of the follow-up programs identified from the analysis of the EA applications for the reviewed projects include monitoring programs for: air quality; marine and surface water quality; fisheries and aquatic life; wildlife; vegetation, and so on (BC EAO 2015b,e; CEAA 2016b). Examples of Key Strategies and Progressive Programs Proposed by the Province Numerous regulatory and legislative measures to reduce GHG emissions across the Province have been implemented since 2008, including the provincial carbon tax; carbon-neutrality mandate for all public sector operations; mandatory GHG emissions reporting program for industrial facilities; potential cap-and-trade program and compliance offset scheme for large final emitters (BC MOE 2016b). In 2014 the Provincial

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32   Handbook of energy politics BOX 1.4 MITIGATION MEASURES TO AVOID OR REDUCE POTENTIAL ADVERSE EFFECTS The CEAA 2012 defines mitigation measures as “measures for the elimination, reduction or control of the adverse environmental effects of a designated project, and includes restitution for any damage to the environment caused by those effects through replacement, restoration, compensation or any other means.” The BC MOE defines a mitigation measure as action taken “to avoid, minimize, restore on-site, or offset impacts on environmental values and associated components, resulting from a project or activity” (BC MOE 2014b). According to BC EAO, compensation may include not only direct physical measures (for example, habitat enhancement, restoration or creation), but also financial mechanisms (for example, contributions to research and recovery plans, population enhancement programs, and so on) for reducing the residual effect of a project (BC EAO 2013d). Various types of mitigation can be prioritized in a hierarchy starting with the highest priority (avoidance). All feasible measures at the level of higher priority should be considered before moving to the next one of lower priority, with a rationale provided for this approach. However, it is not necessarily the case in practice, since moving through the hierarchy may not be completely linear (BC EAO 2013d; BC MOE 2014b). Avoidance should be considered at the initial project planning and route selection process. It can include assessing multiple pipeline route options within the proposed corridor and limiting the potential for adverse effects through route selection (for example, avoiding sensitive wildlife or wetlands habitat; avoiding key areas known to be important for Indigenous peoples; cooperating with another proponent in the same area and utilizing existing access roads where possible to reduce the project footprint). Impacts on some VCs within a project study area can be avoided through application of alternative timing for the project activities (for example, scheduling the clearing and construction activities to avoid the nesting period for migratory birds and restricted periods set out to protect watercourses and SARA-listed species) (BC EAO 2013d; BC MOE 2014b). Minimization as the next highest priority for application of mitigation should be considered when avoidance measures have been depleted or they are not feasible. The same procedures as those considered for avoidance can generally apply to minimization as well, since minimize means to partially avoid the level of impacts on VCs. It can also be considered at the initial route selection process (for example, locating the pipeline route along previously disturbed areas, including existing forestry cutblocks and access roads to reduce the overall proposed project footprint and minimize habitat fragmentation) (BC MOE 2014b). Restoration on-site involves returning the impacted ecosystem to a sustainable ecological pathway. Unlike the minimization measures, restoration may be implemented or completed at a future date. In the order of preference, the restore on-site measures include restoration, remediation and reclamation. To restore environmental VCs is usually much more expensive than it would be to conserve them by avoidance or by minimization of impacts (BC MOE 2014b). Monitoring and evaluation of the restoration for effectiveness is critical for determining whether the restoration project is achieving its targets.

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Natural gas development in British Columbia  ­33 Offset is the lowest priority in the mitigation hierarchy, and it should be implemented only after all previous steps to fully avoid, minimize and restore on-site have been properly considered. The responsibility for offsetting (either direct or indirect) rests with the proponent, who must provide the costs associated with offsetting by an in-lieu payment (BC MOE 2014b).

Government issued the Greenhouse Gas Industrial Reporting and Control Act that requires proponents to achieve an emissions intensity benchmark of 0.16 CO2e/t LNG. The BC MOE with support from Provincial Government agencies has developed management plans and recovery strategies to reduce the expected decline in caribou populations in BC, including the Implementation Plan for the Ongoing Management of Boreal Caribou in British Columbia (2011); the Interim Operating Practices for Oil and Gas Activities in Identified Boreal Caribou Habitat in British Columbia (2011); the Mountain Caribou Recovery Implementation Plan (2007) and other documents (BC MEM 2012; BC MOE n.d., 2011, 2014a; Government of BC 2011). The Province is also moving forward with initiatives that aim to assess and manage cumulative effects to key values, including vegetation and wildlife values, and to consider the impact to Aboriginal rights (BC EAO 2016d). Examples of those initiatives include, but are not limited to, the Cumulative Effects Framework, Area-Based Analysis, Northeast Water Strategy and Water Tool, LNG Environmental Stewardship Initiative and Regional Strategic Environmental Assessment (BC MARR 2016d; BC MFLNRO and BC MEM 2016; BC OGC 2015b,d; Province of BC 2015, 2016c). Indigenous Peoples: Consultations, Engagement and Agreements While the duty to consult Indigenous peoples rests with the Crown, the procedural aspects of consultation may be delegated to proponents. They are encouraged to engage with Indigenous peoples as early as possible in the planning stages in order to build relationships and continue throughout the lifecycle of the project (BC EAO 2013e; BC MARR 2016a). The Province of BC, BC  EAO and BC Ministry of Aboriginal Relations and Reconciliation (BC MARR) have developed a number of guidelines to assist proponents with meeting obligations to consult with Indigenous peoples (BC EAO 2013e; BC MARR 2014a, 2016a; Province of BC n.d., 2010). The proposed guidelines adopt a four-phased approach to the consultation procedures, including the preparation, engagement,

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34

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Pipeline route changes to avoid: Incursions into Old Growth Areas, parks and   protected areas Critical and sensitive habitat for species at risk   (for example, caribou, grizzly bear) Culturally sensitive and traditionally important   area for Indigenous peoples Alternative timing to avoid conducting activities   within the migratory bird nesting period Developing a number of environmental  protection plans/monitoring programs to minimize project impacts Locating a portion of the route parallel to  previously disturbed areas Reducing GHG emissions by using energy efficient equipment and power from the BC Hydro instead of natural gas

Avoidance

Minimization

Mitigation measures incorporated as certificate’s legally binding conditions

Type of mitigation

BC MOE 2010; BC MOE and BC MNGD 2014h, 2015b

BC MOE 2010; BC MOE and BC MNGD 2015b;  Canada and NEB 2010, 2016; MOE 2016; NEB 2011 BC MOE 2010; BC MOE and BC MNGD 2014c,h;  Canada and NEB 2010, 2012; MOE 2016; NEB 2010, 2011, 2015a BC MOE and BC MNGD 2015d, 2016b

BC MOE and BC MNGD 2014a,g,h, 2015d, 2016a

BC MOE and BC MNGD 2014a,g,h; NEB 2011

BC EAO 2016c; BC MOE and BC MNGD 2014a,g,h,  2016a,b

Examples of projects with the legal binding condition – references

Table 1.5  E  xamples of mitigation in legally binding conditions of environmental assessment certificates (EAC, CPCN and EADS)

35

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Offset

Restoration on-site

Developing a post-construction monitoring  plan and reports Providing funds to support conservation of  grizzly bear populations Developing a caribou offset measures plan Developing a fish compensation/ offsetting plan  with DFO and Transport Canada Compensation for permanent loss of wetlands  or wetland function Replacement or recruitment of Old Growth  Management Areas

Developing a site restoration and reclamation  program Preparing a caribou habitat restoration plan

Canada and NEB 2012; NEB 2011, 2015a BC MOE and BC MNGD 2015b; Canada and NEB  2010; MOE 2016 BC MOE and BC MNGD 2015b, 2016b; Canada and  NEB 2010; MOE 2016; NEB 2011 BC MOE and BC MNGD 2014a,g,h

BC MOE and BC MNGD 2014a,h, 2016a

BC EAO 2016c; BC MOE 2010; Canada and NEB 2010,  2012; NEB 2015a BC MOE and BC MNGD 2013a; Canada and NEB  2012; NEB 2011, 2015a Canada and NEB 2010, 2012; NEB 2011, 2015a

36   Handbook of energy politics a­ ccommodation, decision and follow-up phases each consisting of three to five steps (BC MARR 2014a; Province of BC n.d., 2010). Agreements with Indigenous peoples can help with building effective relationships and progressing toward sustainable and resilient Aboriginal communities. There are various types of agreements with Indigenous groups that have been negotiated within the Province to date; those specific to the natural gas and LNG industry include, but are not limited to, the LNG Environmental Stewardship Initiative, capacity-building initiatives and economic benefit agreements (BC MARR 2015c, 2016c,d,e). LNG Environmental Stewardship Initiative A new form of collaboration between the Province, Indigenous peoples (involving 32 First Nations as of July 2015) and the LNG sector that was established to ensure the balance between the environment and economic growth, provide strong environmental legacies related to LNG development and produce high quality, trusted and accessible environmental information (BC MARR 2014b, 2015b, 2016d). The Regional Strategic Environmental Assessment developed under the Stewardship Initiative aims to assess the cumulative effects of natural resource development activities on environmental VCs related to the Treaty 8 rights of the participating First Nations in northeast British Columbia (Province of BC 2016c). Capacity-building initiatives The Province is working with Indigenous peoples on all aspects of LNG opportunities in BC that include skills training, employment, consultation and accommodation work in regulatory decision-making and economic benefits sharing. In 2015 the Province launched a new Aboriginal Skills Training Development Fund that is an investment of up to $30  million over the next three years for new Aboriginal skills training projects and partnerships. The overall goal of this program is adding 15 000 more Indigenous workers to the Province’s workforce within ten years (BC MARR 2015a,c). As of June 2016, more than 1000 Indigenous peoples have already benefited from the training programs, with 85 percent graduating and finding a job (Pynn 2016). Proponents of natural gas pipeline and LNG projects also have the potential to provide important economic opportunities for Indigenous peoples, including capacity-building initiatives to support employment, contracting and business development. Examples of these initiatives have been specified by the proponents on a number of the reviewed projects (BC EAO 2014c; BC MARR 2015a,c). It is worthwhile noting that there is no legal obligation for proponents to provide capacity funding to Indigenous

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Natural gas development in British Columbia  ­37 groups as part of the consultation process. Nevertheless, proponents often chose to provide funding to help inform the consultation process and to avoid potential impacts to Aboriginal interests from the proposed project. These types of agreements should not be confused with any economic benefit agreements (BC EAO 2013e). Economic benefit agreements Examples of economic benefit agreements with Indigenous peoples include but are not limited to: ●

●

●

●

●

The Natural Gas Pipeline Benefits Agreements that are currently reached with 29 out of 32  eligible First Nations for four major natural gas pipelines, the Prince Rupert Gas Transmission, Coastal GasLink, Westcoast Connector Gas Transmission and Pacific Trail Pipeline (totaling in 62 agreements) (BC MARR 2015c, 2016e). The First Nations Limited Partnership Agreement which is unique among any pipeline agreements in Western Canada, since the Pacific Trail Pipeline Project is the first proposed natural gas pipeline related to LNG in BC with the support of all 16 directly affected First Nations (BC MARR 2015c; Chevron Canada 2016; FNLP 2016). The Coastal First Nations LNG Benefits Agreement signed by nine Coastal First Nations for ten proposed LNG projects to share in the benefits associated with the development of an LNG industry on the north coast of British Columbia (BC MARR and GBI Society 2016). Impact benefits agreements, including agreements with four of five Indigenous groups potentially affected by the Pacific NorthWest LNG project and four economic benefit agreements on natural gas exploration, development and production between the Province and the Treaty 8 First Nations (Hoekstra 2016; Province of BC 2014b). Revenue sharing agreements, for example, with Lax Kw’alaams and Metlakatla First Nations that share a portion of Provincial Government revenues from sole proponent agreements related to the Grassy Point lands and the proponents Aurora LNG (Aurora LNG Digby Island Project) and Woodside Energy (Grassy Point LNG Project), and so on (Province of BC 2014b).

It should be noted that economic benefits agreements are not legally required and must be kept separate and distinct from the duty to consult. By entering into impact benefits agreements, Indigenous peoples are not waiving their right to review, comment and approve or not, any

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38   Handbook of energy politics environmental studies, permit applications or environmental monitoring regimes related to the project (McCarthy Tétrault LLP 2016; McMillan LLP 2011).

6  CONCLUSIONS This chapter has reviewed a substantial amount of information on the major environmental and Indigenous peoples issues arising from natural gas and LNG development in British Columbia and the key approaches to address these issues. A regulatory framework for the natural gas and LNG industry in BC is robust, with many layers of government policies and regulations to guide responsible development of this sector. While the provincial and federal regulatory authorities work toward harmonization of the EA processes in order to avoid duplication of efforts and to clarify roles and responsibilities, these two regimes remain distinct and somewhat complex. It is very important for the proponents of the natural gas pipeline and LNG projects in BC to fully understand the provincial and federal EA processes in order to manage time frames and costs for the proposed projects where possible and to build effective relationships with stakeholders, Indigenous groups and the general public. The review of the EA applications for 29 major natural gas, NGL and LNG projects in British Columbia that have undergone a typical EA process (active or complete) with the provincial and/or federal responsible authority since 2010 identified the following key environmental issues: ●

Significant residual adverse effects related to GHG emissions. Significant residual adverse effects and cumulative effects to rare and threatened wildlife species (specifically, to caribou, grizzly bear and harbour porpoise). ● Cumulative adverse impacts of natural gas development. ●

Significant residual adverse effects related to GHG emissions have been reported on seven projects out of 18 where the provincial or federal EA has been completed. Significant residual adverse effects on caribou and caribou habitat were determined on three major natural gas pipeline projects out of 18 with the EA process completed, and were also determined as a key issue that should be fully compensated for on two other natural gas pipeline projects. The analysis of EA reports for six provincially and/or federally approved natural gas pipeline and LNG projects that include the marine resources VCs revealed impacts to marine mammals to be a

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Natural gas development in British Columbia  ­39 concern for several projects. The residual adverse effects and cumulative adverse effects on marine mammals (particularly, on harbour porpoise) were considered to be significant for one LNG project. There is a growing concern about the cumulative impacts of natural gas development arising from both stakeholders and the general public. For two reviewed projects, impacts to threatened wildlife species (caribou and grizzly bear) were considered as significant in terms of cumulative effects, but not in terms of project specific effects. These cumulative impacts will only become more significant with the increased intensity of natural gas and LNG development. Cumulative impacts are also of particular concern for Indigenous groups, with many of them unsatisfied with the adequacy of cumulative effects assessment of past, present and reasonably foreseeable industrial activity in their traditional territory, in relation to their respective Aboriginal interests. Other the most common potential adverse impacts on Aboriginal interests summarized in this chapter include but are not limited to effects on health and socio-economic conditions; physical and cultural heritage; the current use of lands and resources for traditional purposes; and sites of historical or archeological significance. Main approaches to mitigate the identified environmental issues include various types of mitigation measures (specified as legally binding conditions of the EAC, EADS or CPCN) to avoid, minimize, restore on-site or offset potential adverse effects. Pipeline route changes to avoid or decrease potential adverse effects can also be proposed as project design restrictions. In order to implement mitigation measures and best management practices, EMPs and follow-up programs would be required for all phases of proposed projects. They are usually developed by proponents in consultation with appropriate regulatory agencies, Indigenous groups and key stakeholders. In addition, the Province of BC has proposed, designed and implemented a number of key strategies, progressive programs and policies to reduce potential adverse effects of industrial development on the environmental VCs. Understanding of Aboriginal and treaty legal rights issues is fundamental to the potential success of proposed natural gas pipeline and LNG projects in British Columbia. A failure to understand these issues can affect the progress or even the regulatory approval of a proposed project. While the duty to consult Indigenous groups rests with the Crown, the regulatory authorities can assign certain procedural aspects of consultation to proponents. Industry must contact, involve and reach agreements with Indigenous peoples prior to commencing any operations in their traditional lands. The engagement of Indigenous peoples by proponents needs to start as early as possible, prior to the exploration phase and

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40   Handbook of energy politics continue throughout the lifecycle of the project, including construction, operations, decommissioning and abandonment. The Crown’s duty to consult and accommodate relates to avoiding or mitigating impacts on Aboriginal rights or title and does not imply an obligation to enter into any form of economic benefits agreement with Indigenous groups. Nevertheless, signing such agreements can build effective relations with Indigenous groups potentially affected by a proposed project. The importance of achieving and maintaining positive relationships, effective consultation and engagement with potentially affected Indigenous groups cannot be stressed enough and is one of the most critical factors for the success of the project.

NOTES *

The information presented in this chapter is based on the comprehensive study Risk Analysis of British Columbia Natural Gas Projects: Environmental and Indigenous Peoples Issues conducted by the authors on behalf of the Canadian Energy Research Institute. The Canadian Energy Research Institute is an independent, not-for-profit research establishment created through a partnership of industry, academia and government in 1975. The authors are grateful for the helpful insights received from Miles Scott-Brown (Integrated Environments Ltd.) and Dr Stella Swanson (Swanson Environmental Strategies). 1. The Pacific Trail Pipelines project was previously known as the Kitimat-Summit Lake Pipeline Looping project. 2. The term Indigenous peoples is increasingly replacing Aboriginal peoples, since the United Nations Declaration on Indigenous Peoples (2007), even though the term Aboriginal peoples still prevails in Canadian legislation. The term Indigenous peoples is generally considered to be more inclusive and respectful. For the purposes of this chapter, the authors will use the terms “Aboriginal peoples” and “Indigenous peoples” interchangeably, dependent on provincial versus federal legislation. 3. For the purposes of this chapter, the authors will use the term “First Nation(s),” unless referring to a document or event where the term “Indian” was used.

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Natural gas development in British Columbia  ­41 BC EAO (2013a), “Memorandum of understanding between the Canadian Environmental Assessment Agency and the British Columbia Environmental Assessment Office on Substitution of Environmental Assessments,” accessed 24 October 2016 at http://www.eao. gov.bc.ca/pdf/EAO_CEAA_Substitution_MOU.pdf. BC EAO (2013b), “Extension Order Issued under Section 18 of the Environmental Assessment Act and an Application to Extend Environmental Assessment Certificate E08-01 for the Pacific Trail Pipelines Project,” accessed 26 September 2016 at http://a100. gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_270.html. BC EAO (2013c), “Fortune Creek Gas Project assessment report,” accessed 22 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_379.html. BC EAO (2013d), “Guideline for the selection of valued components and assessment of potential effects,” accessed 6 October 2016 at http://www.eao.gov.bc.ca/pdf/EAO_Valued_ Components_Guideline_2013_09_09.pdf. BC EAO (2013e), “Guide to involving proponents when consulting First Nations in the environmental assessment process,” accessed 6 October 2016 at http://www2.gov.bc.ca/ gov/content/environment/natural-resource-stewardship/consulting-with-first-nations. BC EAO (2013f), “Schedule B. Documentation and correspondence considered by the environmental assessment office: Dawson Liquids Extraction Project,” accessed 20 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_399.html. BC EAO (2014a), “Coastal GasLink Pipeline Project assessment report,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_392.html. BC EAO (2014b), “Westcoast Connector Gas Transmission Project assessment report,” accessed 22 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_proje​ ct_home_385.html. BC EAO (2014c), “Pacific Northwest LNG Project assessment report,” accessed 22 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_396.html. BC EAO (2014d), “Prince Rupert Gas Transmission Project assessment report,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_4​ 03.html. BC EAO (2015a), “Environmental Assessment Office user guide: An overview of environmental assessment in British Columbia,” accessed 17 October 2016 at http://www.eao.gov. bc.ca/pdf/EAO_User_Guide_20150629.pdf. BC EAO (2015b), “LNG Canada Export Terminal Project assessment report,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_3​ 9​8.html. BC EAO (2015c), “Fact sheet: Substitution of environmental assessments in British Columbia,” accessed 22 September 2016 at http://www.eao.gov.bc.ca/pdf/Fact_Sheet_LN​ G%​20Canada%20Substitution_17JUN15.pdf. BC EAO (2015d), “Summary of evaluation for the proposed Saturn 15-27 Sweet Gas Plant Project,” accessed 20 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/ epic_project_home_434.html. BC EAO (2015e), “Woodfibre LNG Project assessment report,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_408.html. BC EAO (2016a), “Environmental assessment process,” accessed 19 October 2016 at http:// www.eao.gov.bc.ca/ea_process.html. BC EAO (2016b), “Project Information Centre (E-PIC) – Project detail report,” accessed 29 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_detail_ report.html. BC EAO (2016c), “Amendment #4 to the Certificate #E08-01 for the Pacific Trail Pipelines Project,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/ epi​c_​pr​o​ject_home_270.html. BC EAO (2016d), “Northeast British Columbia Expansion Project assessment report,” accessed 22 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_pro​ ject_home_433.html. BC EAO (2016e), “Eagle Mountain – Woodfibre Gas Pipeline Project assessment report,”

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42   Handbook of energy politics accessed 22 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_ project_home_406.html. BC EAO, Transport Canada, Environment Canada and Indigenous and Northern Affairs Canada (2006), “Kitimat LNG Terminal Project assessment report,” accessed 26 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_244.html. BC MARR (British Columbia Ministry of Aboriginal Relations and Reconciliation) (2014a), “Guide to involving proponents when consulting First Nations,” accessed 6 October 2016 at http://www2.gov.bc.ca/gov/content/environment/natural-resource-stewardship/ consulting-with-first-nations. BC MARR (2014b), “B.C. to engage with First Nations, industry on eco-stewardship,” BC Government News, 23 May, accessed 31 October 2016 at https://news.gov.bc.ca/stories/ bc-to-engage-with-first-nations-industry-on-eco-stewardship. BC MARR (2015a), “B.C. boosts investment in Aboriginal skills training,” BC Government News, 24 April, accessed 30 October 2016 at https://news.gov.bc.ca/stories/ bc-boosts-investment-in-aboriginal-skills-training. BC MARR (2015b), “Funding supports LNG environmental legacies,” BC Government News, 29 July, accessed 31 October 2016 at https://news.gov.bc.ca/releases/2015ARR0032-001206. BC MARR (2015c), “Factsheet: Partnering with First Nations on LNG development,” BC Government News, 14 December, accessed 30 October 2016 at https://news.gov.bc.ca/ factsheets/partnering-with-first-nations-on-lng-development. BC MARR (2016a), “Consulting with First Nations – Province of British Columbia,” accessed 6 October 2016 at http://www2.gov.bc.ca/gov/content/environment/natural-resou​ rce-stewardship/consulting-with-first-nations. BC MARR (2016b), “First Nations in treaty process – Province of British Columbia,” accessed 6 October 2016 at http://www2.gov.bc.ca/gov/content/environment/naturalresource-­steward​ship/consulting-with-first-nations/first-nations-negotiations/first-na​ti​o​ ns-in-treaty-process. BC MARR (2016c), “First Nations negotiations,” accessed 24 October 2016 at http:// www2.gov.bc.ca/gov/content/environment/natural-resource-stewardship/consulting-withfi​rst-nations/first-nations-negotiations. BC MARR (2016d), “Liquefied Natural Gas environmental stewardship initiative – Province of British Columbia,” accessed 30 October 2016 at http://www2.gov.bc.ca/gov/content/ environment/natural-resource-stewardship/consulting-with-first-nations/liquefied-natur​ al-gas-environmental-stewardship-initiative. BC MARR (2016e), “Natural Gas Pipeline benefits agreements – Province of British Columbia,” accessed 21 September 2016 at http://www2.gov.bc.ca/gov/content/­environme​ nt/natural-resource-stewardship/consulting-with-first-nations/first-nations-negoti​ations/ natural-gas-pipeline-benefits-agreements. BC MARR (2016f), “Treaty 8 First Nations – Province of British Columbia,” accessed 6 October 2016 at http://www2.gov.bc.ca/gov/content/environment/natural-resource-­steward​ ship/consulting-with-first-nations/first-nations-negotiations/first-nations-a-z-listing/tr​e​ aty-8-first-nations. BC MARR and GBI Society (2016), “Coastal First Nations Liquefied Natural Gas benefits agreement between Great Bear Initiative Society and British Columbia,” accessed 20 September 2016 at http://www2.gov.bc.ca/assets/gov/environment/natural-resource-­ steward​ship/consulting-with-first-nations/agreements/cfn_lng_signed_jan_2016.pdf. BC MEM (British Columbia Ministry of Energy and Mines) (2012), “British Columbia’s natural gas strategy. Fuelling B.C.’s economy for the next decade and beyond,” accessed 7 October 2016 at http://www2.gov.bc.ca/assets/gov/farming-natural-resources-andindustry/natural-gas-oil/strategy_natural_gas.pdf. BC MFLNRO (British Columbia Ministry of Forests, Lands and Natural Resource Operations) and BC MEM (2016), “Cumulative effects framework – Province of British Columbia,” accessed 17 October 2016 at http://www2.gov.bc.ca/gov/content/environment/ natural-resource-stewardship/cumulative-effects-framework. BC MOE (British Columbia Ministry of Environment) (n.d.), “Boreal Caribou management

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Natural gas development in British Columbia  ­43 in BC,” accessed 28 September 2016 at http://www2.gov.bc.ca/gov/content/environment/ plants-animals-ecosystems/wildlife/wildlife-conservation/caribou/boreal-caribou. BC MOE (2010), “Information bulletin. Cabin Gas Plant Project approved,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_341. html. BC MOE (2011), “Implementation plan for the ongoing management of Boreal Caribou (Rangifer tarandus caribou pop. 14) in British Columbia,” Victoria, BC. BC MOE (2014a), “Mountain caribou recovery in BC,” accessed 28 October 2016 at http:// www.env.gov.bc.ca/wld/speciesconservation/mc/. BC MOE (2014b), “Procedures for mitigating impacts on environmental values (environmental mitigation procedures). Version 1.0,” accessed 6 October 2016 at http://www.env. gov.bc.ca/emop/docs/EM_Procedures_May27_2014.pdf. BC MOE (2016a), “Caribou in British Columbia,” accessed 16 October 2016 at http://www. env.gov.bc.ca/wld/speciesconservation/. BC MOE (2016b), “Climate action legislation – Province of British Columbia,” accessed 28 October 2016 at http://www2.gov.bc.ca/gov/content/environment/climate-change/poli​ cy-legislation-programs/climate-action-legislation#cngreg. BC MOE and BC MEMPR (British Columbia Ministry of Energy, Mines and Petroleum Resources) (2006), “Environmental assessment certificate #E06-01 for the Kitimat Liquefied Natural Gas Terminal Project,” accessed 21 September 2016 at http://a100.gov. bc.ca/appsdata/epic/html/deploy/epic_project_home_244.html. BC MOE and BC MEMPR (2008), “Environmental assessment certificate #E08-01 for the Kitimat-Summit Lake Pipeline Looping Project,” accessed 21 September 2016 at http:// a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_270.html. BC MOE and BC MEMPR (2010), “Environmental assessment certificate #E09-06 for the Cabin Gas Plant Project,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/ epic/html/deploy/epic_project_home_341.html. BC MOE and BC MNGD (British Columbia Ministry of Natural Gas Development) (2013a), “Fortune Creek Gas Plant. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 22 September 2016 at http://a100.gov.bc.ca/appsdata/ epic/html/deploy/epic_project_home_379.html. BC MOE and BC MNGD (2013b), “Environmental assessment certificate # E13-03 for the Fortune Creek Gas Project,” accessed 22 September 2016 at http://a100.gov.bc.ca/ appsdata/epic/html/deploy/epic_project_home_379.html. BC MOE and BC MNGD (2014a), “Coastal GasLink Pipeline Project. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_392.html. BC MOE and BC MNGD (2014b), “Environmental assessment certificate #E14-03 for the Coastal GasLink Pipeline Project,” accessed 21 September 2016 at http://a100.gov.bc.ca/ appsdata/epic/html/deploy/epic_project_home_392.html. BC MOE and BC MNGD (2014c), “Pacific Northwest LNG Project. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_396.html. BC MOE and BC MNGD (2014d), “Environmental assessment certificate #E14-04 for the Pacific Northwest LNG Project,” accessed 21 September 2016 at http://a100.gov.bc.ca/ appsdata/epic/html/deploy/epic_project_home_396.html. BC MOE and BC MNGD (2014e), “Environmental assessment certificate #E14-05 for the Westcoast Connector Gas Transmission Project,” accessed 22 September 2016 at http:// a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_385.html. BC MOE and BC MNGD (2014f), “Environmental assessment certificate #E14-06 for the Prince Rupert Gas Transmission Project,” accessed 22 September 2016 at http://a100.gov. bc.ca/appsdata/epic/html/deploy/epic_project_home_403.html. BC MOE and BC MNGD (2014g), “Prince Rupert Gas Transmission Project. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_403.html.

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44   Handbook of energy politics BC MOE and BC MNGD (2014h), “Westcoast Connector Gas Transmission Project. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_​ 385.html. BC MOE and BC MNGD (2015a), “Environmental assessment certificate #E15-01 for the LNG Canada Export Terminal Project,” accessed 22 September 2016 at http://a100.gov. bc.​ca/appsdata/epic/html/deploy/epic_project_home_398.html. BC MOE and BC MNGD (2015b), “LNG Canada Export Terminal Project. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 22 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_398.html. BC MOE and BC MNGD (2015c), “Environmental assessment certificate #E15-02 for the Woodfibre LNG Project,” accessed 22 September 2016 at http://a100.gov.bc.ca/appsdata/ epic/html/deploy/epic_project_home_408.html. BC MOE and BC MNGD (2015d), “Woodfibre LNG Project. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 21 September 2016 at http:// a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_408.html. BC MOE and BC MNGD (2016a), “Eagle Mountain – Woodfibre Gas Pipeline Project. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_4​ 06.html. BC MOE and BC MNGD (2016b), “Northeast British Columbia Expansion Project. Schedule B. Table of conditions for an environmental assessment certificate,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_4​33.html. BC MOE and BC MNGD (2016c), “Environmental assessment certificate #E16-01 for the Eagle Mountain – Woodfibre Gas Pipeline Project,” accessed 22 September 2016 at http:// a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_406.html. BC MOE and BC MNGD (2016d), “Environmental assessment certificate #E16-02 for the Northeast British Columbia Expansion Project,” accessed 22 September 2016 at http:// a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_433.html. BC OGC (British Columbia Oil and Gas Commission) (2015a), “Hydrocarbon and byproduct reserves in British Columbia,” accessed 3 November 2016 at https://www.bcogc. ca/node/12952/download. BC OGC (2015b), “NorthEast water tool,” accessed 9 January 2017 at https://water.bcogc. ca/newt. BC OGC (2015c), “Defining: LNG & major projects,” accessed 23 October 2016 at http:// www.bcogc.ca/node/11415/download. BC OGC (2015d), “Industry bulletin 2015-20. Area-based analysis required in application process,” accessed 28 October 2016 at http://www.bcogc.ca/node/12694/download. BC Treaty Commission (1999), “A lay person’s guide to Delgamuukw,” accessed 9 October 2016 at http://www.bctreaty.net/sites/default/files/delgamuukw.pdf. BC Treaty Commission (2008), “Why treaties? A legal perspective,” accessed 9 October 2016 at http://www.bctreaty.net/sites/default/files/why_treaties_update_Aug08.pdf. BC Treaty Commission (2016), “Negotiation update: BC Treaty Commission,” accessed 9 January 2017 at http://www.bctreaty.net/negotiation-update. BCSC (Supreme Court of British Columbia) (2016), Coastal First Nations v. British Columbia (Environment) – 2016 BCSC 34. Supreme Court of British Columbia. Canada (2012), “Regulations Designating Physical Activities SOR/2012-147,” accessed 23 October 2016 at http://laws-lois.justice.gc.ca/PDF/SOR-2012-147.pdf. Canada and NEB (National Energy Board) (2010), “Reasons for decision in the matter of NOVA Gas Transmission Ltd.: Application dated 30  April 2009 for the Groundbirch Pipeline Project,” Calgary, Alberta: National Energy Board. Canada and NEB (2012), “Reasons for decision in the matter of NOVA Gas Transmission Ltd.: Application dated 29 April 2011 for the Northwest Mainline expansion,” Calgary, Alberta: National Energy Board. Canada and NEB (2013), “National Energy Board report in the matter of NOVA Gas

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Natural gas development in British Columbia  ­45 Transmission Ltd.: Application dated 14 October 2011 for the Northwest Mainline Komie North extension. GH-001-2012,” Calgary, Alberta: National Energy Board. Canada and NEB (2015), “National Energy Board report in the matter of Nova Gas Transmission Ltd. Application dated 8 November 2013 for the North Montney Mainline Project: GH-001-2014,” Calgary, Alberta: National Energy Board. Canada and NEB (2016), “National Energy Board report in the matter of NOVA Gas Transmission Ltd. Application dated 2 September 2015 for the Towerbirch Expansion Project. GH-003-2015,” Calgary, Alberta: National Energy Board. Canadian Press (2015), “Tsawwassen First Nation rejects proposed LNG facility,” Vancouver Sun, 17 December. CAPP (Canadian Association of Petroleum Producers) (2016), Statistical Handbook for Canada’s Upstream Petroleum Industry, Calgary, Canada. CEAA (Canadian Environmental Assessment Agency) (2013), “Environmental impact statement guidelines,” accessed 6 October 2016 at https://www.ceaa-acee.gc.ca/050/documents/ p80019/87455E.pdf. CEAA (2015a), “Assessing cumulative environmental effects under the Canadian Environmental Assessment Act, 2012,” Ottawa, Canada. CEAA (2015b), “Ministerial statement. Government of Canada’s decision on the environmental assessment of the LNG Canada Export Terminal Project,” June 17, accessed 26 September 2016 at http://www.ceaa-acee.gc.ca/050/document-eng.cfm?document=101849. CEAA (2016a), “Basics of environmental assessment,” accessed 22 September 2016 at https:// www.canada.ca/en/environmental-assessment-agency/services/environmental-­assessm​e​ nts/basics-environmental-assessment.html. CEAA (2016b), “Pacific NorthWest LNG Project Environmental Assessment Report,” accessed 28 September 2016 at http://www.ceaa.gc.ca/050/documents/p80032/115668E. pdf. CERI (Canadian Energy Research Institute) (2016), “Canadian natural gas market review. Study No. 158,” accessed 3 November 2016 at http://resources.ceri.ca/PDF/Pubs/Studies/ Study_158_Full_Report.pdf. Chevron Canada (2016), “Pacific Trail Pipeline,” accessed 26 September 2016 at http://www. chevron.ca/our-businesses/kitimat-lng-project/pacific-trail-pipeline. DFO (Department of Fisheries and Oceans Canada) (2009), “Management plan for the Pacific harbour porpoise (Phocoena phocoena) in Canada. Species at Risk Act Management Plan Series,” Ottawa, Canada: Fisheries and Oceans Canada. Environmental Reporting BC and BC MOE (2012), “Grizzly bear population status in BC (2012),” accessed 29 September 2016 at http://www.env.gov.bc.ca/soe/indicators/ plants-and-animals/print_ver/2012_Grizzly_Bear_Population_Status_BC.pdf. FNLP (First Nations Limited Partnership) (2016), “First Nations Limited Partnership,” accessed 26 September 2016 at http://bcfnlp.ca/. Government of BC (2011), “Interim operating practices for oil and gas activities in identified boreal caribou habitat in British Columbia,” accessed 25 October 2016 at http://www.env. gov.bc.ca/wld/speciesconservation/bc/documents/Operating%20Practices.pdf. Government of Canada (2013), “National inventory report: Greenhouse gas sources and sinks in Canada – Government of Canada Publications,” accessed 8 November 2016 at http:// www.publications.gc.ca/site/eng/9.506002/publication.html. Government of Canada (2015), “Intended nationally determined contribution: Canada’s INDC submission to the UNFCCC,” accessed 17 October 2016 at http://www4.unfccc.int/submis​ sions/INDC/Published%20Documents/Canada/1/INDC%20-%20Canada%20-%20English. pdf. Government of Canada (2016a), “Statement. Government of Canada moves to restore trust in environmental assessment,” Government of Canada News, 27 January, accessed 27 September 2016 at http://news.gc.ca/web/. Government of Canada (2016b), “News release. The Government of Canada approves Pacific NorthWest LNG Project,” Government of Canada News, 27 September, accessed 27 September 2016 at http://news.gc.ca/web/.

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46   Handbook of energy politics Government of Canada and NEB (2016), “NEB – Applications & filings,” accessed 24 October 2016 at https://www.neb-one.gc.ca/pplctnflng/index-eng.html. Hoekstra, G. (2016), “First Nation support for Pacific NorthWest LNG growing,” Vancouver Sun, 29 April. INAC (Indigenous and Northern Affairs Canada) (2010a), “About British Columbia First Nations,” accessed 28 September 2016 at https://www.aadnc-aandc.gc.ca/eng/. INAC (2010b), “The Nisga’a final agreement in the Canadian context,” accessed 11 October 2016 at http://www.aadnc-aandc.gc.ca/eng/. INAC (2016a), “Treaty negotiations in British Columbia,” accessed 28 September 2016 at https://www.aadnc-aandc.gc.ca/DAM/DAM-INTER-BC/STAGING/texte-text/trynega_11​ 0​010​00​21019_eng.pdf. INAC (2016b), “Métis rights,” accessed 9 October 2016 at http://www.aadnc-aandc.gc.ca/ eng/. Jang, B. (2017), “Two Gitxsan chiefs seek to block Pacific NorthWest LNG terminal construction,” The Globe and Mail, 10 January. McCarthy Tétrault LLP (2016), “Liquefied Natural Gas (LNG) Regulation in British Columbia. August 2016,” accessed 7 October 2016 at https://www.mccarthy.ca/pubs/ LNG_Regulation_in_BC_(August_2016).pdf. McMillan LLP (2011), “Seven steps for navigating the environmental assessment process in British Columbia,” accessed 31 October 2016 at http://www.mcmillan.ca/Files/143329_ seven%20steps%20for%20navigating%20the%20environmental%20assessment%20proc​ ess​%20in%20British%20Columbia.pdf. MOE (Ministry of Environment Canada) (2016), “Decision statement issued under Section 54 of the Canadian Environmental Assessment Act, 2012 for the Pacific NorthWest LNG Project,” accessed 28 September 2016 at http://www.ceaa.gc.ca/050/documents/ p80032/115669E.pdf. NEB (National Energy Board) (2010), “Order XG-W102-07-2010 for the Fort Nelson North Processing Facility Project,” accessed 22 September 2016 at https://apps.neb-one.gc.ca/ REGDOCS/Item/View/565873. NEB (2011), “Reasons for decisions in the matter of NOVA Gas Transmission Ltd. application dated 19 February 2010 for the Horn River Project GH-2-2010,” accessed 16 October 2016 at https://apps.neb-one.gc.ca/REGDOCS/Item/View/601085. NEB (2012), “Draft environmental screening report for the Northwest Mainline expansion pursuant to the Canadian Environmental Assessment Act (CEA Act). Northwest Mainline Expansion,” accessed 26 October 2016 at https://apps.neb-one.gc.ca/REGDOCS/Item/ View/685859. NEB (2015a), “Certificate of Public Convenience and Necessity GC-125 for the North Montney Mainline Project,” accessed 22 September 2016 at http://www.ceaa-acee.gc.ca/05​ 0/d​ocuments/p80057/101998E.pdf. NEB (2015b), “ARCHIVED – NOVA Gas Transmission Ltd. – Horn River Project – GH-22010,” accessed 28 September 2016 at http://www.neb-one.gc.ca/pplctnflng/mjrpp/archive/ hrnrvr/nvgshrnrvr-eng.html. NEB (2015c), “ARCHIVED – NOVA Gas Transmission Ltd. – Northwest Mainline Expansion – GH-2-2011,” accessed 27 September 2016 at http://www.neb-one.gc.ca/ pplctnflng/mjr​pp/archive/nrthwstmnlnxpnsn/nrthwstmnlnxpnsn-eng.html. NEB (2015d), “ARCHIVED – NOVA Gas Transmission Ltd. (NGTL) – Groundbirch Pipeline Project – GH-1-2009,” accessed 28 September 2016 http://www.neb-one.gc.ca/ppl​ c​tn​flng/mjrpp/archive/grndbrch/grndbrch-eng.html. NEB (2016), “Summary of recommendation. NGTL Towerbirch Expansion Project,” accessed 7 October 2016 at http://www.neb-one.gc.ca/pplctnflng/mjrpp/twrbrch/twrbrch-eng.pdf. Nexen Energy ULC (2015), “Application information requirements and valued components selection document for the proposed Aurora LNG Project at Digby Island,” accessed 27 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_4​ 1​6.html. Olynyk, John M. (2005), “The Haida Nation and Taku River Tlingit decisions: Clarifying

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Natural gas development in British Columbia  ­47 roles and responsibilities for Aboriginal consultation and accommodation,” accessed 11 October 2016 at http://www.lawsonlundell.com/media/news/236_Negotiatorarticle.pdf. Pacific Northern Gas Ltd. (2014), “Application information requirements for the Pacific Northern Gas Looping Project,” accessed 6 September 2016 at http://a100.gov.bc.ca/ appsdata/epic/html/deploy/epic_project_home_405.html. Prince Rupert LNG Limited (2014), “Application information requirements for the Prince Rupert LNG,” accessed 6 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/ deploy/epic_project_home_402.html. Province of BC (n.d.), “Building relationships with First Nations: Respecting rights and doing good business,” accessed 29 October 2016 at http://www2.gov.bc.ca/gov/content/ environment/natural-resource-stewardship/consulting-with-first-nations. Province of BC (2002), “Reviewable projects regulation, BC Reg 370/2002,” accessed  23 October 2016 at http://www.bclaws.ca/civix/document/id/loo79/loo79/13_370_2002. Province of BC (2008), “Climate action plan,” accessed 17 October 2016 at http://www.gov. bc.ca/premier/attachments/climate_action_plan.pdf. Province of BC (2010), “Updated procedures for meeting legal obligations when consulting First Nations. Interim,” accessed 6 October 2016 at http://www2.gov.bc.ca/gov/content/ environment/natural-resource-stewardship/consulting-with-first-nations. Province of BC (2014a), “Addressing cumulative effects in natural resource decision-making: A framework for success,” accessed 17 October 2016 at http://www2.gov.bc.ca/gov/conte​ nt/en​vironment/natural-resource-stewardship/cumulative-effects-framework. Province of BC (2014b), “B.C. and First Nations sign first LNG revenue-sharing ­agreements,” BC Government News, 9 April, accessed 31 October 2016 at https://news.gov.bc.ca/stori​ es/bc-and-first-nations-sign-first-lng-revenue-sharing-agreements. Province of BC (2015), “Northeast water strategy,” accessed 28 October 2016 at http://www2. gov.bc.ca/assets/gov/environment/air-land-water/water/northeast-water-strategy/2015-no​ r​theast-water-strategy.pdf. Province of BC (2016a), “B.C. LNG projects – LNG in BC,” accessed 24 October 2016 at http://lnginbc.gov.bc.ca/tile/bc-lng-projects/. Province of BC (2016b), “Climate leadership plan,” accessed 17 October 2016 at https:// climate.gov.bc.ca/app/uploads/sites/13/2016/10/4030_CLP_Booklet_web.pdf. Province of BC (2016c), “Edition: LNG environmental stewardship initiative,” BC Government News, accessed 28 October 2016 at https://news.gov.bc.ca/newsletters/ lng-environmental-stewardship-initiative/lng-environmental-stewardship-initiative/regi onal-highlights. Pynn, L. (2016), “First Nations overwhelmingly support LNG, B.C. minister asserts,” Vancouver Sun, 7 June. RCAP (Royal Commission on Aboriginal People) (1996), “Perspectives and realities: Métis perspectives,” in Report of the Royal Commission on Aboriginal People, vol. 4., accessed 12 October 2016 at http://caid.ca/RRCAP4.5.pdf. Robe, K.B. and P.A. Dean (2016), “Case Comment: Coastal First Nations v. British Columbia (Environment), 2016 BCSC 34,” accessed 11 October 2016 at http://www.mondaq.com/ canada/x/511790/Oil+Gas+Electricity/Case+Comment+Coastal+First+Natio​ns+v+Briti sh+Columbia+Environment+2016+BCSC+34. Salmo Consulting Inc. and Diversified Environmental Services (2003), “Cumulative effects indicators, thresholds and case studies: Volume 2,” accessed 18 October 2016 at https:// www.alces.ca/projects/download/242/CEAMF-Final-Report2.pdf. SCC (Supreme Court of Canada) (1973), “Calder et al. v. Attorney-General of British Columbia,” 1973 S.C.R. 313. SCC (1990), “Her Majesty the Queen v. Ronald Edward Sparrow,” 1990 1 S.C.R 1075. SCC (1997), “Delgamuukw v. British Columbia,” 1997 3 S.C.R. 1010. SCC (2003), “Her Majesty the Queen v. Steve Powley and Roddy Charles Powley,” 2003 SCC 43. SCC (2004a), “Haida Nation v. British Columbia (Minister of Forests),” 2004 SCC 73. SCC (2004b), “Taku River Tlingit First Nation v. British Columbia (Project Assessment Director),” 2004 SCC 74.

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48   Handbook of energy politics SCC (2005), “Mikisew Cree First Nation v. Canada (Minister of Canadian Heritage),” 2005 SCC 69. SCC (2014a), “Tsilhqot’in Nation v. British Columbia,” 2014 SCC 44. SCC (2014b), “Grassy Narrows First Nation v. Ontario (Natural Resources),” 2014 SCC 48. Squamish Nation Chiefs and Council (2016), “Squamish Nation FortisBC environmental assessment agreement bulletin,” accessed 22 September 2016 at http://www.squamish.net/ wp-content/uploads/2016/06/Membership-Bulletin-Fortis-EA-Agreement_JAK_01237855. pdf. Stantec Consulting Ltd. (2014), “Progress Proposed Town North Gas Project. Project Description Under the British Columbia Environmental Assessment Act,” accessed 21 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/epic_project_home_42​ 8.html. Statistics Canada (2013), “Statistics Canada: 2011 national household survey Aboriginal population profile,” accessed 7 November 2016 at http://www12.statcan.gc.ca/nhs-enm/20​ 11/dp-pd/aprof/index.cfm?Lang=E. Tsilhqot’in National Government (2014), “Summary of the Tsilhqot’in Aboriginal title case (William Case) decision,” accessed 11 October 2016 at http://www.tsilhqotin.ca/PDFs/20​ 14_07_03_Summary_SCC_Decision.pdf. UBC First Nations and Indigenous Studies (2009), “Royal Proclamation, 1763,” accessed 12 October 2016 at http://indigenousfoundations.arts.ubc.ca/home/government-policy/ royal-proclamation-1763.html. WCC LNG Project Ltd. (2016), “Application information requirements for the WCC LNG Project,” accessed 27 September 2016 at http://a100.gov.bc.ca/appsdata/epic/html/deploy/ epic_project_home_429.html. WesPac Midstream (2016), “Valued component selection document for the WesPac Tilbury Marine Jetty Project,” accessed 27 September 2016 at http://a100.gov.bc.ca/appsdata/epic/ html/deploy/epic_project_home_435.html. Woodfibre LNG (2016), “Squamish Nation reaches environmental assessment agreement with FortisBC on Eagle Mountain – Woodfibre Gas Pipeline Project,” Woodfibre LNG. June 27, accessed 22 September 2016 at http://www.woodfibrelng.ca/squamish-­nation-reachesenvironmental-assessment-agreement-with-fortisbc-on-eagle-mountain-woodfibre-gaspipeline-project/. Woodside Energy Holdings Pty Ltd. (2016), “Application information requirements for the Grassy Point LNG Project,” accessed 27 September 2016 at http://a100.gov.bc.ca/ appsdata/epic/html/deploy/epic_project_home_422.html. WWF-Canada and UNBC-CIRC (2015), “Cumulative effects assessment and management: Sharing knowledge and building capacity in the North Coast (Workshop Summary Report),” accessed 18 October 2016 at http://awsassets.wwf.ca/downloads/cumulative_ effects_assessment_and_management___sharing_knowledge_and_building_capacit_2. pdf.

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2.  Oil on the waters of RIC energy relations Nina Poussenkova

A MARRIAGE MADE IN HEAVEN? Traditionally, Russia’s energy policy has been focused on Europe, its historic strategic partner. Their energy interdependence is long-standing and solid, with over 30 percent of the OECD Europe crude imports and more than 70 percent of gas imports coming from Russia in 2016. That year, nearly 60 percent of Russia’s crude oil exports and more than 75 percent of Russia’s natural gas exports went to OECD Europe.1 This European domination of Russia’s energy exports remained practically unchallenged in the early years of Russian reforms. During the 1990s with their low oil prices, the Russian oil and gas companies were facing too many difficulties at home to try conquering new markets. The government was too busy coping with the domestic political, economic and social collapse to attempt forging petroleum relations with Asia-Pacific. Moreover, Russia’s attitude to its two major potential energy customers in the region, Japan and China, was shadowed by the unresolved issue of the “Northern Territories” with the former, and by numerous geopolitical and territorial disputes with the latter. The “Chinese threat” had also affected the traditionally complicated relations between the neighbors. Indeed, as James Henderson from the Oxford Institute of Energy Studies notes, “China’s economic growth has dwarfed that achieved by Russia, and the latter has always been concerned that in supplying the energy to fuel further growth it could just become a ‘resource appendage’ providing further strength to its historic rival.”2 Another Asian giant was virtually ignored. Despite the long-standing cooperation and generally friendly Soviet–Indian relations, including in the oil and gas sphere, Russia did not really consider India with its growing appetite for foreign hydrocarbons a serious energy opportunity at that time. However, the 2000s, with their greater political and economic stability in Russia and with rising world oil prices, prompted Russia to try diversifying its energy exports away from the stagnating Europe and to aim at the Asia-Pacific premium market, primarily at China. Also, a RIC (Russia-India-China) concept was put forward by Yevgeny Primakov at the end of 1990s that envisaged a new triangle of emerging power in 49

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50   Handbook of energy politics the East to counterbalance the Western, particularly the US influence. A stronger Russia of the 2000s intended to play the leading role in RIC. Another driver of Russian energy policy’s Eastern vector was the urgent need to revitalize East Siberia and the Far East, the regions that occupy some 60 percent of Russia’s territory and account for 10 percent of its population. The deteriorating socio-economic situation in this strategic area and the resulting depopulation is one of the most serious domestic challenges Russia currently faces (particularly given the close proximity of Russia’s East to China). Russia also had to establish a new oil and gas province to supplement the aging West Siberia that currently accounts for some 60 percent of Russia’s crude production, and East Siberia and the Far East seemed to be the obvious choice. One of the draft versions of the Energy Strategy of Russia up to 2035 predicted that production in West Siberia would decrease to 288 mt by 2035, while that of East Siberia and the Far East would grow to 107 mt.3 Therefore, the development of Eastern energy riches could partially replace the main petroleum province of Russia (and, in addition, improve living standards in the region). Consequently, it seemed feasible to deliver Eastern oil and gas to China in order to take advantage of their geographic proximity. During the 2000s, state companies, Rosneft and Gazprom, with the full blessing and support of the government gradually displaced private players, such as YUKOS and TNK-BP, in the strategic Eastern region and began to implement the Asian vector of the state energy policy. So, on the state level, Russia’s turn to the East was determined, on the one hand, by long-term strategic geopolitical, economic, commercial and social considerations. On the other hand, short-term tactical motives played their role as well: Russia wanted to demonstrate to Europe that it had other attractive energy opportunities, thus putting pressure on its European partners. In March 2006, when relations of Gazprom with its EU customers deteriorated after the first gas war with Belarus, Vladimir Putin visited China. A MoU on the construction of the ESPO spur to China was signed, as well as a protocol on gas deliveries that should have begun in 2011. The frightened EU consumers signed long-term contracts with Russia, which Moscow intended to achieve from the very beginning. Rosneft, that wanted to become a global energy company, also had long-term strategic considerations for Going East: it wanted to find its niche in the Chinese market, and diversify its export routes. Still, Rosneft pursued its own corporate agenda as well: meeting its financial needs because of the massive debts that it incurred through its policy of aggressive acquisitions of Russian private players. At the same time, the Chinese “Going Abroad” policy was launched

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Oil on the waters of RIC energy relations  ­51 in 2001. Becoming a net importer of oil in 1993, China surpassed the United States at the end of 2013 as the world’s largest net importer of crude, according to EIA. BP forecasts that China’s share in global energy demand will grow from 23 percent in 2015 to 26 percent in 2035. Oil import dependence will rise from 61 percent in 2015 to 79 percent in 2035.4 Therefore, ensuring energy security by diversifying petroleum supplies and finding equity oil abroad became truly a matter of life and death for China. Chinese NOCs pursue the “Going Abroad” policy along four key directions: buying of assets and companies, establishment of alliances with other NOCs and IOCs, as well as deals of the type “resources for market access” and “loans-for-oil.” Given this complex set of internal and external factors, the Russian state began to make a particular focus on the Eastern vector of its energy policy in the new millennium. In late 2009 the Energy Strategy of Russia up to 2030 was adopted that stated that: the share of the European direction in the total volume of exports of Russian fuel and energy resources will steadily decline due to diversification of export energy market in the Eastern direction (China, Japan, South Korea, Pacific Rim countries) . . . By the end of the third state of implementation of the Strategy the proportion of Eastern direction in the export of liquid hydrocarbons (oil and petroleum products) will grow from the current 6 percent to 22–25 percent, and in gas exports from 0 to 19–20 percent.5

In the gas sphere where Russia and China were for a long time “engaged to be engaged” their relations have been thoroughly researched by various international and Russian experts. In the oil sphere, Russia and China have been “married” for more than a decade, but not very happily. Their “marriage” (and the recent appearance of a new player in the eternal RIC triangle, India) has been virtually ignored by analysts, and this chapter attempts to fill the gap. The international sanctions against Russia, which denied Russian companies access to global capital markets and deprived them of foreign technology and equipment for the Arctic, deepwater and shale projects, pushed Rosneft even more to PRC as the only possible source of finance. However, the sanctions strengthened the already very strong position of the Chinese companies at negotiations with their Russian counterparts, since China indeed has a wide choice of partners and suppliers of crude worldwide. Sanctions also contributed to the dramatic change in Russians’ perception of China. The recent public opinion polls show that people consider PRC to be a friend #3 of Russia (after Belarus and Kazakhstan). Meanwhile, their attitude to the West, particularly the US, is worsening.

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52   Handbook of energy politics It is noteworthy that the percentage of respondents who regard China as Russia’s friend has grown from 20 percent in 2013 to 43 percent in 2015, however, then decreased to 34 percent in 2016.6 Presumably, the Russians are not worried that China will “swallow” Russia. They seem to appreciate that PRC does not make any political demands, for example, for promoting democracy in Russia, in contrast to the West. Therefore, it seems logical that the draft Energy Strategy up to 2035 that is being developed during the sanctions puts an even greater emphasis on the Eastern direction: it formulates the following strategic objective, “growth of volumes and diversification of external and internal deliveries of liquid hydrocarbons, including more than doubling of deliveries of crude oil and petroleum products to the APR markets.”7 So, theoretically Russia and China could have been ideal energy partners: the biggest owner of reserves and petroleum exporter, and the biggest (and fastest growing) consumer of hydrocarbons. But still Europe remains the key counterpart of Russia in the oil and gas sphere, while PRC is more successfully establishing cooperation with other hydrocarbon producers. And the growing petroleum rapprochement between Russia and China creates additional uncertainties in the global energy scene, and new long-term challenges for Russia that are slightly alleviated by the recent Rosneft–India deals.

IN THE BEGINNING THERE WAS MONEY It is noteworthy that the “Turn to the East” was originally initiated by Rosneft in the direction of India. In February 2001, Rosneft and the Indian ONGC Videsh signed a deal concerning the Sakhalin-1 project whereby Rosneft sold half of its share (20 percent) to India and also got reimbursement of past expenditures and exemption from further investments up to the beginning of commercial production. This deal facilitated a big contract with India for deliveries of weapons, starting with 310 T-90C tanks. Actually, the idea about selling a part of Russian share in Sakhalin-1 emerged after the 1998 crisis. Depressed world oil prices and the August default forced Rosneft to rethink its ambitions about Sakhalin projects where it initially demanded a minimum 30 percent interest. In November 1998, Sergey Bogdanchikov, president of Rosneft, said: “Rosneft is not the world’s largest company. Twenty percent would suffice for us.”8 However, at that time no buyers were found, probably because of unclear prospects of the Russian economy and risks inherent in Sakhalin-1. In 2000, Bogdanchikov repeatedly stated that Rosneft faced difficulties with

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Oil on the waters of RIC energy relations  ­53 raising credits to finance participation in Sakhalin projects, and was short of its own funds,9 and this time his voice was heard at the very top. It is unclear what was more important for the government, to sell weapons or to save Rosneft’s money, but, apparently, this deal helped to kill two birds with one stone. But after that the Indian vector was put on hold for almost 15 years (though the two companies signed an MoU in 2007 planning to participate in joint projects in Russia, India and the third countries, and another MoU in May 2014 on cooperation on the Arctic shelf), and Rosneft almost exclusively focused on PRC.10 Significantly, it was Mikhail Khodorkovskiy who initiated petroleum dialogue with China. YUKOS was the master of “Big Oil” in the East of Russia. In the late 1990s, it was the first Russian oil company to show interest in East Siberia and see a potential major market in PRC. YUKOS began cooperation with China in 1999, having delivered by railway the first cargo of 12,000 tons. YUKOS’ railway exports to China grew rapidly, and Mikhail Khodorkovskiy decided to build the Angarsk-Daquing oil pipeline. In 1999, YUKOS, Transneft and CNPC began to prepare relevant documents. In May 2003, the heads of YUKOS and CNPC signed a long-term contract for oil deliveries via the future pipeline: 20 mt/yr for the first five years, and 30 mt/yr after 2010. The Angarsk-Daquing pipeline promoted by YUKOS competed for a while with the Angarsk-Nakhodka pipeline lobbied by Transneft. The YUKOS version with the length of 2,247 km would have cost $1.7 bln, while the Transneft option with the length of 3,765 km, $5.2 bln. AngarskDaquing would have been profitable with the throughput of 20 m/yr, while Angarsk-Nakhodka with 50 mt/yr. However, deliveries of crude to the Nakhodka port would have permitted diversifying markets, while the Angarsk-Daquing option would have made Russia dependent on China. At that time, the choice between two routes would have been determined by political considerations.11 In Spring 2003 a compromise was proposed: to build the AngarskNakhodka pipeline with a spur to Daquing. However, soon the Ministry of Natural Resources vetoed both projects for environmental reasons. After that, the YUKOS case began; the government of Mikhail Kasyanov who supported the Angarsk-Daquing option resigned, and for a while the pipelines were forgotten. But soon a new powerful player reinvented the Eastern vector of Russia’s oil policy. The 2000s were the era of Rosneft’s renaissance: it evolved from a minor player with 20 mt/yr production in 2001 into a giant with 210 mt/yr in 2016.12 In principle, the revival of the company began in 1998, when Sergey Bogdanchikov was appointed its president. But

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54   Handbook of energy politics after Vladimir Putin was elected Russia’s president in 2000 and began to promote etatization of economy, particularly of its energy sector, Rosneft started to aggressively recapture its positions in the oil industry. This process intensified when the political heavyweight Igor Sechin, deputy head of the presidential administration, became BoD chairman of Rosneft in July 2004. He exercised a considerable influence over the energy sector of Russia, being appointed vice-premier in charge of energy issues in 2008 (which also strengthened Rosneft’s status). Since 2009, according to Forbes and Vedomosti, Sechin has been considered the second most influential person in Russia after Putin.13 In 2012, Igor Sechin became president of Rosneft – and the process of Rosneftization of the Russian oil sector gained a new momentum. Rosneft and personally Igor Sechin are the drivers of RIC oil relations. Since Russia–China energy cooperation is a strategic issue, Russian top leaders were actively involved in all key negotiations with China (and now with India). However, as the decision-making process at the highest level in Russia is not exactly transparent, is Rosneft the tail that wags the dog in RIC oil relations? Indeed, though the role of the state in Russia is decisive, energy policy is made largely by powerful state-owned oil and gas companies pursuing their own corporate and commercial interests, as Nikita Lomagin notes.14 The same question can now be asked about the oil breakthrough with India. Ironically, having become the number one oil company in Russia after the acquisition of YUKOS’ assets, Rosneft inherited its vision for petroleum cooperation with China. It acts along several closely interrelated directions: raising of Chinese credits, lobbying the construction of ESPO and a spur to China, increasing crude exports to PRC, providing access of Chinese companies to Russian upstream and entering the Chinese downstream. Actually, the Russian–Chinese oil relations made a breakthrough after Rosneft acquired Yuganskneftegaz, the main subsidiary of YUKOS, for $9.35 billion in December 2004. In 2005, the Chinese banks lent Rosneft $6 billion to repay its debts. It was the first time in Russian history that Chinese money was used to finance the redistribution of assets in the domestic oil industry. Afterwards a pattern was established when, following each major acquisition, Rosneft turned to China for funds. In return, Rosneft pledged to export 48.8 mt of oil to China by railway up to 2010. The terms of the contract were not disclosed, and, therefore, rumors were rife that the price of oil was set too low. Rosneft was in such a hurry to get the Chinese money that it agreed to rather unfavorable conditions: crude price was linked to Brent, initially with a $3 discount. In November 2007, the state company negotiated the reduction of discount to $2.325.15 Later, it tried to reduce it even further, but without success.

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Oil on the waters of RIC energy relations  ­55 In general, the contract price was somewhat higher than the market one: the average discount of Urals to Brent was $3.8/bar in 2005–07. But analysts calculated that transportation costs made Rosneft’s deliveries to China less profitable than to Europe. Even with higher price, Rosneft reported opportunity costs, and the CNPC contract remained problematic, primarily because of the delay with the launch of ESPO. However, many experts admit that since the state company urgently needed money to pay for Yuganksneftegaz, the contract terms might have been considerably less attractive for Rosneft.16 And thus, the first Chinese credit helped to open the door for Russian large-scale crude deliveries to China and for the Chinese NOCs to the Russian oil sector.

THEN THERE WAS A PIPELINE On December 31, 2004, Prime Minister Mikhail Fradkov signed an ordinance on the construction of the East Siberia–Pacific Ocean (ESPO)17 pipeline in 2005–20. Officially, this geopolitical project intended to open a window to the East, according to Vladimir Putin’s statement. Unofficially, it was meant to put pressure on Europe which, as the former president of Transneft Semyon Vainstock said, “we have overfed with our oil.”18 A vicious circle existed for a long time in the East of Russia: oil fields were not developed since there was no export pipeline, and pipelines were not built because there was no crude to load them. ESPO broke this vicious circle, and Rosneft and personally Sergey Bogdanchikov made a weighty contribution to the process by actively lobbying the construction of the pipeline and commissioning fields in East Siberia. The state company by that time became the owner of the biggest deposits in the region, such as Vankor, Verkhnechonsk and Yurubcheno-Tokhomsk. Currently, Rosneft’s recoverable reserves of oil and condensate in East Siberia and the Far East (A, B, C1+C2 categories) amount to 2.4 bln tons. In the mid-2000s, Rosneft chose between two options of oil transportation from Vankor. The Northern option envisaged pumping crude to Dikson in the Arctic Ocean, and then by tankers to Europe, the US or other destinations. The Southern option targeted delivering oil to Purpe and further to China by Transneft’s trunk pipelines. The first option seemed commercially more attractive. However, Bogdanchikov had to choose the second one: the political decision to build ESPO was made, but there was not enough oil to pump. So, Rosneft was forced to serve the state interests to the detriment of its own economic considerations.19 Vankor

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56   Handbook of energy politics helped to load ESPO, the construction of which was seriously delayed, partly because of the lack of clarity about the resource base for the pipeline. Afterwards, Bogdanchikov actively lobbied ESPO construction: in August 2005, he pleaded with Vladimir Putin “to ask the government and the regional authorities to pay more attention to the pipeline . . . Otherwise, billions of our dollars would be frozen.”20 Presumably, Bogdanchikov’s arguments convinced Putin. He instructed Prime Minister Fradkov to speed up the pipeline project. After all delays ESPO was launched in 2009, a year later than scheduled. Currently, there are plans to expand ESPO capacity at Taishet-Skovorodino section to 80 mt/yr, and at Skovorodino-Kozmino to 50 mt/yr by 2020.21 Rosneft also became an active lobbyist of the spur to China. It was back in 2006 that Transneft and CNPC signed a protocol on the construction of the Skovorodino–Chinese border pipeline. Initially, this 15 mt/yr project was scheduled to begin in 2007 and finish by the end of 2008, simultaneously with the launch of the first stage of ESPO. However, its progress was halted, mainly because of controversies between the Russians and the Chinese on the price of Russian crude. The strategic decision on the spur to China depends on the agreements about the price of oil delivered to China, said Victor Khristenko, then Minister of Energy, in particular, whether it would be possible to raise the price under the 2005 contract of Rosneft. Besides, Vladimir Yakunin, then head of Russian Railways, an extremely powerful lobbyist, was strongly against the project: crude was delivered to China by railway in the absence of the pipeline.22 On March 14, 2008, Nikolai Tokarev, president of Transneft, asked Vice-Premier Sergei Naryshkin to speed up the decision on the spur to China. Transneft’s worry was understandable, since the design of the second stage of ESPO and the capacity of the Kozmino port depended on the availability of the spur.23 Still, a tangible progress was achieved only in February 2009, when Vice-Premier Igor Sechin visited China.24 This breakthrough became possible mainly due to the financial crisis in Russia and the growing need for money of Rosneft and Transneft. During the visit, four documents were signed: two agreements of Russian companies with China Development Bank on the long-term $25 billion credit, a 20-year contract between CNPC and Rosneft on oil deliveries, as well as a contract between Transneft and CNPC on construction and operation of the SkovorodinoMohe pipeline. According to Article 13 of the Agreement between the Governments of RF and PRC on Oil Cooperation, Transneft and Rosneft received exclusive rights of access to the spur for 20 years. This ensured indisputable competitive advantages for the state company over its private rivals

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Oil on the waters of RIC energy relations  ­57 operating in the East of Russia. They would have to use the pipeline to Kozmino which is some 2,000 km longer; therefore, their costs would be much higher, while Rosneft would save about $20/ton.25 Indeed, the government as a shareholder takes good care of its company. In September 2010, the construction of the 15 mt/yr spur was finished, and crude transportation began in January 2011. In 2014, works were completed to expand the Skovorodino-Mohe spur to 20 mt/yr; by end of 2017, its capacity should grow to 30 mt/yr.26 The Chinese started to build the Mohe-Daquing section with a total length of 925 km in May 2009 and finished in Summer 2010. Then, in 2014 CNPC froze the further expansion of the spur from 15 mt to 30 mt/yr. It wanted to limit annual transportation of oil through Skovorodino-Mohe to 20 mt and export the rest through Kozmino and Kazakhstan since it has a program of developing refineries in its north-west.27 Transneft was against these plans because it was worried about its investments made into the expansion of the spur to 30 mt.28 Since CNPC did not manage to build the necessary infrastructure on time, Rosneft already faced difficulties in 2015 with implementing its 2013 contract (see further on): it planned to deliver 32 mt to APR, including 29 mt to China in 2015, and needed all the available capacity of ESPO.29 Still, changing its mind once again, on June 19, 2015 CNPC signed a construction contract for the second domestic 15 mt/yr pipeline to carry Russian crude from Mohe to Daquing.30 Presumably, it will be completed by the end of 2017. Commenting on CNPC’s decision to expand the capacity of the MoheDaquing spur, BMI Research experts said: The promise of greater access to China’s large, growing domestic market has proven very attractive to Russian suppliers, who have accelerated their Asian pivot following the restrictive sanctions. CNPC’s pipeline seeks to improve the connectivity of Russian crude oil supplies to a larger consumer base within the Chinese market.31

THEN THERE WERE CRUDE EXPORTS Traditionally, Europe was the key market of Russian crude. However, it is now competing with Asia’s steadily increasing share. Underscoring the importance of the Asian direction, APR receives the new Russian export blend: ESPO blend that was launched in late 2009 and is a mix of crudes produced in several Siberian fields. ESPO is a fairly sweet, medium-light oil, with gravity of 35.7°API and 0.48 percent sulfur content, that is, it is of higher quality than the Urals that the EU receives.32

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58   Handbook of energy politics Also, the recent decision to use RMB in settlements for oil will probably strengthen Russia’s positions in China. In general, Russia and China are important trading partners. In 2015, trade turnover between Russia and China amounted to $68 bln (28.6  percent less than in 2014), Russian exports to China were $33 bln  (–20 percent) and Russian imports from China, $34 bln (−35.2 percent). However, Russian–Chinese trade is rather unbalanced. In 2015, deliveries of “mineral fuels, oil and petroleum products” accounted for 60.7 percent of value of Russian exports to China. By contrast, machines and equipment (including oil and gas field equipment) account for 37 percent of Chinese export to Russia. This structure of Russian exports to China, and the growth of oil shipments consolidate the resource orientation of Russian economy, and strengthen concerns about the possibility of it becoming the “resource colony” of PRC. The falling oil prices have taken their toll on Russia’s crude exports to China. In January–December 2015, Russian deliveries of “mineral fuels, oil and petroleum products” decreased by 0.2 percent to 65.6 mt, while their total value dropped by 32.2 percent vs. 2014 to $20.19 bln. Deliveries of oil grew by 28.2 percent to 42.43 mt; however, their value declined by 31.1 percent to $17.23 bln.33 Rosneft is the main (and actively growing) supplier of Russian oil to Asia-Pacific (Figure 2.1), though Surgutneftegas also delivers certain amounts of crude produced in Yakutiya. In 2014, total oil exports by Rosneft amounted to 102.4 mt, including 61.1 mt to Europe and other directions, 33.5 to Asia Pacific (33 percent of 50.00 40.00 30.00 20.00 10.00 0.00 2009

2010

2011

2012

2013

2014

2015

2016

Source:  Rosneft Annual Reports.

Figure 2.1  Rosneft’s oil exports to APR, 2009–2016, mt/yr

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Oil on the waters of RIC energy relations  ­59 Table 2.1  Prices for Rosneft’s oil by destination, 2014, 2013 and 2012

Average price on   foreign markets Thousand rubles/ton Crude oil, non-CIS Europe and other   directions Asia Thousand rubles/barrel Crude oil, non-CIS Europe and other   directions Asia

2014

2013

2012

26.0 26.4

24.2 24.8

23.7 24.2

25.1

22.7

21.6

3.51 3.57

3.29 3.37

3.24 3.37

3.40

3.08

2.95

Source:  Rosneft (2014) “Management’s discussion and analysis of financial condition and results of operations for the quarters ended December 31, 2014 and September 30, 2014, and for twelve months ended December 31, 2014, 2013 and 2012,” p. 28.

the total) and 7.8 mt to CIS. In 2015, its total oil exports grew to 109.1 mt, including 60.4 mt to Europe and other directions, 39.7 mt to Asia Pacific (36 percent of the total) and 9.0 mt to CIS.34 Out of these 39.7 mt, 30.2 mt were supplied to China (21 percent more than in 2014); and deliveries to China under long-term contracts grew by 18 percent, to 26.6 mt.35 In 2016, Rosneft exported 114.9 mt in total, including 43.1 mt to APR. In addition, a considerable proportion of petroleum product export is now directed to APR: in 2014, 43.6 mt went to Europe and other directions, and 11.7 mt to Asia-Pacific; in 2015, 46.3 mt went to Europe and 13.2 mt to Asia-Pacific.36 Rosneft claims that “among export directions, the Eastern direction, i.e. deliveries by pipeline to China and sales in the Kozmino and De-Castri ports, remains the most economically attractive for the company.”37 However, according to Rosneft’s report,38 its average sales price of crude to Asia has been consistently lower than the average international sales price and a price of its oil sold in Europe (Table 2.1). Still, Rosneft intends to further increase its exports to China. Igor Sechin predicted that by 2019 its share of exports to the APR will reach 40 percent vs. 33 percent in 2014 and 36 percent in 2015. As Igor Sechin stated in his 2015 address to Rosneft’s shareholders: Rosneft, while preserving its old markets, is mastering new export routes, and continues to increase its presence in the promising Asia-Pacific region.

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60   Handbook of energy politics This task is our undoubted priority, though, of course, not to the detriment of cooperation with our European partners. In 2014, deliveries to the Eastern direction already grew by more than 40%. We plan to increase them by another 30% in 2015.39

However, despite his official statement, this ambitious target will probably be implemented at the expense of the Europe-bound oil exports. With the slightly rising crude production in Russia and gradually growing domestic consumption, the increase of exports to China can only be compensated by the decrease of shipments to Europe. Mikhail Krutikhin from RusEnergy commented, “the general trend of redirecting oil flows has been observed for a long time, and now we can say with confidence that Russia’s oil will not be enough both for Europe and Asia.”40 Moreover, competition at the EU oil market will intensify. Saudi Arabia, the US and Iran are ready to increase petroleum exports to Europe which will result in a partial displacement of Russia. Saudi Aramco already delivered the first shipment of crude to Poland at lower prices than those offered by Russia. Responding to the ensuing concern of Russian oil companies, the Minister of Energy Alexander Novak admitted that the era of the “cut-throat competition” is coming.41 “Our share in oil deliveries to Europe will shrink. I think we’ll lose up to 10 percent, but, objectively, Russia cannot provide such discounts as Saudis do. The way out is to reorient at the Asian markets,” believes Sergei Hestanov from the Russian Academy of National Economy and Public Administration.42 However, it seems to be the case of the proverbial “chicken and egg” dilemma: the shrinking of the Russia’s share in the European market was, presumably, partly caused by Russia’s shift to Asia. The sanctions turned out to be an additional driver of Russian companies’ expansion to APR, as Seth Kleinman from CitiGroup indicates: I believe that the turn to the East of Rosneft and other Russian companies can be primarily explained by the fact that they think they were squeezed from the West because of sanctions. I know that people in Russia are indignant about the sanctions; however, ironically, they should be perceived with certain gratitude. Because I am not sure that heads of Russian companies really understood how important it was that the fight was now about the share of the Asian market. And that Russia is now fully participating in this fight only because it was pushed away from the West and turned to the East.43

Indeed, the niche of Russian oil at the Chinese market is steadily growing. In 2014, it became supplier number three to China, after Saudi Arabia and Angola; its share in the Chinese market grew from 9 percent to 11 percent, while the share of Saudi Arabia shrank from 19 percent to 16 percent. Two years later the change was even more dramatic. According to EIA, of the

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Oil on the waters of RIC energy relations  ­61 Chinese 7.6 mln b/d of 2016 crude oil imports, the lion’s share was supplied by Russia (14 percent of total imports), Saudi Arabia (13 percent), Angola (11 percent), Iraq (10 percent), Oman (9 percent) and Iran (8 percent).44 In 2005–16, Rosneft already delivered more than 186 mt worth over $95 bln to China. According to the company, the total volume of deliveries within the framework of long-term contracts will ultimately exceed 700 mt.45 However, despite these impressive results and ambitious plans of Rosneft, the fight for the Chinese oil market is no holds barred, with Saudi Arabia, Angola, Iran and Iraq aiming at maintaining their leading positions. Traders of Iraqi oil are ready to dump even in the low price environment.46 Amrita Sen from Energy Aspects Ltd confirms that “imports from Iraq and Iran have also been growing recently. Saudi Arabia is aggressively trading its oil; therefore we expect that China will be quite selective and price-sensitive, given the broad range of suppliers.”47 Indeed, there are certain factors that can limit Russia’s oil export to China, for example, slowdown of demand and growing competition, according to Valeriy Nesterov from Sberbank CIB. Saudi Arabia has unbeatable competitive advantages: considerable spare capacity and flexible logistics. Meanwhile, Russian companies are constrained by throughput of pipelines and ports in the East. Pipeline potential is limited since China did not expand its part of the spur on time. Therefore, Russian oil is delivered by pipeline to Vladivostok and then by tankers to China, which makes deliveries more expensive. Thus, Russia will hardly be able to maintain its position as the leading importer of oil into China in the long term.48 Moreover, the Chinese crude imports are quite well diversified. Also, though China plans to lessen its dependence on the Middle East oil, it does not intend to become critically dependent on exports from Russia.

RUSSIAN UPSTREAM Thanks to Rosneft, the Chinese companies entered the Russian upstream which they had hoped to access for a long time.49 Fortune smiled at them after they helped Rosneft to pay for Yuganskneftegaz. In 2005, Rosneft invited Sinopec with 25.1 percent to the Veninsk Block of Sakhalin-3. Sinopec committed to cover a proportion of Rosneft’s expenditures for geological and exploration activities, and provide a certain amount of financing at the development stage.50 Now, geological activities have been completed at the block, and the partners are waiting for the production license.

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62   Handbook of energy politics Then, in August 2006, Sinopec purchased from TNK-BP 96.96 percent of its subsidiary Udmurtneft51 for $3.5 billion through the company Promleasing. In December 2006 Rosneft exercised an option on buying 51 percent of Promleasing from Sinopec.52 Besides Sinopec, the Hungarian MOL, a consortium of Itera and Indian ONGC, as well as Gazprom neft, the oil subsidiary of Gazprom, were interested in Udmurtneft. Representatives of Gazprom complained that a “political decision” was made in favor of the state oil company (and, presumably, its Chinese partner).53 Furthermore, during Vladimir Putin’s 2006 visit to Beijing, Rosneft and CNPC signed a cooperation agreement. Under it, in mid-2006, Rosneft (51 percent) and CNPC (49 percent) formed a Vostok Energy JV to explore and produce hydrocarbons in Russia. In Summer 2007, Vostok Energy bought licenses for two small fields in the Irkutsk region located near ESPO.54 However, despite the promising beginning, no real activities are reported by the JV. China further strengthened its ties with Rosneft by becoming its shareholders. During its IPO, CNPC bought 0.6 percent of Rosneft’s shares for $500 mln.55 In general, Chinese NOCs prefer to have an equity stake in overseas crude production; they are not interested in purely oil deliveries. However, they are not prepared to overpay for foreign assets, which Rosneft discovered to its chagrin. Thus, in 2013, Rosneft (51 percent) and CNPC (49 percent) agreed to establish a JV to operate in East Siberia on the basis of Taas-Yuryakh Neftegazdobycha, license holder for the SredneBotuobinskoye field.56 Presumably, Rosneft offered 30 percent in TaasYuryakh to CNPC. However, this deal collapsed because the partners could not agree on its terms: “the Chinese were offering too little,” said an informed source.57 And a representative of CNPC confirmed that the price gap was too big.58 The same year, Rosneft signed agreements with CNPC on joint activities in the Arctic. The Chinese NOC was supposed to work on the Zapadno-Prinovozemelskiy plot in the Barents Sea and Yuzhno-Russkiy and Medynsko-Varandeiskiy plots in the Pechora Sea. However, CNPC is not eager to start implementing challenging Polar projects because of the disagreements with Rosneft on prices, high costs and unclear economics of Arctic exploration. During sanctions, when Russian companies lost their international partners in the Arctic, deepwater and shale projects, and the financial position of Rosneft continued its aggressive acquisition policy deteriorated, search for solvent partners became even more urgent. Therefore, at the Davos Forum in January 2015, First Vice-Premier

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Oil on the waters of RIC energy relations  ­63 Igor Shuvalov said that “China could become a strategic partner for Russia in the oil and gas sector, since China is stable and predictable.”59 However, the recent conflicts between Russian and Chinese companies concerning the “iron-clad contract” of 2009 (see further on) and the construction of the second line of Mohe-Daquing pipeline show that Chinese predictability is rather exaggerated. Formulating the government’s approach to the Chinese investments, Vice-Premier Arkady Dvorkovich said at the Krasnoyarsk Economic Forum in February 2015 that Russia was ready to discuss a possibility of providing control in oil and gas projects to Chinese partners, meaning strategic fields (excluding shelf). “There is a special subject, i.e. shelf, where we invite Chinese partners as minority partners, but there are no such limitations with respect to most other projects,” emphasized Dvorkovich.60 Actually, Dvorkovich referred to the potential deal on the strategic onshore field. On November 9, 2014, Rosneft and CNPC signed a framework agreement on the purchase of 10 percent of Vankorneft, Rosneft’s subsidiary, license-holder for fields of the Vankor cluster. Vankorneft was established in 2004 to develop Vankor oil, gas and condensate field located in the north of the Krasnoyarsk region. Vankor is truly a jewel in Rosneft’s crown; the biggest field discovered and commissioned in Russia in the past 25 years with reserves of 500 mt of oil and condensate and 182 bcm of gas. Supported by generous fiscal benefits, Rosneft launched commercial production there in 2009. It was expected that the field would peak at 25 mt/yr, but Vankor reached a plateau of 22 mt (10 percent of the total Rosneft’s output in 2015) and stayed there; moreover, it is expected that production would start decreasing.  In principle, the launch of Suzunsk, Tagulsk and Lodochnoye fields of the Vankor cluster should offset the decline at Vankor itself. At that time, analysts valued this stake at about $1 billion. CNPC then said that “we are interested in expanding cooperation with Rosneft, in transition from purely upstream to upstream + downstream, i.e. in comprehensive cooperation.”61 The Chinese, apparently, were ready to buy a larger stake of Vankorneft, actually, as large as Rosneft was prepared to sell. The official statement made by Vladimir Putin with respect to this agreement illustrated the current attitude of Russian leadership to relations with China: “Vankor is now one of our biggest production enterprises, highly promising. In general, we have a very weighted approach to providing access to our foreign partners, but, certainly, there are no limitations for our Chinese friends.”62

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64   Handbook of energy politics However, an informed source admitted unofficially that “though China is our partner now, nobody is prepared to give it too big a stake.”63 In any case, it took a very long time for the Russian and Chinese friends to reach an agreement on prices for Vankor. As Vladimir Milov notes, in case of Vankor “as in other cases, there appears to be a huge gap between the Russians, who want to sell the asset at the highest possible price, and the Chinese, who do not want to overpay. The oil price collapse has widened this asset price gap.”64 Also, presumably, the Chinese were not satisfied with the fact that they as “friends” are being offered relatively limited minority stakes, similar to other partners, who are merely “acquaintances.” So, probably not surprisingly, the deal on Vankorneft soon collapsed. Also in September 2015, Rosneft and Sinopec signed Main Terms of Agreement on Cooperation within the Framework of Joint Development of Russkoye and Yurubcheno-Tokhomskoye Fields during Vladimir Putin’s visit to Beijing.65 Sinopec can receive up to 49 percent of VSNK and Tyumenneftegaz, license-holders for these fields. In September 2016, during the Eastern Economic Forum, Rosneft and Sinopec signed a legally binding agreement on the preparation of a feasibility study for a project on construction and operation of a gas processing and petrochemical complex in East Siberia with initial throughput of 5 bcm of gas. The complex will use as resources oil and gas fields of Yurubchen cluster in East Siberia.66 In addition to its traditional oil partners, CNPC and Sinopec, Rosneft that wants to develop its gas business found a new ally in the Chinese gas sector. On November 7, 2016, Rosneft and Beijing Gas Group Company Limited concluded a sales agreement, shareholders and operating agreement concerning the sale of 20 percent shares of Verkhnechonskneftegaz for some $1.1 bln, as well as an agreement on cooperation in gas business. These documents were signed as a follow-up of agreements reached during the visit of Vladimir Putin to China in June 2016. Beijing Gas will get a stake in one of the biggest producing fields in East Siberia with developed infrastructure and access to ESPO, while Rosneft will enter China’s domestic gas market.67 Rosneft expects to take advantage of the decision of PRC’s authorities to transfer power generation of Beijing from coal to gas and to use gas as motor fuel in China. Since now Western contractors are unwilling to work with Rosneft for fear of new constraints (particularly after the US introduced sanctions against Gazprom’s Yuzhno-Kirinskoye field), Rosneft opened the Russian market for the Chinese oil service companies as well. China Oilfield Services Limited was invited to drill two prospecting wells for Rosneft and Statoil in the Sea of Okhotsk on Magadan-1 and Lisyanskiy plots in 2016.68

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Oil on the waters of RIC energy relations  ­65 Thus, joint implementation of upstream projects by Rosneft and Chinese NOCs is proceeding less actively than was envisaged initially. Interestingly, Sinopec has achieved much more impressive results in the Russian oil sector than CNPC. It might be because Sinopec is smaller and less influential than CNPC, and, therefore, less demanding and tough. CNPC, which was considered for a while the most probable contender for participation in Rosneft’s privatization, insisted on an active role in Rosneft’s management. CEO of CNPC Wan Ilin admitted that even with the stabilizing oil prices CNPC is not in a hurry for a partnership with Rosneft in Russian shelf projects: The proposed projects are at the earliest stage of implementation; as a result, they require considerable investments, and with the current oil prices we consider them risky. The second consideration is strict terms of partnership that limit opportunities for the Chinese side to participate in management of these projects.69

In principle, the desire of a foreign partner to jointly manage the projects is absolutely understandable and legitimate, but Rosneft seems to be not eager to hand the Chinese the reins. Thus, even with the help of Rosneft the Chinese NOCs did not get much of a foothold in Russian upstream. They are much more successful with their expansion in other petroleum states, such as Kazakhstan, Sudan, Venezuela and Angola. Since 2008, the NOCs have purchased assets in the Middle East, North America, Latin America, Africa and Asia and invested some $73 billion in overseas oil and gas assets between 2011 and 2013. Now Chinese NOCs are operating in upstream of 42 countries. China’s oil production from its overseas equity shares and acquisitions grew significantly, from 140 thousand bbl/d in 2000 to 2.1 million bbl/d in 2013.70 Therefore, Chinese NOCs wish to get access to the Russian upstream, but they have other no less attractive opportunities in many oil and gas producing countries.

CHINESE DOWNSTREAM Oil relations between Russia and China were to be based on the principle “our upstream for your downstream.” Consequently, in late 2007, Rosneft (49 percent) and CNPC (51 percent) established a JV PetroChina-Rosneft Orient Petrochemical (Tianjin) Company to build a 16 mt/yr refinery and a network of 300–500 fuel stations in China. Then, it was expected that it would cost $3 bln and would become operational in 2011.71

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66   Handbook of energy politics However, Rosneft is facing serious problems with securing a niche in the Chinese downstream through the Tianjin refinery. There are many unresolved issues, such as project financing, refinery capacity and sources of crude. After endless delays, in 2010 Igor Sechin and Wan Tsishan laid the first stone of the future refinery in Tianjin. On March 22, 2013, an agreement between the governments of RF and PRC on Cooperation in Construction and Operation of the Tianjin Refinery and Petrochemical Complex and Upstream Projects was signed that provided three exclusive rights to the JV: for independent import of crude oil; for free export of petroleum products and petrochemicals; for domestic sales of petroleum products and petrochemicals. These rights might improve the economics of the project. During the state visit to China in May 2014, Rosneft and PetroChina signed the Schedule for Commissioning the Tianjin Refinery and Crude Deliveries for Refining that envisaged launching the refinery in late 2019 (that is, eight years after the initial deadline).72 In time of sanctions, Rosneft found a new friend, China National Chemical Corporation (ChemChina), in the petrochemical sector. In September 2015, in the presence of Vladimir Putin and Xi Jinping, it signed two documents with ChemChina. Under them, Rosneft plans to buy a 30 percent stake in CNCC, while ChemChina will acquire the controlling interest in the Eastern Petrochemical Company of Rosneft (thus Rosneft finds a strategic partner for its costly project that is frozen due to shortage of funds). Apparently, Rosneft will face many problems in China. First, fuel prices in China are regulated, and rules are frequently changing. Second, only Sinopec and PetroChina have licenses for import and export of petroleum products. Third, the Chinese companies themselves plan to drastically increase their refining capacities. Fourth, Rosneft will have to compete with the global giants at the Chinese market. China eagerly invites ExxonMobil or Shell that can contribute state-of-the-art technologies and advanced skills to Chinese downstream. And Rosneft can provide only crude oil . . .

AGAIN MONEY . . . China wanted Rosneft to prolong the first oil deliveries contract up to 2011–30. Information about the Chinese loans of $20–25 billion in exchange for 20-year crude shipments to China surfaced in October 2008, when Prime-Minister Wen Jiabao visited Moscow. During the financial

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Oil on the waters of RIC energy relations  ­67 crisis of 2008–09 it was impossible to raise such funds at the global markets. The Chinese credit at that time would have simplified life for Rosneft. After it purchased the remaining assets of YUKOS, its net debt at July 1, 2008, amounted to $21.4 billion, including $13.4 billion of short-term credits.73 Rosneft’s position at negotiations was much weaker than that of its Chinese counterpart: it was far more important for the Russian company to obtain this credit than for CNPC to ensure commitments for deliveries of 15 mt/yr of oil. The “deal of the century” was promoted by President Dmitry Medvedev who invented the idea, Prime Minister Vladimir Putin who reached the agreement on general principles, and Vice-Premier Igor Sechin who monitored the contract on behalf of Russia.74 It was expected that Rosneft and CNPC would resolve all problems by late 2008. However, by mid-November negotiations on oil deliveries and credits stopped, and Moscow blamed Beijing for their disruption: it claimed that the Chinese insisted on absurd credit terms and demanded five different guarantees.75 Besides, the commissioning of ESPO was delayed by one year; therefore, the issue of the spur became redundant. Moreover, Rosneft could not agree with CNPC on the oil price. It was only in February 2009, after tough bargaining with the Chinese that Igor Sechin personally led, that Rosneft received a $15 billion credit from China; at the same time, the Chinese banks granted $10 billion to Transneft, mainly for the construction of ESPO, including a spur to China. In return, two state companies pledged to deliver 15 mt/yr to China for 20 years. On July 18, 2009, the RF president signed the Federal Law On Ratification of the Agreement between the Governments of Russia and China on Cooperation in the Oil Sphere. Then, this credit was a record for Russia in terms of its amount and time frame. However, the specifics of the agreement were not disclosed. The Ministry of Energy only stated that the credit terms were attractive for Russia: “interest rate is more than twice lower than the effective one at the international markets, which is particularly important during the global crisis.”76 In contrast to the first loan-for-oil deal, the price was to change monthly on the basis of Argus and Platts quotes in Kozmino.77 “The Chinese credit is iron-clad, it is verified by both parties and has an international jurisdiction,” stated Igor Sechin.78 However, the problems with the “iron-clad” credit began as soon as oil shipments started in January 2011. The parties assessed differently the T coefficient that determined logistic expenditures of Transneft. CNPC began to underpay $13/bar, since now it received oil via the ESPO

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68   Handbook of energy politics spur instead of by railway, and the new route was half the length.79 This position of CNPC could have resulted in losses of $30 billion for Russian companies over the contract duration. Negotiations at the corporate level failed; by Summer 2011, CNPC’s debt reached $200 mln. No compromise was achieved at the governmental level. In June, at the regular session of the Russian–Chinese energy dialogue80 that Igor Sechin headed from the Russian side, CNPC agreed to repay the lion’s share of debt and reduce the T coefficient to $3/bar. This gave Igor Sechin an opportunity to say that “all contradictions are eliminated and mutual understanding is reached.”81 But Transneft warned that if CNPC did not fully repay the debt, the Russian company would make a settlement with China Development Bank ahead of schedule and apply to international courts. It was only in early 2012 that Rosneft, Transneft and CNPC agreed upon new delivery terms. Rosneft and Transneft provided a $1.5/bar “country” discount to CNPC, while CNPC pledged to fully repay its $134 mln debt for oil deliveries from the early 2011. Rosneft considered changes in the contract to be “Russia’s victory” since it managed to reduce the discount from $13/bar to $1.5/bar.82 However, the dispute was actually resolved in favor of CNPC: the spur was built on the Chinese money under guarantees of crude deliveries to a monopoly buyer; that is, China. Thus, during the 2008–09 crisis China was the only chance for Rosneft to raise funds necessary to pay for its acquisition of YUKOS. Whereas for China, Russian credit was one of many: in 2009 alone the country provided loans-for-oil to Venezuela ($8 bln), Brazil ($10 bln), Kazakhstan ($10 bln) . . . And by the end of 2013, Chinese NOCs had secured bilateral loans-for-oil deals with Kazakhstan, Venezuela, Brazil, Ecuador, Bolivia, Angola and Ghana, and loan-for-gas agreement with Turkmenistan, amounting to almost $150 billion.

AND EVEN MORE MONEY Russia–China oil cooperation developed particularly intensively in 2013. Chinese money became vital for Rosneft after its acquisition of yet another domestic player: in March 2013, Rosneft bought TNK-BP for $61  billion, including $44.38 billion in cash. The state company had to borrow practically the whole amount. Therefore, in March Vladimir Putin and the new PRC’s Chairman Xi Jinping (who made his first official visit abroad to Russia) signed a joint declaration on cooperation and further development of

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Oil on the waters of RIC energy relations  ­69 ­ artnership. The ­governments of Russia and China closed an Agreement p on Expanding Cooperation in Supplies of Oil that was ratified by the Federal Law # 352-FZ. The same month Rosneft reached a credit agreement with the State Bank of China and with the China Development Bank on a 25-year $2 billion loan. Two super-giant oil export contracts were also closed in 2013. The first one, between Rosneft and CNPC on delivering 360 mt of crude for 25 years: the new “deal of the century” was worth some $270 billion, and an advance payment of some $65 billion was envisaged. Price of barrel was $101.3, that is, at the level of the world prices at that time. Second was the $85 bln contract with Sinopec, under which Rosneft would supply 100 mt of crude for ten years. The 2013 Rosneft’s contract with CNPC was initially considered a victory of Russia’s oil policy. However, it became clear that China continues to steadily expand its control over hydrocarbon resources in a neighbor state under attractive terms. And the financial exposure of Rosneft (and, indirectly, the Russian state as its main shareholder) to a single creditor assumed alarming proportions. As Yuri Kogtev from RusEnergy, said “The dependence of the biggest Russian oil company on China may evolve from financial into political. If oil prices drop, financial dependence of the borrower will grow and it will have to borrow even more.”83 Also, significantly, Vagit Alekperov, president of LUKOIL, thus commented on Chinese credits: Unfortunately, we’ve never had any luck in negotiations with the Chinese banks. They are ready to provide financing either in the form of loans-for-oil or equipment-tied credits. These are the most expensive credits in the world. We do not use such credits.84

Besides, this new credit complicated further the already strained relations between Rosneft and Transneft. Transneft stated that the rapid growth of Rosneft’s exports to China would require considerable investments into the expansion of pipelines in Russia’s East. These investments will be covered by higher transportation tariffs for all the users of trunk pipelines; that is, benefits of one exporter will be ensured by rising costs for the whole oil sector. The situation was aggravated when Rosneft refused to finance the expansion of ESPO and the spur to China for additional deliveries of oil. It wanted Transneft to undertake all expenditures. “Regrettably, not all parameters of this agreement [on deliveries of oil to China] were coordinated with the company [Transneft]. We are put in a very difficult situation, since enormous expenditures are required to

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70   Handbook of energy politics expand the existing trunk pipelines in the Eastern direction,” said Nikolai Tokarev in August 2013.85 Still, despite all these conflicts, in October 2013, Rosneft and Transneft signed agreements aimed at increasing volumes of crude deliveries to PRC. Moreover, in November Rosneft, KazMunaiGaz and KazTransOil signed a Preliminary Agreement on Oil Transportation through the Territory of Kazakhstan. The deal of the century is actively promoted by both sides. In January 2017, Rosneft and CNPC signed an additional agreement on increasing oil transit through Kazakhstan and on extending the time frame of the contract signed on June 21, 2013 to December 31, 2023. Deliveries from January 1, 2017 to December 31, 2023 will amount to 70 mt, and the total volume of shipments under this contract, taking into account 21 mt that were already supplied to China, will reach 91 mt over a ten-year period.86 The “deal of the century” revealed another significant challenge for Rosneft. The company might face a shortage of oil that could impede fulfillment of its additional export commitments to China. There are solid grounds for this concern since already in 2013 Rosneft encountered production decline at mature fields that it inherited from YUKOS and TNK-BP. Igor Sechin assured that the company would commission several major fields87 permitting it to meet all its Eastern commitments. Actually, Rosneft will have enough crude to deliver to China if it launches all these fields on time. In August 2013, Igor Sechin promised that Rosneft would commission them in 2016–19.88 But during sanctions which denied it access to international long-term financing, it is already missing deadlines for lack of funds. Moreover, the government refused to grant it money from the National Wealth Fund for refinancing of credit and launching of fields. Still, in November 2015, Rosneft reported that during Q3 2015 it received a $15 bln advance payment for long-term contracted deliveries of oil, presumably from CNPC. It immediately improved the balance sheet of the company. Now, Rosneft can invest in its Eastern fields in order to cover advance payments with oil deliveries. However, advance payments are quite an expensive instrument, according to experts.89 Thus, the new “deal of the century” forced Rosneft to search for ways to increase crude production in order to ensure additional oil deliveries to China. At that time analysts were wondering: if organic growth was not enough, would the company feel compelled to acquire another Russian player in order to meet its Chinese commitments? And would it then require a new Chinese credit to pay for the acquisition? Ultimately, the situation turned out to be more complicated. Indeed, in 2016 Rosneft felt compelled to acquire for $5.3 bln Bashneft, a 20-mt

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Oil on the waters of RIC energy relations  ­71 producer that was one of the leaders of oil production growth in Russia. Predictably, Rosneft had to search for external funds to pay for the acquisition. But this time, unpredictably, it was India that came to the rescue.

THE ETERNAL TRIANGLE With hindsight one can say that the deal with India was an obvious card to play in relations with China. First, India is a petroleum-hungry country: in 2015, it was the fourth-largest consumer of oil and petroleum products after the United States, China and Japan, and it was also the fourth-largest net importer of oil and petroleum products. The gap between India’s oil demand and supply is widening. The government has encouraged national oil companies to acquire overseas upstream assets as a way to shield the domestic energy sector from global price volatility and to reduce India’s growing dependence on imported crude. Indian NOCs have purchased equity stakes in South America, Africa, Southeast Asia and the Caspian Sea region. However, the lion’s share of petroleum imports continues to originate in the Middle East.90 Second, Russia and India have been long-term economic and political partners and allies. Diplomatic relations between the Soviet Union and India were established on April 13, 1947. The current Russian–Indian relations are based on the Agreement on Friendship and Cooperation as of January 28, 1993. Significantly, in October 2000, soon after Vladimir Putin became President of Russia, he made the state visit to India during which a Declaration on Strategic Partnership between Russia and India was signed. Since then, annual top-level meetings have been held on key areas of cooperation. Third, trade relations between the countries have a considerable upside potential. In 2014, trade turnover between Russia and India amounted to $9.5 bln, with Russian exports at $6.3 bln, and Russian imports at $3.2  bln; that is, it was practically ten times smaller than turnover with PRC. However, the structure of Russian exports to India, in contrast to China, is much less resource-based, since machines, equipment and transportation vehicles account for 36.7 percent, precious stones and metals for 17.6 percent and chemical products for 11.7 percent.91 Therefore, there is no worry that Russia can become a resource appendage to India. So, masterly playing the Indian card, Rosneft decided to renew its relations with the Indian partner 15 years after it sold a stake in Sakhalin-1 to ONGC. On September 4, 2015, within the framework of the First Eastern Economic Forum, Rosneft and ONGC Videsh signed an agreement on the sale of 15 percent in Vankorneft, and both companies began to gather

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72   Handbook of energy politics all necessary permits. The process proceeded at a breakneck speed: on May 31, 2016, they closed the deal on the sale of a 15 percent stake in Vankorneft for $1.27 bln. But it was just the beginning. On September 14, 2016, Rosneft and ONGC signed a new agreement, on the sale of yet another 11 percent of Vankorneft. On October 28, they closed the deal with a base value of $930 mln, and now ONGC will be the owner of 26 percent of Rosneft’s subsidiary.92 Simultaneously, another deal was being implemented (and was closed on October 5), on the sale of 23.9 percent of Vankorneft to a consortium of Indian investors (Oil India, Indian Oil and Bharat PetroResources) for $2.021 bln.93 As a result, the stake of Indian companies in Vankorneft will grow to 49.9 percent. Rosneft will retain 51.1 percent, the majority in the Board of Directors, as well as control over operating activities of its subsidiary and over the production infrastructure of the Vankor cluster. The situation when foreign companies will own almost 50 percent of one of the most attractive upstream projects in Russia became possible because of international sanctions against Rosneft, its gigantic debts and falling oil prices which hit Rosneft rather badly. An interesting paradox emerged. Vankor is one of the key sources of crude for supplies to China by ESPO. Actually, the Indian companies own practically half of Vankorneft, and, subsequently, are producing oil for China. This situation is particularly piquant given the far from ideal relations between China and India. Moreover, adding insult to injury, the Indian companies were allowed to buy a much bigger share in Vankorneft than was offered to CNPC. In principle, this event sent a strong signal to PRC that Russia has other attractive partners. And ONGC won a serious moral victory over its Chinese rivals: in the past, it often competed with the Chinese companies for valuable petroleum assets worldwide, and was frequently defeated by the Chinese, for example, in Angola. Vankor became the biggest, but not the only breakthrough, of India into the Russian upstream. On March 16, 2016 Rosneft, Oil India, Indian Oil and Bharat PetroResources signed an agreement on the sale of 29.9 percent of Taas-Yuryakh Neftegazdobycha to Indian companies. Earlier, Rosneft tried in vain to sell a stake in this subsidiary to its Chinese friend, CNPC. The Indians will join the JV that Rosneft created together with BP on the basis of Taas-Yuryakh. The deal was closed on October 5, 2016, and the base price was $1.2 bln.94 According to Vitaly Yermakov from the Higher School of Economics, the federal budget seems to be one driver of the current sale of Russian upstream assets to India as Rosneft needs to raise the additional cash to pay for the purchase of a 50.08 percent stake in Bashneft. The Russian state sold this

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Oil on the waters of RIC energy relations  ­73 stake to Rosneft to raise funds to reduce the budget deficit and to maintain nominal control over oil assets that are changing hands. The Indian companies’ payment helps Russia close a near term financial gap and effectively allows Rosneft to continue its expansion in the Russian oil sector.95 However, the economic logic behind the Vankor deal seems to be somewhat obscure since it actually means selling half of Rosneft’s “jewel in the crown” to help pay for the acquisition of a player that operates mainly mature fields with heavy and sour oil in Bashkiria and that showed impressive growth largely thanks to the excellent management team – that was fired immediately after the acquisition. Thus, Indian companies managed in a couple of years to acquire stakes in oil producing subsidiaries of Rosneft which ensured them control over much larger crude production volumes than Chinese companies achieved in a decade (see Table 2.2). While Rosneft is not particularly successful in trying to secure a niche in the Chinese downstream, it is much more fortunate in India. In this sphere, its existing business relations with the Indian Essar definitely helped. During BRICS summit held in Ufa in July 2015, Rosneft and Essar Table 2.2 Chinese and Indian companies stakes in oil producing subsidiaries/projects of Rosneft Chinese companies Rosneft subsidiary/ project CNPC Sinopec Sinopec

Share of Chinese/ Total oil Indian company production in 2016

Vostok Energy Sakhalin-3, Veninsk block Udmurtneft

49% 25.1%

– –

47.7%

6.5 mt

Sakhalin-1 Vankorneft

20% 49.4%

9.0 mt 21 mt

Taas-Yuryakh Neftegasdobycha

29.9%

1.1 mt

Indian companies ONGC ONGC, Oil of  India, Indian Oil, Bharat PetroResources ONGC, Oil  India, Indian Oil, Bharat PetroResources

Source:  Author’s estimates.

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74   Handbook of energy politics concluded a long-term contract for oil deliveries to be refined at Vadinar refinery. This document was signed as a follow-up of agreements reached during the visit of Vladimir Putin to India in 2014 and envisaged deliveries of some 100 mt over a ten-year period.96 On October 15, 2016, Rosneft bought 49 percent of Essar Oil Limited (EOL). Vadinar refinery with throughput capacity of 20 mln tons/yr and yield of light products of 95.5 percent is part of EOL. It is a complex and modern refinery with Nelson Index of 11.8, capable of refining heavy crude. EOL also owns network of 2.7 thousand fuel stations in India. Rosneft and a consortium of international investors, that would include Trafigura, will buy EOL business for $ 12.9 bln.97 On the one hand, the EOL deal will permit Rosneft to enter the Indian fuel market, one of the fastest growing in Asia. Besides, it will get an opportunity to make deliveries to other Asia-Pacific countries, such as Indonesia, Vietnam, Philippines and Australia. On the other hand, it would have been useful if these funds had been invested in the domestic refining segment, as Rosneft refineries are still in quite a bad shape despite the ongoing upgrading process. The highest yield of light products (73 percent) among Rosneft refining subsidiaries is at the Angarsk Petrochemical Complex, while other subsidiaries demonstrate the level just slightly above 60 percent.98 Similar to the 2001 deal, the current oil cooperation with India is an element of a broader political and economic partnership between the two countries. Thus, in October 2016, during the visit of Vladimir Putin to India, agreements were signed on nuclear power generation, on ­construction of frigates, on deliveries of anti-aircraft systems to India, on establishment of a JV to manufacture Ka-226T helicopters, and so on, and so forth.

A MARRIAGE OF (IN)CONVENIENCE? What does the petroleum rapprochement with China and India mean for the global oil industry and for Russia? Globally, Russia’s turn to the East, primarily to China, means redirection of the established oil flows. It means intensified competition for the Chinese market with subsequent cutting of prices by suppliers. It means redistribution of the EU market, since Russian oil will not be enough both for Europe and China (and now India). So, ultimately the turn to the East is achieved at the expense of Europe. The Western sanctions against Russia result in an even greater shift of Russia’s oil policy towards China and India; therefore, the main beneficiary of the sanctions

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Oil on the waters of RIC energy relations  ­75 seem to be the Chinese and Indians since they get what they want under attractive terms. For Russia, the turn to the East is a chance to strengthen its energy security, diversify oil export flows and forge new relations with PRC. Therefore, if Russia’s rapprochement with China meant a way of developing mutually beneficial cooperation with its neighbor (without sacrificing its long-standing relations with Europe), it would be an excellent business and economic opportunity. However, if it is an attempt to make a geopolitical reorientation towards Asia, it is a risky choice, since Russia is essentially a European country. Also, if it is a plan to “play the Chinese card” in negotiations with Europe, particularly during the sanctions, in order to put pressure on its EU customers, it could further jeopardize Russia’s relationship with its traditional strategic partner. As Mikhail Krutikhin points out, the redirection of petroleum exports to Asia from the traditional Western market is an element of the geopolitical strategy of Russia’s top leadership. Besides, the Chinese are dictating terms and conditions by using a winning tactic that he calls “a jump from the ambush,” that is, they are waiting for a situation when the unwise moves made by policymakers lead the Russian state companies into a cul-de-sac, from which they cannot exit without external financial aid.99 Therefore, the turn to the East is fraught with considerable challenges for Russia, because the long-term strategic economic and social goals are intertwined with short-term tactical political motives. The serious threat for Russia is that China is economically and demographically stronger and faster developing than Russia. Significantly, Russia’s strategy up to 2020 developed in 2012 predicts that the external pressure on Russia would grow in the next eight years. The main risks for Russia connected with the emergence of the new “centers of power” are determined by the growth of China’s economic potential and international status. “China is conquering dominant positions at commodity markets, including ‘traditional Russian’ ones, as well as new technologically advanced ones, which is fraught with further deepening of resource orientation of Russian export.”100 China is overtaking Russia by all indicators, and by 2020 Russia will lag even more behind PRC. Politically, there are also serious challenges for Russia. When RIC concept was proposed in the late 1990s, “it was thought that Russia would play the leading role in the ‘triangle’. Now it is clear that China will play this role, and this changes the entire situation,” remarked Alexei Maslov from the Higher School of Economics. “One needs to understand that strengthening of the triangle will take place according to China’s concept of a new ‘Great Silk Road’. In other words, China will unite countries based on mutual self-interest, primarily, economic.”101

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76   Handbook of energy politics As Vladimir Milov points out, examination of the Sino-Russian partnership shows that the new strategic partner is not ready “to engage in Russia’s globally oriented energy games,” instead it wants to “pursue its own pragmatic energy interests.”102 Moreover, for a long time Russia’s broadly advertised turn to the East actually meant a turn only to China. Therefore, experts feared that Russia would become increasingly dependent on the economic situation in PRC, particularly on the rise or decline of its energy demand. China is attractive to Russia as a vast market for hydrocarbons; however, if Russia is tied too much to PRC, it will be more difficult for it to expand relations with Japan and South Korea. Furthermore, transportation infrastructure is not sufficiently developed to ensure quick relocation of export deliveries between Japan, South Korea and China, which would have permitted avoiding “market of one buyer” and price pressure on Russian exporters. As Philip Andrews-Speed from Chatham House said: “in the longterm perspective Russia will have to learn the lesson: the buyer has more power over prices than the seller. China has a much wider choice than Russia.”103 Moreover, the energy interdependence between the two countries became even more asymmetrical during sanctions, since China turned out to be virtually the only source of finance for Russia. In addition, the inequality of Russo-Sino energy relations is underscored by the fact that Russia considers China to be its strategic partner. However, according to Valeriy Zubov, State Duma deputy, and Alexei Makarkin from the Center of Political Technologies, who co-authored an article “Why do we need China, and why does China need us?”, China regards Russia as a huge resource-rich country which raw materials it can use by acting tough.104 Indeed, the growing oil exports to China consolidate Russia’s position as “resource colony” of PRC. No visible attempts are made to diversify Russian exports and develop cooperation in other spheres. Real cooperation of Rosneft with the Chinese NOCs is progressing mainly in terms of raising of Chinese loans-for-oil and increasing crude exports to PRC. The invitation of Chinese investors to the oil sector of Russia is fraught with serious risks, points out Alexei Maslov. “It is, evidently, a forced move on the Russian side, since Russia needs money. However, the Chinese always play a long-term game. Chinese investments into the energy sector of Kazakhstan did not seem dangerous initially; however now the Chinese control 30–40 percent of Kazakh oil fields.”105 In addition, petroleum relations with China are monopolized by Rosneft to the exclusion of other Russian oil companies. Though the state oil company acts as an instrument of the governmental energy policy, it

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Oil on the waters of RIC energy relations  ­77 has its own corporate interests, and it promotes the Eastern vector with due account for them. Sometimes they conflict with the long-term interests of the whole sector and create new uncertainties for Russia. However, these legitimate concerns of Russian experts about the relations with China were recently alleviated by the new oil deals with India. Indubitably, close petroleum contacts with India are beneficial to Russia and Rosneft. First, it is better to have several partners, rather than being in monopolistic dependence of a super-strong player. Second, India is a fast-growing country with an insatiable hunger for energy. Third, relations between Russia and India have always been much smoother and more straightforward than with China. Fourth, India is neither a political nor an economic superpower. It is objectively interested in petroleum cooperation with Russia, which simplifies the negotiation process. Nevertheless, while partnerships with majors, such as BP, provide Rosneft not only with money, but also with know-how and technologies, improve corporate governance, promote environmental awareness and so on, the Indian companies will hardly be able to make a valuable contribution to efficient and sustainable development of the Arctic or deepwater fields of Rosneft. ONGC does not have real experience of operatorship of large-scale integrated projects which is the strength of the global majors; nor does it possess state-of-the-art technologies for production of hard-torecover reserves or unconventional resources. So, will the emergence of the third player in the RIC triangle pour oil on troubled waters of Russia–China petroleum relations, or will it make Russia’s partnership with its European and Asian energy counterparts even more stormy?

NOTES   1. EIA (2017) “Russia. Country analysis brief.” Last updated October 31, 2017. Accessed December 12, 2017.   2. J. Henderson (2011) “The strategic implications of Russia’s Eastern oil resources,” OIES, WPM 41, January, p. 4.   3. Draft Energy Strategy up to 2035. Moscow, 2014, available at http://www.­energystrategy. ru/ab_ins/source/ES-2035_09_2015.pdf. Accessed December 12, 2017.   4. BP Global (2015) “Country insights: China,” available at http://www.bp.com/en/ global/corporate/energy-economics/energy-outlook/country-and-regional-insights/ china-insights.html. Accessed December 12, 2017.   5. Energy Strategy of Russia up to 2030, Moscow, 2009, available at https://minenergo. gov.ru/node/1026. Accessed December 12, 2017.   6. http://www.levada.ru/2016/06/02/rossiyane-reshili-kto-im-vragi/. Accessed December 6, 2017.   7. Main Provisions of the Energy Strategy of Russia up to 2035, Moscow, 2017, available at minenergo.gov.ru›system/download/1913/2406. Accessed December 12, 2017.

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78   Handbook of energy politics   8. Russian Petroleum Investor, December 1998/January 1999, p. 52.   9. Oil and Capital, No 3, 2001, p. 48.   10. Meanwhile, on January 13, 2009, ONGC Videsh Ltd bought the Imperial Energy group of companies that was engaged in exploration and production in the Tomsk region of Russia.   11. Oil and Gas Vertical, No 12, 2002, p. 40–42.   12. Taking into account Bashneft consolidation.   13. See http://ria.ru/tags/person_Igor_Sechin/   14. N. Lomagin (2015) Foreign Policy Preferences of Russia’s Energy Sector: A Shift to Asia? In: Russia, Eurasia and the New Geopolitics of Energy. Confrontation and Consolidation, London: Palgrave Macmillan.   15. Vedomosti, April 11, 2008.   16. Vedomosti, January 22, 2008.   17. ESPO has design capacity of 80 mt/yr. Its first stage envisaged construction of 2,694 km of a 30 mt/yr pipeline from Taishet (Irkutsk region) to the border with China (Skovorodino, Amur region). This stage began in April 2006 and was completed in December 2009. Construction of the second stage began in 2010 from Skovorodino to the Kozmino port (length of 2,064 km). It was commissioned in December 2012 with capacity of 30 mt/yr. In 2014, works were completed to expand the ­Taishet-Skovorodino section to 58 mt/yr.   18. Vedomosti, December 29, 2009.   19. Oil and Gas Vertical, No 14, 2005, pp. 62–3.   20. Vedomosti, August 31, 2005.   21. http://www.transneft.ru/about/projects/current/1204/. Accessed December 6, 2017.   22. Oil and Capital, No 11, 2008, p. 21.   23. Vedomosti, April 11, 2008.   24. Oil and Capital, No 3, 2009, p.42.   25. Oil and Gas Vertical, No 15–16, 2009, p. 21   26. http://www.transneft.ru/about/projects/current/mohe/. Accessed December 12, 2017.   27. Kommersant, June 29, 2015.   28. Kommersant, June 15, 2015   29. Kommersant, January 28, 2015.   30. Kommersant, June 29, 2015.   31. http://www.worldoil.com/news/2015/7/01/russia-seen-extending-oil-sales-lead-withsecond-china-pipeline. Accessed December 12, 2017.   32. Gravity of 31–2° API and sulfur content of 1.2–1.4 percent.   33. http://www.ved.gov.ru/exportcountries/cn/cn_ru_relations/cn_ru_trade/. Accessed December 12, 2017.   34. Rosneft 2016 Annual Report, p. 102.   35. Rosneft 2016 Annual Report, p. 104.   36. Ibid.   37. http://www.rosneft.ru/Downstream/crude_oil_sales/. Accessed December 12, 2017.   38. Rosneft (2014) “Management’s discussion and analysis of financial condition and results of operations for the quarters ended December 31, 2014 and September 30, 2014, and for twelve months ended December 31, 2014, 2013 and 2012,” (MDA), p. 28.   39. Rosneft 2015 Annual Report, pp. 6–7.   40. gazeta.ru, June 23, 2015.   41. Forbes (2015), October 14. Available at  http://www.forbes.ru/news/302883-novaknazval-zhestochaishei-konkurentsiyu-na-mirovom-rynke-nefti. Accessed December 12, 2017.   42. gazeta.ru, June 23, 2015.   43. Vedomosti, September 29, 2015.   44. J. Barron (2017) “More Chinese crude oil imports coming from non-OPEC countries,” EIA, April 14, available at https://www.eia.gov/todayinenergy/detail.php?id=30792. Accessed December 12, 2017.

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Oil on the waters of RIC energy relations  ­79   45. https://www.rosneft.ru/press/releases/item/185281/. Accessed December 12, 2017.   46. http://torgprominfo.com/eksport-rossijskoj-nefti-v-kitaj-sokratilsya-na-1778/. Access­ed December 12, 2017.   47. http://www.vestifinance.ru/articles/60332. Accessed December 12, 2017.   48. Vedomosti, June 24, 2015. Available at https://www.vedomosti.ru/newspaper/articles/​ 2015/06/24/597723-rossiiskaya-neft-napolnyaet-kitai. Accessed December 12, 2017.   49. The Chinese companies tried to participate in privatization of Slavneft, in the Yuganskneftegaz auction, and to buy the Orenburg company Stimul.   50. https://neftegaz.ru/news/view/69822-Rosneft-otpravila-Sinopec-v-razvedku-na-Saha​ lin-3. Accessed December 12, 2017.   51. A 6 mt producer located in the Volga-Urals region.   52. https://lenta.ru/news/2006/11/17/rosneft/. Accessed December 12, 2017.   53. Vedomosti, June 21, 2006.   54. Vedomosti, August 1, 2007.   55. Oil and Gas Vertical, No 13, 2006.   56. Recoverable reserves of 134 mt of oil and condensate and 155 bcm of gas.   57. http://ria.ru/economy/20141224/1039885899.html#ixzz3o68Okemz. Accessed December 12, 2017.   58. Vedomosti, November 19, 2014.   59. http://www.rbc.ru/politics/23/01/2015/54c262399a79478439e5745d. Accessed December 12, 2017.   60. http://www.rbc.ru/economics/27/02/2015/54f002189a7947255e32ef80. Accessed Dec­ em­ber 12, 2017.   61. Vedomosti, May 5, 2015.   62. http://www.novayagazeta.ru/economy/65129.html. Accessed December 12, 2017.   63. Kommersant, September 2, 2014.   64. IFRI, Milov, pp. 6–7.   65. http://www.rosneft.ru/news/pressrelease/03092015.html. Accessed December 12, 2017.   66. https://www.rosneft.ru/press/releases/item/183487/. Accessed December 12, 2017.   67. Verkhnechonsk oil, gas and condensate field has C1+C2 reserves of 173 mt of oil and gas condensate and 115 bcm of gas; that is, it is a federal-level field with 8.5 mt of oil production in 2015. Available at https://www.rosneft.ru/press/releases/item/184437/. Accessed December 12, 2017.   68. Vedomosti, September 2, 2015.   69. Kommersant, May 31, 2016.   70. EIA (2015) “China. Country analysis briefs.” Last updated May 14, 2015.   71. Vedomosti, September 22, 2010.   72. http://www.rosneft.ru/Downstream/refining/Construction/. Accessed December 12, 2017.   73. Vedomosti, November 7, 2008.   74. Oil and Gas Vertical, No 15–16, 2009, p. 21.   75. Oil and Capital, No 11, 2008, p. 20.   76. http://minenergo.gov.ru/press/min_news/421.html?print=Y. Accessed December 12, 2017.   77. Vedomosti, February 18, 2009.   78. Kommersant, February 28, 2012, available at https://www.kommersant.ru/doc/1882127. Accessed December 12, 2017.   79. Oil and Gas Vertical, No 22, 2011, p. 49.   80. Russian–Chinese energy dialogue was launched in 2008 during the visit of President Dmitry Medvedev to China. Its co-chairmen are vice-premiers of the Russian and Chinese governments in charge of fuel and energy sectors.   81. Kommersant, February 28, 2012, available at https://www.kommersant.ru/doc/1882127. Accessed December 12, 2017.   82. Kommersant, February 28, 2012, available at https://www.kommersant.ru/doc/1882127. Accessed December 12, 2017.   83. Kommersant, Supplement “Oil and Gas”, No. 156 (5187), 30.08.2013.   84. Vedomosti, September 6, 2015.

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80   Handbook of energy politics   85. Vedomosti, September 23, 2013.   86. https://www.rosneft.ru/press/releases/item/185281/. Accessed December 12, 2017.   87. Suzunskoye (4.8 mt/yr at peak production), Tagulskoye (4.7 mt/yr), Russkoye (7.5 mt/ yr) Yurubcheno-Tokhomskoye (5 mt/yr) and so on.   88. Vedomosti, December 11, 2013.   89. Vedomosti, November 15, 2015.   90. EIA (2016) “India. Country analysis brief.” Last updated June 14, 2016. Accessed December 12, 2017.   91. http://www.ved.gov.ru/monitoring/foreign_trade_statistics/countries_breakdown/. Acc­es­sed December 12, 2017.   92. https://www.rosneft.ru/press/releases/item/184363/. Accessed December 12, 2017.   93. https://www.rosneft.ru/press/releases/item/183891/. Accessed December 12, 2017.   94. https://www.rosneft.ru/press/releases/item/183889/. Accessed December 12, 2017.   95. V. Yermakov (2016) “Securing the future: the implications of India’s expanding role in the Russian oil sector,” Oxford Energy Forum, November, 107, 12–13.   96. Rosneft 2016 Annual Report, p. 105.   97. https://www.rosneft.ru/press/releases/item/184097/. Accessed December 12, 2017.   98. https://www.rosneft.ru/business/Downstream/refining/. Accessed December 12, 2017.   99. Vedomosti, September 18, 2014. 100. V. Mau and Ya. Kuzminov (2012) Strategy-2020: New Model of Growth – New Social Policy, Moscow: Delo, RANEPA, p. 803. 101. Svobodnaya Pressa (2015) “America’s new nightmare: India, China plus Russia,” May 15, first published March 14, available at http://in.rbth.com/world/2015/05/15/ameri​ cas_new_nightmare_india_china_plus_russia_43123. Accessed December 12, 2017. 102. V. Milov (2015) “Russia’s new energy alliances: Mythology versus reality,” Russie.Nei. Visions, 86, July, IFRI. 103. Kommersant-Online, June 14, 2011. 104. V. Zubov and A. Makarkin (2014) Vedomosti, November 18, available at https://www. vedomosti.ru/opinion/articles/2014/11/18/zachem-nam-kitaj. Accessed December 12, 2017. 105. gazeta.ru, February 28, 2015.

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3.  Energy transition and natural gas development in China Liu Xiaoli and Tian Lei

I. IT IS IMPERATIVE THAT CHINA’S ENERGY MAKES A LOW-CARBON AND GREEN TRANSFORMATION Over more than 30 years of rapid development, China has successfully stepped into the ranks of middle income countries, with its industrial scale even taking first place in the world. As an important material base of economic development, energy has provided a strong support for such a development miracle of China. However, a huge cost has also been paid. Currently, China relies heavily on coal, an extensive and inefficient energy development mode. This not only leads to a huge waste of resources and causes extremely serious environmental pollution and ecological environmental degradation, but also increases the risk of China falling into the Middle Income Trap. The extensive and inefficient energy development mode is a bottleneck problem for China’s development at present and in the future, and therefore it is imperative to advance the low-carbon and green transformation of energy. 1. The Current Mode of China’s Energy Development Has Caused Many Problems The long-term extensive development mode of China with a high-carbon energy structure heavily relying on coal that consumed a huge amount of energy has brought about constraints of the serious resource waste, the challenging eco-environmental problem and the increasing international pressure from addressing greenhouse gases emission reduction. First, the extensive and inefficient exploitation and utilization of energy has resulted in great energy waste. China has a generally low exploitation ratio of energy resources, with the overall recovery rate of coal resource being only 30 percent and utilization rate of coal gangue being only around 66 percent. The comprehensive efficiency of processing, transforming, storing and end-using of energy is only 38 percent which is more than 10 percent lower than that of developed countries.1 Though 81

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toe/thousand USD

0.5 0.4 0.3 0.24 0.2

0.15 0.09

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World

China

US

Japan

0.11

EU

Notes:  The data comes from the IEA and the calculation is based on the constant USD price 2005. China takes the data in 2015 and the world takes the data in 2013.

Figure 3.1  Energy intensity of some countries China has greatly improved its comprehensive energy utilization efficiency by various means, its GDP energy intensity is about 2.2 times the world average level, 3.5 times the level of America and 5.9 times the level of Japan. China’s GDP electricity consumption is about 2.4 times the world average level, 3.3 times the level of America and 4.6 times the level of Japan (Figures 3.1 and 3.2). Second, the large-scale use of fossil fuels has resulted in extremely serious environmental pollution. China’s SO2, NOx, fly ashes, dusts and inhalable particles have ranked the first in the world for a long time. Since 2013, large-scale haze has been observed many times in the BeijingTianjin-Hebei region, the Northern China region, the Three Provinces in Northeast China region and some provinces in the Central China region, causing a threat to health and constraint on the sustainable development of China’s economy and society, which put enormous pressure on the Chinese government. A vast majority of air pollutants come from the burning of fossil fuels, in particular the large-scale coal consumption is an important cause of haze. According to statistics, China’s SO2 emissions from the direct end-use of coal accounts for more than 40 percent of the total coal-fired emissions. And the dust and inhalable particles take an even higher proportion. Studies show that coal consumption contributes 50–60 percent PM 2.5 concentration.2

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0.92

kW · h/USD

0.8

0.6 0.38

0.4

0.28 0.2

0

World

China

US

0.2

0.2

Japan

EU

Notes:  The data comes from the IEA and the calculation is based on the constant USD price 2005. China takes the data in 2015 and the world takes the data in 2013.

Figure 3.2  Electricity consumption per unit GDP of some countries Third, the long-term high-strength exploitation and utilization of energy has seriously damaged the regional ecological environment. China’s coal mined-out areas have exceeded 1 million hectares in total. Coal exploitation has caused soil erosion in a range of about 245 km2 in the northwestern region, making the Yellow River Valley the area with the most serious soil erosion. High-strength development of hydropower resources has significantly changed the ecosystem of rivers, lakes and wetlands. Nuclear energy development has led to a long-term potential risk to the surrounding environment. Since regional ecological environments have approached and even reached the upper limit of their supporting capacity, ecological security has become an unbearable load of the country’s economic and social development, which has posed a strict restriction on the energy development. Fourth, the international pressure from addressing greenhouse gases emission reduction is growing. China has become the biggest CO2 emitter in the world and more than 80 percent of the emissions come from fossil energy consumption (Figure 3.3). In 2014, China’s per-capita emissions exceeded 7 tons which was higher than 5 tons, the world average level. At the APEC 2014, the Chinese government vowed to achieve the peak of carbon emission in around 2030. In June 2015, China released its Intended Nationally Determined Contributions (INDCs) for greenhouse gases emission reduction, which clearly defines the action plan to address

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84   Handbook of energy politics 10,000

8,000

6,000

4,000

2,000

1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

0

Source:  BP (2017).

Figure 3.3  Carbon dioxide emissions in China climate change in 2030 and suggests that CO2 emissions intensity will drop by 60–5 percent in 2030 compared with that in 2005. 2. Economic Transition Needs Energy Transition and also Provides Opportunities Transition China’s economy has entered a period of new normal. The economy will increase at a medium speed rather than at a high speed; the economic structure will undergo continuous optimization and upgrading; the service industry, the hi-tech industry and the equipment manufacturing industry will become important growth points; the economic growth mode will shift from the factor-driven stage and investment-driven stage to the innovation-driven stage; the economic development will be more dependent on the improvement of human capital and the advances of technology. Economic transition requires an energy transition towards high efficiency, convenience, low pollution and low carbon, and at the same time, the development of low carbon energy industry will also provide a major support for the economic transition. With economy’s entry into the period of new normal, the energy development also shows a new trend of low growth and low increment and the energy demand will shift from medium and high speed growth to low speed growth. The growth of total energy consumption lowered from an annual average of 8.1 percent in 2003–11 to less than 4 percent in 2012–14

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Energy transition and natural gas development in China  ­85 Growth rate of energy consumption Reduced Obviously

% 20

50 16.8% 40

12.2% 108Tce

16

16.2% 13.5%

30

12 9.0%

20

5.8%

9.6%

8.7% 8

6.7% 4.8% 7.3%

7.3%

10 2.9% 0

3.6% 3.9% 3.7% 2.2%

4 0.9%

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

0

Annual Energy Consumption Annual Growth Rate Average Annual Growth Rate

Source:  China Energy Statistical Yearbook 2000–2015, China Statistics Press.

Figure 3.4  Lowered growth of China’s energy consumption (Figure 3.4) and the increment also reduced from an annual average of 210 million tons of standard coal in 2003–11 to 130 million tons of standard coal in 2012–14 (Figure 3.5) which means a great relief of pressure from an ensured energy supply. The situation of quickly meeting the growth of demand by large-scale coal exploitation will be gone forever. It will bring important opportunities for China to accelerate the adjustment, optimization and upgrading of its energy structure which will promote the implementation of energy revolution. 3. China’s Energy Revolution Strategy Requires the Low-Carbon and Green Development of Energy In June 2014 the Chinese government put forward that it would vigorously advance the overall energy development strategy of the Energy Production and Consumption Revolution. It would comprehensively promote the consumption revolution, the supply revolution, the technical revolution and the institutional revolution of energy, and deepen the international energy cooperation, striving to address the root cause of a large number of constraints on energy development, promote the transformation and upgrading of energy industry and fully safeguard national energy security.

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86   Handbook of energy politics Annual Energy consumption Increment Reduced Obviously 3.5

3.3

3.0

2.8

108Tce

2.5

2.3

2.5

2.5

2.5

2.6

2.0

2.0

1.6

1.4

1.5 1.0

3.1

0.9

0.9

1.5

1.5 1.4

0.9 0.4

0.5 0.0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Annual Energy consumption Increment Average of Annual Energy consumption Increment

Source:  China Energy Statistical Yearbook 2000–2015, China Statistics Press.

Figure 3.5  C  hina’s energy consumption entering a period of lowered increment The overall goal of China’s energy revolution strategy is to strive for transition of energy production and consumption mode towards the low carbon and green mode through a series of revolution-based measures and hardworking efforts. Specifically, for one thing, China will strengthen the management over the total energy consumption, intensify the reduction and substitute measure in total production and consumption of coal, vigorously promote system energy saving, and constantly improve energy efficiency. For another, China will greatly strengthen the ability of green development and clean conversion of energy. It will massively increase the development and utilization of natural gas, high proportionally develop non-fossil energies, actively build a new intelligent power system and energy Internet, constantly increase the systematic and intelligent level of energy, and strive to construct a clean, efficient, safe and sustainable modern energy system. The energy development strategy set by the Chinese government will help the vigorous development and utilization of natural gas. 4. The Low-Carbon and Green Development of Energy has Become a Global Consensus At present, around 67 percent of greenhouse gas emissions are correlated with energy production and consumption. In order to address the ­challenge

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Energy transition and natural gas development in China  ­87 of climate change, the Paris Agreement was established at the Paris Conference on Climate Change in December 2015. The Paris Agreement requires the implementation of low carbon transition of economic growth, consumption and energy. It establishes the basic structure that all the countries extensively participate in the transition and determines the international institutional arrangement for addressing climate change after 2020 focusing on the Intended Nationally Determined Contributions, which will greatly promote the transition of energy consumption in the world from coal and oil to natural gas and renewable energy. In the early stage of the low carbon and green development of global energy, that is, the period by 2030, the fossil energy age will not come to an end and natural gas will become a single energy in the world with the greatest growth in that stage, a transition period. In the past decade (2005–2014), natural gas in the world had a consumption growth of around 2.7 percent, and it was the fossil energy with the fastest growth. The IEA estimates that natural gas will have a consumption annual average growth of 1.4 percent by 2040 and become the one with the fastest growth among fossil fuels. The consumption of natural gas will increase from 3.51 trillion m3 in 2013 to 5.16 trillion m3 in 2040.3

II. NATURAL GAS SERVES AS A BRIDGE FOR THE LOW-CARBON AND GREEN TRANSFORMATION OF CHINA’S ENERGY Almost all the industrialized countries have experienced severe air pollution resulting from a coal-dominated energy structure. International experience shows that vigorous development of natural gas is the typical practice of developed countries and emerging economies to optimize and upgrade their energy system. It was predicted by our research team one year ago that China’s energy demand will continue to increase at about 1.7 percent by 2030. With efforts to be made, the proportion of non-fossil energy in the primary energy consumption structure may reach 20 percent, but that of coal will remain close to 50 percent. Therefore, it is difficult to achieve the important task of energy transition by relying solely on non-fossil energy. Vigorous development of natural gas is the most realistic choice for China to achieve the transition from high-carbon energy to low-carbon and carbon-free energy. Besides, China has the condition and foundation for large-scale use of natural gas which can serve as a transition in the energy structure transformation of China, and act as an important support for the low-carbon energy transition of China in a rather long period of time.

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88   Handbook of energy politics 1. Increasing the Scale and Proportion of Natural Gas Use is the Core Measure to Achieve the Goal of Addressing Air Pollution and Reducing Carbon Emissions As the cleanest hydrocarbon fuel, the environmental protection advantage of natural gas has gained a wide spread recognition. In the field of industrial fuels, in contrast with coal and oil, natural gas records a SO2 emission reduction of almost 100 percent and a fly ash emission reduction of more than 60 percent. In the field of power generation, in contrast with coal, for the same electricity and heat supply, in contrast with the “ultralow-emission” coal-fired power plants, gas-fired power plants record a fly ash emission reduction of 96 percent, SO2 emission reduction of almost 100 percent and NOx of 55 percent. If the gas-fired power plant’s need for water resource is taken into account, the environmental significance of natural gas will be even greater. This is because the amount of water required is one-fourth of that required by a coal-fired power plant or a nuclear power plant due to the difference of cooling systems they adopt. In contrast with burning the coal of equivalent heat value, burning of 1 cubic meter of natural gas records a CO2 emission reduction of between 47 percent and 84 percent based on the estimates of the China Petroleum Planning and Engineering Institute (Sun Hui, Li Wei 2009). So long as proper environmental measures are adopted, the environmental benefits of changing to the use of natural gas will be remarkable. China is making efforts to increase the scale and proportion of natural gas use. It is estimated that the use of natural gas will replace the scattered use of 0.3–0.4 billion tons of coal by 2030. It will reduce the PM2.5 concentration by more than 10 percent according to rough estimation, which means a great reduction of carbon emission and a great significance for the improvement of health and well-being and the fulfillment of carbon reduction goals. 2. Natural Gas is the Major Quality Energy to Support China’s New Urbanization Construction In 2015, China’s urbanization rate just reached 56 percent which was not only obviously lower than the level of developed countries – almost 80 percent – but also lower than the level of the countries in the same development stage, and therefore, there will be a great potential for China’s urbanization development. The Chinese government clearly put forward the concept of “New Urbanization” in the 18th Party Congress and promulgated the National New Urbanization Planning (2014–20). According to the goal of the planning, the urbanization rate of permanent resident

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Energy transition and natural gas development in China  ­89 population will reach around 67 percent by 2030, when more than 0.18 billion agriculture population and other permanent resident population will transfer to and settle in urban areas. According to empirical data analysis, the increase of urbanization rate of every one percentage point will bring about an energy consumption of about 80 million tons of standard coal which means an energy demand of about 0.9 billion tons of standard coal will be created when the urbanization rate increases from 56 percent in 2015 to 67 percent in 2030. During the process of new urbanization development, with the migration of rural population to urban areas, domestic demand for energy, especially clean energies such as natural gas will increase rapidly. There is a big difference between domestic urban residents and rural residents in the level and method of energy use. The per-capita energy consumption in urban area is 3–3.5 times that in rural areas and the lifestyle in urban areas needs more natural gas, electricity, oils and other quality energies. Therefore, natural gas will be a major quality energy to support the rapid development of China’s new urbanization process, because it is not only a major energy type to meet the increased demand of energy but also a realistic choice to replace coal. 3. Promotion and Utilization of Natural Gas will be Conducive to the Increase of China’s Energy Efficiency Level It is difficult for conventional coal power units to have a breakthrough improvement in thermal efficiency due to the limits of their own equipment and system. The most advanced ultra-supercritical power generation unit can have a theoretical power generation efficiency of 48–57 percent. Gas-steam combined-cycle power generation with an efficiency close to 60 percent at present (which is still increasing) is one of the applied power generation technologies with the highest efficiency. The system of gas-fired combined heat and power (CHP) can have an efficiency of 60–80 percent. And the system of combined cooling, heat and power (CCHP) can have an efficiency as high as 90 percent, which ranks first in the efficiencies of energy conversion technologies that have already been commercialized and are available for large-scale application. In addition, the application of natural gas in the distributed energy system has a great significance to the fulfillment of cascade utilization of energy which can reduce the losses caused in the transportation process and improve the energy utilization efficiency.

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90   Handbook of energy politics 4. Natural Gas can Promote the Development of Renewable Energy and Accelerate the Low-Carbon Process Wind and solar energy are ideal clean energies. But due to the random and intermittence of wind power and solar power generation, the generation capacity is correlated with climate conditions. Large-scale application of wind power and solar power generation has a very high requirement on the power grid, because a peak-load regulation power source should be provided. Gas power generation has a very good regulation capacity and peakload regulation performance. From starting-up to full-load operation, the combustion turbine normally needs less than 20 minutes, and in case of quick starting up, the time is even shorter. Output of the combustion engine can be continuously regulated within a range of 0–100 percent. Therefore, it has become a consensus in the world that the combustion turbine and gas-steam combined cycle are used for peak-load dispatching power stations in big cities. In future, China’s variable power sources such as wind power and solar power will rapidly develop. According to the results of the Study on the Gas Power Generation for Improving Power Grid’s Capacity to Accommodate More Wind Power by the ERI of the NDRC (Liu Xiaoli et al. 2012), if the development scale of wind power across the country reaches 100–50 GW by 2020, the installed capacity of wind power in the power grid of North China, East China and Northeast China regions will vary between 64.50 GW and 99.75 GW. Since the peak-load regulation capacity of the system varies with the increase or decrease of wind power development scale, the installed capacity of gas-fired generation in the three regions may change between 33.5 GW and 36.83 GW. Put another way, if the installed capacity of gas-fired generation increases by about 3.48 GW, it will bring about a development scale of wind power of approximately 35.25 GW in the aforementioned regions. In addition, the distributed gas-fired generation can also serve as a complement for renewable power generation in remote areas, so as to ensure the efficient use of large-scale high voltage power transmission systems. Thus, the development of natural gas is favorable for promoting the development of renewable energy, accelerating the low-carbon process.

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Energy transition and natural gas development in China  ­91 5. Breakthroughs in Unconventional Oil and Gas Technologies are an Important Part of the New Round of Energy Revolution which will Contribute to the Transition and Upgrading of China’s Energy Industry and Drive the Economic Growth The significance of America’s shale gas revolution just lies in the exploration of the resource boundary of traditional fossil energy. At the same time, the technology for the low-carbon use of traditional fossil energy also witnesses an accelerated development and will mature gradually. China’s unconventional oil and gas technologies are experiencing accelerated development and important breakthroughs have been made in shale gas exploration and development. Breakthroughs in non-conventional oil and gas technologies will not only ensure the demand for oil and gas supply in the process of China’s energy structure transformation, but will also drive the transformation and upgrading of the energy industry to promote the national economic development. In future, there will be a great potential for natural gas development in China. China Petroleum Planning and Engineering Institute estimates that the end-use market alone will have its scale tripled by 2030. If the growth potentials of various aspects in the upper stream, midstream and downstream of the natural gas industrial chain are also considered, a substantial investment demand will be created. It is estimated that an accumulative investment increase of approximately 6 trillion yuan will be created in the period from 2015 to 2030, corresponding to an annual investment increase of 400 billion yuan, which can bring about an annual GDP growth of 0.6 percentage points.

III. CHINA HAS THE CONDITIONS FOR LARGESCALE DEVELOPMENT AND UTILIZATION OF NATURAL GAS 1. China is Abundant in Natural Gas Resource with Rapid Increase of Production Output China has a solid base of natural resources and is in a period of rapid development of natural gas exploration with fast growth of reserves and production. According to the Dynamic Evaluation of National Oil and Gas Resources 2015,4 China’s geological resources of natural gas amount to 90.3 trillion m3 and the recoverable resources amount to 50.1 trillion m3 corresponding to an increase of 158 percent and 127 percent respectively in contrast with the results of the 2007 evaluation of national oil and gas

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Natural Gas Production

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–5 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Natural Gas Production/*10–1 billion cubic meters

resources. By the end of 2015, the remaining technologically recoverable reserves were 5.19 trillion m3. China is also abundant in the resources of unconventional natural gas with accelerating exploration and development. The geological resources of shale gas across the country within a depth of 4,500 meters underground are 122 trillion m3, the recoverable resources are 22 trillion m3, the accumulative proven geological reserves are 544.1 billion m3 and the proven rate is only 0.4 percent. The geological resources of coal-bed methane within a depth of 2,000 meters underground are 30 trillion m3, the recoverable resources are 12.5 trillion m3, the total proven geological reserves are 629.3 billion m3 and the proven rate is only 2.1 percent. With important progress being made again and again in the exploration and development of natural gas, China’s output of natural gas rapidly increased from 27.2 billion m3 in 2000 to 124 billion m3 in 2015, with an annual average increase of more than 10 percent. China has made great breakthroughs in shale gas exploration, with commercial development officially started in 2014 and a shale gas output across the country reaching 4.47 billion m3 in 2015. China has also gained rapid growth in coal-bed methane output, recording 4.43 billion m3 across the country in 2015 with a 24.75 percent increase year-on-year (Figure 3.6). It is estimated by our research team that China will continue a rapid growth trend in natural gas output by 2030, and the output is expected to exceed 232 billion m3 in

Source:  China Energy Statistical Yearbook 2000–2015, China Statistics Press.

Figure 3.6  Natural gas output of China

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Energy transition and natural gas development in China  ­93 2020. The output of conventional natural gas will reach 160 billion m3, the output of shale gas will reach 20 billion m3, the output of coal-bed methane will reach 10 billion m3 and that of coal-to-gas will reach 10 billion m3. The output of natural gas will continue to grow to 350 billion m3 in 2030, out of which, the output of conventional natural gas will reach 260 billion m3, the output of shale gas will reach 50 billion m3, the output of coal-bed methane will reach 20 billion m3 and that of coal-to-gas will reach 20 billion m3. The rapid growth of domestic natural gas output provides a resource base for China to explore and utilize it in a large scale. 2. The Main Frame of Natural Gas Infrastructure Across the Country is Basically in Place With the rapid construction of the infrastructure such as gas trunk pipelines, LNG receiving stations, the main frame across the country is already basically in place, gradually strengthening its role to guarantee the development of natural gas market. By the end of 2014, the length of the natural gas pipeline that has been put into operation reached 69,000 km, with the total gas transportation capacity of the trunk pipeline network exceeding 200 billion m3/year. In China, the gas supply structure of gas supply from the western area to the eastern area, domestic offshore gas and LNG imports to mainland, local gas supply from oil and gas fields has basically taken shape, thus a network of natural gas pipeline across the country began to take shape. In future, China will continue to make improvements, vigorously developing the gas truck pipeline network, the LNG pipeline and the pipelines for the connection of different regions, thus constructing a complete national network that achieves the interconnection among various kinds of gas resources. At present, there are 11 LNG receiving stations and one transfer station in operation, which have basically covered the coastal areas of China and provided more resource supports for the sustainable economic development of the coastal areas of China. During the 13th Five-Year Plan period, priority will be given to the storage capacity expansion of the already-built LNG receiving stations. It is estimated that there will be seven LNG receiving stations with second-phase capacity expansion being completed by 2020. In addition, there will be at least seven first-phase LNG receiving stations completed by 2020, which will mainly be located in South China and East China, and it is estimated that the total LNG receiving capacity of China will reach 77.4 million tons/year by 2020.

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94   Handbook of energy politics 3. Structural Reform of the Oil and Gas Industry is Favorable for the Development of Natural Gas The Chinese government is making efforts to promote and deepen the reform of the oil and gas industry, with the orientation towards further deregulation. It promotes the fair participation of various players in relevant areas of the oil and gas industry to the greatest extent, gradually eliminating the trade barrier that impedes entry of private capitals. This improves the fairness in resource occupancy and opportunity access, so as to create a fair and compliant business environment, improve the industry chain’s efficiency and achieve the rapid development of the oil and gas industry. In the upstream field, the government will reform the exclusive operation system for the exploration and development of oil and gas resources in an orderly way, relax the limit on the access to the exploration and development provided that standards for the qualifications in technology, environmental protection, capital and safety are clearly defined, and gradually create a main structure of exploration and development involving various players. In the field of pipeline transportation and distribution, the government will further improve the mechanism for the fair access to the oil and gas infrastructures. It will promote the transparency of pipeline transportation, storage, gasification and liquefaction data capacity, promote the independent operation of important infrastructures in an orderly way, with infrastructure management being separated from the operation and encourage the diversification of players who run infrastructure operation business and players who invest infrastructure. In the field of enterprise management, the government will deepen the joint stock reform of state-owned oil and gas enterprises to further improve their management system and operation mechanism. It will promote the independent operation of such oil and gas businesses as technical services, engineering construction and equipment manufacture, so as to cultivate and establish a completely market-oriented competition system in the technical services, engineering construction and equipment manufacture for the oil and gas industry. The reform will vitalize and promote the rapid development of the natural gas industry. 4.  The World has Abundant Natural Resources with Sufficient Supplies Judging from an international perspective, we are now in an opportunity period when the global natural gas markets have increased supplies. For over ten years, the proven reserves of natural gas have maintained a very fast growth trend. According to the statistics of the IEA, currently the global natural gas resources amount to 751 trillion m3 with a remaining

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Energy transition and natural gas development in China  ­95 proven recoverable amount of 185.7 trillion m3, recording a reserve and production ratio of 55.1. Besides, the annual increase of proven reserves exceeds the consumption of natural gas, and the reserve and production ratio shows a steady growth trend.5 At the same time, the natural gas output in the world reached 3.54 trillion m3 in 2015 (BP 2017). According to BP, benefiting from the robust growth of global shale gas output, the natural gas supply will increase steadily with an estimated annual growth of up to 5.6 percent. The proportion of shale gas in the total output of natural gas will increase from 10 percent in 2014 to almost 25 percent in 2035. The growth of shale gas output will change North America from a net import region to a net export region. With the constant production capacity expansion of LNG, the supply of LNG will exceed demand in around 2020. The sufficient supply of natural gas in the international  market provides a foundation for China to use the international resources.

IV. SEVERAL MAJOR ISSUES TO BE ADDRESSED FOR THE LARGE-SCALE DEVELOPMENT AND UTILIZATION OF NATURAL GAS Though there is great potential for natural gas demand in the Chinese market, China will face challenges in terms of sustainable development and utilization of natural gas. In order to bridge the transition to lowcarbon and green energy, China urgently needs to accelerate the reform of the whole natural gas industry chain and address several major issues. These include a market-based gas price mechanism, a lag in infrastructure development, fair access to infrastructures, safe supply of natural gas and support from relevant fiscal and tax policies. 1. The Establishment of a Market-Based Gas Price Mechanism and Improvement of Competitiveness Gas price is a core factor that currently restricts the development of China’s natural gas market. This is highlighted by high gas price, unreasonable price relations with other energies and the unavailability of a complete market-based pricing mechanism. The high gas price and unreasonable price relations with other energies have seriously restricted the expansion of China’s natural gas market. Take the gas supplied through onshore pipelines, for example. In 2015, the city gate price in Shanghai was 12.5 USD/MMBtu and the terminal sales price was above 17 USD/MMBtu, which were much higher than prices

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96   Handbook of energy politics non-residential city gate prices

14.8

Imported LNG prices

3.0

12.7

2.5

10.6

2.0

8.5

1.5

6.3

1.0

4.2

0.5

2.1

0.0

Guangdong Shanghai

Zhejiang

Jiangsu

Shandong

Hebei

Liaoning

US$/MMBtu

yuan/m3

3.5

0.0

Notes:  (a) Imported LNG price includes gasification and transportation fees. (b) Exchange rate in 2015 between US$ and RMB is 6.38. Source:  SIA Energy (2015). Data of imported LNG price is from China’s customs. Nonresidential city gate prices in some provinces are from http://www.ndrc.gov.cn/gzdt/201511/ t20151118_758904.html.

Figure 3.7  T  he comparison of imported LNG prices and current nonresidential city gate prices in some provinces in North America and Europe. Though under the impact of declined international oil price, the NDRC lowered the national average city gate benchmark price of natural gas in November 2015. The average price was lowered from 2.5 yuan/m3 to 1.81 yuan/m3 in April 2015, with a cut as high as 28 percent, the imported LNG price remained higher than most of the city gate prices (Figure 3.7) which made natural gas uncompetitive compared to other energies. In January, 2016, the price of natural gas for industrial users in Beijing City was four times that of coal for industrial users, and the price of natural gas for power plants was three times that of coal for power plants (Figure 3.8). The lack of competitiveness greatly restricts growth of new gas users – as a result, natural gas is even replaced by coal and fuel oil in some regions. Transportation and distribution contribute a great deal to the price increase (the premium rate in those processes exceed 100 percent in some regions) which is also an important cause of high terminal sales price of natural gas. The high price of domestic natural gas is surely partially caused by the objective condition of resource endowment (burying depth, geologic structure and associated resources from the exploitation of oil and gas), but there is still great potential for cost reduction and benefit increase. We should first loosen the limit on the market access, increase the market competitiveness and vitality, promote

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Energy transition and natural gas development in China  ­97 Ratio of Beijing’s gas price for industrial users and power plants to steam coal price of Qinhuangdao 7 6 5 4 3 2 1

20 15 20 /4/ 15 1 20 /4/1 15 5 20 /4/2 15 9 20 /5/1 15 3 20 /5/2 15 7 20 /6/1 15 0 /6 20 /24 15 20 /7 15 /8 /7 20 /22 15 20 /8 15 /5 /8 20 /19 15 20 /9 1 /2 20 5/9 15 /16 20 /10 15 /14 20 /10 15 /28 20 /11 15 /11 /1 20 1/2 15 5 20 /1 15 2/9 /1 2 20 /23 16 20 /1/ 16 6 /1 /2 0

0

gas for industrial use

gas for power generation

coal

Source:  Author’s calculation.

Figure 3.8  P  rice comparison of natural gas and coal for power plants and for industrial users innovations and marketization of equipment, so as to increase domestic output and reduce production cost. At present, the government is also making efforts to formulate a method for supervising price in areas of pipeline transportation and storage so as to strengthen the government supervision over natural monopoly areas. China’s natural gas is still in a transitional stage from regulated price to market pricing. Before 2012, the cost-plus method was adopted for the pricing of natural gas, with the price regulated by the government. Since 2013, the netback pricing method has been adopted to gradually loosen the price regulation. At present, market pricing is implemented for the ex-factory price of offshore natural gas, shale gas, coal-bed methane, coal gas and the LNG price, and the natural gas supplied by onshore pipeline is still priced by the government. Though the government encourages the gas price to be determined through negotiation between the supplier and the consumer in the case of large consumers enjoying direct gas supply, it is difficult for such a practice to be implemented. This is because the government has set the benchmark city gate price of each province. Moreover, the gas price for residential users and that for non-residential users involve great cross-subsidies. Gas price is significantly raised for industrial, commercial and other non-residential users and increases the burden of enterprises. In some regions, adjustment of sales price falls behind that

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98   Handbook of energy politics of city gate price; as a result, the changes of upstream markets cannot be reflected in a timely manner. In addition, the policies for the gas price of peak-load regulation supply and that of interruptible supply are not available. We should further improve the price mechanism of natural gas, establish a dynamic adjustment mechanism that is tied to alternative energies, and loosen regulation on gas price for non-residential users as soon as possible. We should also determine price by the relation between market supply and demand, introduce policy to merge gas price for residential users and for non-residential users, eliminate cross-subsidies between gas price for residential users and that for industrial and commercial users, and formulate incentive pricing policies such as the introduction of gas price for interruptible supply and that for peak-load regulation supply. 2.  Infrastructure Development Lag China’s infrastructure development lags behind that of the natural gas market. Though China has made rapid development in the construction of long-distance gas pipelines, with a length reaching 69,000 km, it is still far behind the developed countries. For example, the total length of gas pipeline of China is merely 1/8 that of America and 1/4 that of Russia; pipeline network density is merely 1/8 that of America, 1/9 that of France, and 1/10 that of Germany. Due to the impact of such factors as the unclear responsibility for a guaranteed supply, the unreasonable price mechanism and the unavailability of a market mechanism that encourages the construction of gas storage facilities, the construction of gas storage facilities also falls behind. This leads to a seriously inadequate capacity of peak-load regulation and directly impacts the safe and stable gas supply and the growth of market. The peak-valley difference of gas use in China goes up year by year, the monthly uneven factor increased from 1.2 in 2010 to 1.42 in 2015, and the peak-valley difference in winter and summer in Beijing, Tianjin and Hebei was as high as more than ten. By the end of 2015, the effective gas volume of China’s underground gas storage was about 5.5 billion m3, which was only 3 percent of the gas consumption, much lower than the international average level, 11 percent. Due to the impact of inadequate capacity of peak-load regulation which depends on the capacity of gas storage, the problem of limiting production in summer while limiting supply in winter is quite serious. With the further expansion of natural gas market and the rapid growth of demand for peak-load regulation, the task for the construction of gas pipeline network and underground gas storage tanks will be more arduous. It is estimated that the added length of China’s gas pipeline will exceed 100,000 km and the demand for gas peak-load regulation will approach 30 billion m3 by 2030.

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Energy transition and natural gas development in China  ­99 At present, the construction and operation of China’s gas pipeline networks are still managed by a small number of large state-owned enterprises and are subjected to an operation mode of vertical integration. Such an operation mode played a positive role in the early stage of natural gas market development. However, with the rapid expansion of market size and the diversified players of upstream and downstream markets, it has already impacted social capital investment in the construction of infrastructures and seriously restricted the implementation of third-party access and the reform of natural gas price. In order to promote pipeline construction, various investors should be allowed to participate in the investment and operation of relevant facilities including pipeline networks and LNG terminals in the way of independent legal entities. A reasonable and transparent pricing mechanism for pipeline networks and a unified standard for gas volume calculation shall be established so as to make investors interested in pipeline construction and ensure the interconnection of gas pipeline networks. We should explore and establish an independent pricing mechanism for gas storage peak-load regulation and introduce corresponding policies of financial supports for different types of gas storage facilities, so as to motivate enterprises to participate in the construction of these. 3.  The Establishment of Fair Access to Gas Infrastructures In order to promote fair access to oil and gas pipeline facilities, improve the utilization efficiency of the facilities and ensure the safe and stable supply of oil and gas, the National Energy Administration introduced the Method for the Supervision of the Fair Access to Oil and Gas Pipeline Facilities (Trial) (“Supervision Method” for short) (National Energy Administration 2014). Since the introduction of the Supervision Method, an attempt has been made for third-party access to LNG import. As a result, enterprises like ENN Gas Holdings Ltd., Guanghui Energy Co. Ltd., Pacific Oil & Gas, Dalian Yintai Chemicals Logistics Co. Ltd., Huagang Gas Group (Hebei) and Beijing Gas have successively taken advantage of the LNG terminals of CNPC and the floating LNG wharf of CNOOC in Tianjin. They have done so through negotiations or with granted approvals to import spot LNG. However, due to the integrated production, transportation and sales of natural gas in China, the gas pipelines of the three major oil companies (PetroChina, Sinopec, CNOOC) are only used for the transportation of natural gas produced and sold by themselves, so the motivation to get the pipelines open is not available. Also, due to concern about the limited gas market capacity that the fair access may result in the three major oil companies’ breach of the long-term

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100   Handbook of energy politics contract in LNG, the fair access will conflict with the responsibility of the upstream enterprises for guaranteed supplies. The third-party users are a small number, the actual needs for fair access are less, the relevant legislation level is not high and the effective supervision is not available. It is difficult for the fair access to be effectively achieved under the existing system; as a result, some companies have got the gas source in overseas markets but cannot make the gas enter Chinese market through LNG terminals or pipelines. We should follow the reform thinking of releasing the upstream and downstream regulations, and supervising the transportation and distribution businesses in future to actively promote the implementation of separating transportation from upstream, distribution and sale, and implement the fair access of third parties. At the same time, we should improve the regulations for the implementation of fair access and strengthen the supervision over the fair access to infrastructures and the pipeline transportation charges. 4.  Safe Supply of Natural Gas In order to meet the requirement of the growing natural gas market, China needs stable natural gas supplies with reasonable prices. But there are challenges both from domestic natural gas exploitation and from the import of overseas pipeline gas and LNG. Natural gas exploitation in China is restricted by low cost and green development. Low oil price since 2014 has already impacted on the production and operation of China’s oil and gas enterprises. The enterprises suffered a great decline in profits, and investment in the upstream exploration showed a significant reduction. Meanwhile, unconventional natural gas will become the focus of China’s gas exploration, but its high cost is still not properly addressed, which may drive up the average cost of gas exploration. With the constant growth of demand for natural gas in China, the eco-environmental problems caused by the vigorous exploration of oil and gas will increase, and the contradiction between the economic benefits and the environmental governance during the exploration of resources will be more acute. The increased reserves and output of oil and gas in future will mainly come from the fields of unconventional and deep-sea resources and this will also lead to the increase of production cost. With the importation of natural gas comes problems of high prices and uncertainties. Since China started to import natural gas in 2006, its dependence on imported natural gas has exceeded 30 percent (in 2015). In order to meet growing domestic demand, China will continue to import a huge amount of natural gas, but since it is currently faced with high prices for both pipeline natural gas and imported LNG, some import enterprises

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Energy transition and natural gas development in China  ­101 are suffering great losses. In addition to high prices, some pipeline gas and LNG projects are faced with difficulties in the development of gas sources due to the great decline in international oil prices. This poses a risk to the stable supply. Moreover, necessary policy supports are required for the development of natural gas, such as those for the development of unconventional natural gas, infrastructure construction and natural gas utilization technology.

V.  CONCLUSION 1. Whether because of the various problems and challenges faced by China’s energy development, or the world’s low-carbon and green energy development trend, it is imperative for China to implement a low-carbon and green transition of energy. Consequently, China has put forward the energy revolution strategy. 2. In China, increasing gas consumption is seen as an important means to optimize energy structure, address air pollution and promote economic growth. And it is also the realistic choice to avoid path dependence on coal energy, since China has the conditions for the large-scale supply of domestic resources. Gas can serve as a transition energy in China’s energy structure transformation, and act as an important support for the low-carbon energy transition of China for a rather long period of time. 3. China is abundant in natural gas and has great potential in its output. The development of infrastructures including natural gas pipeline networks and LNG receiving stations are progressing quickly. The basic structure of a gas trunk pipeline network across the country is in place. The global natural gas markets have increased supplies, therefore the country is in an opportunity period for large-scale development and utilization of natural gas. 4. Though China has great potential for the development of the natural gas market, we should not ignore the difficulties and challenges that it will face due to the high price of natural gas, the inadequate capacity of gas storage and peak-load regulation, the failure to effectively implement the fair access to the infrastructures and the risks in safe and stable supplies. 5. China should seize the opportunity from the structure change of global natural gas market and the reform of oil and gas industry to adjust and improve the policies that support the development of natural gas, reduce the cost of natural gas use, improve economic competitiveness, ensure the safety of supply and make natural gas a bridge in the process of energy transition.

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102   Handbook of energy politics

NOTES 1. Wang Zhongying, Zhang Yousheng, et al. (2016) The Construction of Eco-civilization and Transformation of Energy. 2. Wang Zhongying, Zhang Yousheng, et al. (2016) The Construction of Eco-civilization and Transformation of Energy. 3. IEA (2015) “World energy outlook 2015.” 4. Dynamic evaluation of national oil and natural gas resources 2015, http://www.mlr.gov. cn/xwdt/jrxw/201606/t20160614_1408518.htm. 5. IEA (2015) “World energy outlook 2015.”

REFERENCES BP (2016) “BP energy outlook 2016.” https://www.bp.com/content/dam/bp/pdf/energyeconomics/energy-outlook-2016/bp-energy-outlook-2016.pdf. BP (2017) “Statistical Review of World Energy 2017 – underpinning data.” https://www. bp.com/content/dam/bp/en/corporate/excel/energy-economics/statistical-review-2017/bpstatistical-review-of-world-energy-2017-underpinning-data.xlsx. China Energy Statistical Yearbook 2010–2015 (2015) Beijing: China Statistics Press. “Development report 2015 of oil and gas industry at home and abroad” (2015) Beijing: Petroleum Industry Press. IEA (2015) “World energy outlook 2015.” London: IEA. Liu Xiaoli et al. (2012) “Gas power generation for improving power grid’s capacity to accommodate more wind power.” Beijing, December. (The research report is supported by the China sustainable energy program of the energy foundation.) National Energy Administration (2015) “Method for the supervision of the fair access to oil and gas pipeline facilities (trial).” http://www.nea.gov.cn/2014-02/24/c_133139014.htm. Sun Hui, Li Wei (2009) “How does natural gas play a role in energy saving and emission reduction?” Petroleum Planning & Engineering, (5) (Chinese). Wang Zhongying, Zhang Yousheng et al. (2016) The Construction of Eco-civilization and Transformation of Energy, Beijing: China Economic Publishing House.

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4.  Institutions and the supply of oil Douglas B. Reynolds

I  INTRODUCTION Institutional economics theory, as explained in Commons (1931), North (1981) and Williamson (1985), suggests that having the correct institutions in place will lead to greater social welfare and more economic growth for a given country. The conventional wisdom that Acemoglu and Johnson (2005) and Banerjee and Ghatak (2005) elaborate on is that historical accidents, such as colonization episodes by a particular country, can result in the placement of welfare improving or welfare reducing institutions that eventually result in higher, or lower, growth potential. On the one hand, it is often suggested that England put in place in what is now the United States of America good property right institutions, which is hypothesized to have induced outstanding U.S. economic growth. On the other hand, in South America, the King of Spain gave special favors to insiders for lucrative gold mining and other concessions, which created poor property right institutions, which is hypothesized to have induced poor economic growth in Latin America. An alternative hypothesis for the difference in growth between Latin America and North America could be their respective geographic economic potential as Diamond (1997) explains. Indeed, Acemoglu et al. (2001) show that institutions are not necessarily exogenous but endogenous. Therefore, as Gleaser and Shleifer (2004) argue, instead of good institutions causing high growth rates to occur, it is high growth rates that cause good institutions to emerge. A third proposition by Banerjee (2002) is that institutional change can be looked at in the same way as technological change. A new institutional framework that is invented or borrowed will be used if it results in an overall gain to society, otherwise it will be discarded. Various institutions can also affect oil and gas production. For example, consider two particular oil and gas regions: Texas and Alaska. On the surface, they both have the same institutional makeup since they both have a well-developed property right rule of law, the same federal regulations and the same national constitution. However, there are important differences. Texas has mostly private mineral rights ownership, but Alaska has mostly government-owned mineral rights. While such property right 103

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104   Handbook of energy politics variances may sound similar, there is clearly a difference in incentives as the Texas landowners are much more aggressive in incentivizing oil exploration and development than are the government landholders in Alaska. Some have suggested that this is one reason for the lack of robust exploration and production on Alaska’s North Slope in comparison to Texas. This distinguishing characteristic in property right institutions, then, suggests that if a country changes its institutions to a Texas style, individual property right system, then that country could find and extract more oil, more quickly than otherwise. However, Texas and Alaska have many other differences in their respective oil and gas industries that also affect exploration and development, such as the weather, the level of remoteness and the available infrastructure of the regions. On the one hand, Alaska has bottlenecks to get its oil to market because there is only one single trans-Alaska oil pipeline, through which all North Slope oil must be transported to market. On the other hand, Texas has many pipelines and refineries, which all compete with each other to obtain oil from the various in-state and nearby outof-state oilfields. The level of competition in Texas allows oil producers to find the cheapest option to transport and refine their oil to maximize its value. In Alaska, the pipeline bottleneck creates a natural economy of scale for the oil conditioning plant that processes the oil, separates the water and natural gas and produces miscible injectants out of propane. The larger the plant the cheaper its costs. However, this bigger, cheaper plant creates a monopsony for independent producers that can create costlier oil processing, which inhibits exploration. Nevertheless, the different exploration outcomes and different institutions of Texas and Alaska do suggest that institutions can affect oil production when considered appropriately alongside other variables. Also, as we will see, government-owned oil production enterprises, such as National Oil Companies (NOCs), can also have a large effect on oil supplies within a country due to risk aversion.

II THE MARKOWITZ EFFICIENCY FRONTIER FOR INVESTMENT RISK Explaining how oil producers operate and how institutions affect those operations is difficult to do without first explaining how risk and uncertainty affects firms. One of the heralding ideas of free market enterprise, as Coase (1937) shows, is that the individual firm is the best entity for producing goods and services while efficiently allocating scarce resources. Firms always want to perform better and become more profitable, and

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Institutions and the supply of oil  ­105 in this way, assuming markets are competitive, they create economic efficiency for all of society. High profits, in a competitive environment, signify that a company is creating low cost and high valued goods and services for consumers, which is economically efficient. Low profits signify the opposite. However, before a firm can create efficiency, it has to have sound management, and one way to do this is to make sure that the firm’s managers’ interests properly align with the firm’s owners’ interests, even if that owner happens to be the state. This is called the principal–agent problem. The literature on the principal–agent problem such as Arrow (1970) emphasizes that the principal (the owner) and the agent (the manager) have asymmetric information, where the manager knows more than the owners and uses that information for his own best interest, which may be contrary to the best interest of the owners. Alternatively, a more compelling principal–agent problem is that investors tend to have a different appetite for risk-taking than do managers, where the more risks a firm takes, the more reward or value a firm can obtain, assuming the firm doesn’t take irresponsible risks. Indeed, taking risks is a vital ingredient for starting a company, for expanding an existing company and, as we shall see, for exploring for oil. In financial portfolio theory, Markowitz (1959) shows a risk/reward possibilities frontier where investors can choose between less risky bonds, with a low return, and more risky equities, with a high return or some combination of the two. The original Markowitz curve represented an efficient risk/reward frontier between bonds and equities, called the efficiency frontier in finance, but what is called an iso-capital constraint in economics. Figure 4.1 Curve 1 shows an iso-capital constraint that relates oil production to oil exploration risk. The curve presents an investor with all of the available exploration opportunities given his fixed financial capital, whereupon the investor must choose his maximum return based on his preference for safety. Figure 4.1, Curve 1 shows how investment capital can be used either to invest in relatively safe intensive oil exploration, that is, adding wells to an existing oilfield, or to invest in relatively risky extensive oil exploration, that is, drilling wells in new, previously unexplored, greenfield regions (see Ramsey 1980). Intensive exploration usually has good probabilities of success with less environmental problems, but where each new drilling spawns a lower oil yield per well, which means it has higher costs per barrel and less output per investment dollar. The risk of exploring extensively, or wildcatting as it is called in the industry, includes such things as finding dry holes and losing money due to environmental regulatory delays, all of which create risk and a high standard deviation of return. For example, Shell Oil Company’s ill-fated

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106   Handbook of energy politics

Expected Rate Of Oil Production

Risk taking oil explorer with high production rate at maximum utility Risk averse explorer with low production rate at maximum utility

2.

A

3.

B

Iso-Capital Constraint

1.

Low Exploration Risk: Safe, Intensive Exploration

Risk High Exploration Risk: Risky, Extensive Exploration

1.Typical Oil Exploration Iso-Capital Constraint Curve 2. Iso-Utility Curve for a More Risk Averse Manager 3. Iso-Utility Curve for a Less Risk Averse Manager

Figure 4.1  Utility maximization with an iso-capital constraint. The equilibrium of a risk averse and a less risk averse oil explorer Chukchi Sea offshore oil exploration project off of Alaska’s northern shore in the 2010s was just such a risky endeavor. The Arctic offshore region has potentially 50 billion barrels of oil, and yet even though Shell spent billions on the exploration, notwithstanding environmental delays and costly accidents, they found nothing commercially producible. Nevertheless, that is the risk you take in order to earn a high rate of return. The more extensive, and risky, the oil exploration is that you engage in, the greater is your oil production reward, but where risk-taking encounters the law of diminishing returns. Curve 1, then, represents the idea that the more risk you take, the better your return, but also, as Ramsey (1981) shows, the higher is your chance of ruin, which is why the iso-capital constraint is concave. On the investor side of the risk/reward relationship, there is an entirely different curve shape as investors are usually risk averse as explained in Newendorp and Schuyler (2000). This is shown in Figure 4.1, Curves 2 and 3, which show two separate investors with two separate risk dispositions. The curves are convex because investors usually must be rewarded

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Institutions and the supply of oil  ­107 with ever-higher rates of return, or alternatively with more oil, in order to undertake more risk. The points of confluence between the investors’ highest obtainable preferences and the capital constraint determine each investor’s taste for risk. Curve 2 shows a relatively more risk averse ­investor who maximizes his risk-reward utility at the intersection of the iso-capital constraint at point A. Curve 3 shows the equilibrium for a relatively more risk loving, less risk averse investor at point B, who is appropriately rewarded with a higher level of oil production. Investor A prefers less risk, but then is relegated to a low level of oil production. Interestingly, managers of companies tend to have a preference for Curve 2, while investors in companies tend to prefer being at Curve 3. This is because investors can diversify their risk using mutual funds while managers cannot diversify their risk, as they can work only at one firm. Therefore, Figure 4.1 brings up another interesting aspect of the principal–agent problem: managers and owners have differences in their preference for risk-taking.

III  THE RISKY SHIFT HYPOTHESIS According to neoclassical economics, each person’s risk-taking utility function, such as Curves 2 and 3 in Figure 4.1, do not change under normal circumstances. However, Stoner (1961, 1968) suggests an alternative theory where a single person’s risk/reward utility curve can change due to something called the Risky Shift Hypothesis. The term “risky shift,” or alternatively “cautious shift,” explains how one person can have two different risk/reward utility curves depending on exogenous factors, such as political, psychological or sociological effects, as Frey (1997) shows. For example, Kogan and Wallach (1964), and Wallach et al. (1962) observe that individuals in a mob become more unruly than they would normally be, such that a person’s normal risk-taking level changes under those different circumstances. Indeed, changes in risk preferences can explain things like revolutions, asset price bubbles and financial panics. In business terms, March and Shapira (1987) and Hirschleifer and Suh (1991) show that managers often shift their risk-taking to lower, or higher, levels in different situations. A manager’s behavior regarding risk is affected by the environment under which he/she acts, one aspect of which being that the manager has to decide upon risk for other people’s loss or gain, such as his/her workers, and which normally makes him/her more risk averse. This is why in contrast to large, “stodgy,” risk-averse firms, small “dynamic” firms with owner-operators take more risk and, according to Helfand et al. (2007), show more job creation, because the ­owner-operator

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108   Handbook of energy politics gets to keep all the profit he/she creates. Interestingly, Reynolds et al. (2009) and Charness and Jackson (2007) show how Stoner’s Risky Shift Hypothesis works in game experiments where people will take more risk for their own gain or loss, but will take less risk if they have to choose the gain or loss for others. The Risky Shift Hypothesis, then, can explain why if a CEO is given a flat salary, but lots of responsibility, he/she simply tries to keep the company safe from any catastrophic failure for himself/herself, his/her workers and even his/her primary investors. He/she tends toward equilibrium A in Figure 4.1, even though that reduces the chance for new profit streams. This, then, brings up another factor of the principal–agent dilemma, which is that most corporate managers like to be at point A of Figure 4.1, whereas most investors want the manager to be at point B of Figure 4.1. That is, investors are already diversified, so they want to create a risky shift of the manager’s risk preferences in order to increase their returns. The key, then, to having the manager take appropriate risks that benefit the firm’s investors is to give the manager a certain amount of the reward, which both he/she and the owners will capture. In free market economies, one way to align these interests is by giving stock options to corporate managers so that if the manager makes more, or less, money for the stockholders, then the managers’ pay is reflected in the company’s stock price value that the stock owners receive. Using stock options, the manager is rewarded for taking more risk which in turn rewards the firm’s owners. In business theory, this is called changing the culture of the business, but this kind of change, or lack of change, can also happen due to an entire country’s oil and gas institutions.

IV  ECONOMIC INSTITUTIONAL SYSTEMS Macroeconomic theory suggests that there are two extreme economic systems: the pure market economy and the pure totalitarian, command and control, planned economy. The market economy is characterized by free markets with privately owned firms competing with each other to make profits. The command and control economy is characterized by a government-controlled system where all economic entities and decisions are driven by socialist directives and planning. A third possibility is a mixed system. A mixed system has elements of both planned and free markets such as China’s communist system, which has a lot of communist planning directives and government-owned enterprises, but which also allows firms to compete with each other on relatively free, competitive markets. Alternatively, America’s mostly free market system has substan-

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Institutions and the supply of oil  ­109 tial government regulations, planning directives and permitting requirements. For example, America curves its brute capitalism with antitrust, banking and financial regulations and it has a government-owned central bank. In terms of an oil producing country, the same kind of economic extremes exist. On the one extreme, representing a free market ideal, would be an oil producing region with many privately owned, independent oil companies competing for the right to buy petroleum leases. The mineral leases would be sold by competing private landowners. On the other extreme, representing a command and control ideal, would be a National Oil Company (NOC), which owns and controls all petroleum mineral rights and oil infrastructure within a country, which is set up as the only national entity allowed to explore for and develop oil, and which follows government dictated plans. However, just as in macroeconomics, there are, as well, many instances of mixed oil producer systems. One example of a mixed oil producer system is where independent, International Oil Companies (IOCs) are allowed to work with NOCs in specific regions or on specific projects, and where many IOCs compete for these projects. The NOC still owns and controls the oil rights, but the IOC does the exploration and receives a share of the profits. This creates an element of competition. Another example of a mixed system was in Texas in the 1950s and 1960s where the state government ran the Texas Railroad Commission (TRC), which regulated and limited oil well production levels in order to maintain stable oil prices. Even though Texas mineral rights and oil companies were all privately owned, nevertheless, the TRC controlled the amount of oil production allowed for each producing well, which means that Texas has had a mixed system. Indeed, there is no such thing as a 100 percent government planned and controlled oil sector nor a 100 percent free market oil sector. All oil governing systems are mixed systems. The only question is to what degree of control or to what degree of market freedom there is in any given region.

V NATIONAL OIL COMPANY PROJECT FINANCING Consider, then, how a mixed system might work when an oil producing country has an NOC, which owns all mineral rights and oil infrastructure within the country and operates all oil exploration and production activities. See Warshaw (2012) for more. At first glance, such an NOC will look like a great source of revenue for the country as the NOC will be able to reap 100 percent of the oilfield profits from existing oil wells and give those

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110   Handbook of energy politics profits to the people. However, upon closer inspection, one realizes that such an NOC may need to conduct new, greenfield oil exploration and development in order to increase the country’s oil revenues. This creates a dilemma. In order for the NOC to explore, develop and produce new oil, it needs financing, and assuming that the NOC already gives all of its profits to the national state, then the only way to finance a new project is to find a new source of funding such as the following: 1. The NOC can finance the new project by using retained earnings, for example, by keeping a portion of the profits that already go to the government. However, that implies the government will suddenly receive less revenue. If the government receives less revenue, then that implies that one or another government program will have to be cut, and that will be unpopular for the people of the country who are directly involved in the cuts. This may lead to the government not granting the NOC permission to retain additional earnings. 2. The government can raise taxes and use the additional tax revenue to give to the NOC in order to finance new oil projects. However, such a program of new taxes may be unpopular or will cause other economic sectors of the country to worsen, in which case, again, such a government program may not be instituted. 3. The government can engage in a joint venture or an oil profit sharing agreement (PSA) with an IOC. The IOC would finance the project, without any need of government money, but on the proviso that the IOC would then be rewarded with a portion of the profits if oil is found. Both sides win, except for the fact that future oil profits going to the country will be less than 100 percent. Therefore, even if an NOC gives an IOC an agreement to explore for new oil, the NOC still has to negotiate the level of retained profits for the IOC. If that profit level is considered too high, then the people of the country will lose substantial revenue from their new oil production and they will become resentful. If the NOC gives the IOC too little reward, then the IOC will not invest in new exploration and development. Therefore, negotiations with IOCs over profit sharing terms will be fraught with political risk. The real dilemma behind the financing is that oil and gas exploration involves taking risks, which means we need to understand risk averse and risk-taking behavior that the institutions induce.

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Institutions and the supply of oil  ­111

VI THE UTILITY DIFFERENCE BETWEEN IOCs AND NOCs When considering risk and how risk plays a role in the exploration and development of oil wells, we can use an alternative Markowitz (1952) curve using utility versus income. Utility is simply an economic concept for understanding how one feels about gains and losses where the disutility of losses are compared to utility of gains in relation to a person’s current income (see also Nolan and Therber 2012 and Reynolds 1999). Consider a country’s decision to invest in a new oil and gas project in Figure 4.2. According to this analysis, the country’s decision maker, who for all intents and purposes is the president or leader of the country, will have a subjective value or utility level as a function of his nations gains or losses in Gross Domestic Product (GDP). The Y-axis is the decision-maker’s utility. The X-axis is the level of national income, or GDP, for the country. The country starts at point I0, its initial endowment of yearly GDP, and Utility

Subjective utility of exploration: based on the expected outcome of two events

First possible outcome: low utility based on not finding oil and paying the cost of the investment

Region of risk aversion

Initial utility

Cost of investment

I1, U1

NOC manager’s theoretical cardinal utility curve as a function of national income

I2, U2 Second possible outcome: high utility based on oil discovery

U0 U3

Region of risk loving

Country monopoly weighted average utility curve for two separate events

Income Value gain of discovery Initial income of country

I0 I3

Expected change in income due to the subjective probability of success

Figure 4.2 Country monopoly risk utility curve for exploration of a potential new oilfield where the new field is not large relative to the size of the country GDP

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112   Handbook of energy politics the decision-maker is at point U0, which is his initial level of utility. The decision-maker has a choice, he can do nothing and keep the country at I0, with his utility level at U0, or he can choose to invest in a new oil exploration project. Assuming the NOC has to use funding options 1 or 2 above and the NOC finds no oil, then there is a loss of income to the country to point I1, due to the cost of exploration. In that case, there is a loss of utility to the decision-maker all the way to point U1. If exploration is successful, then there is a gain in income to the country and a gain in utility to the leader of the country to I2 and U2 respectively. According to Kahneman and Tversky (2002), the utility of a loss can be convex due to people having a high disutility of unplanned losses, that is, they are risk loving for losses once a project starts. In the case of an NOC, the decision maker experiences extreme utility loss for a failed investment because of the political flack he would endure. “Why did the government waste all this money on a failed attempt to find more oil?” The government would then be proclaimed to be inefficient and the leader would take all the heat. On the other hand, the exploration gamble may pay off. If a new oilfield is found, then the country may move from I0 to I2, a substantial increase in income for the country. However, the decision-maker does not necessarily gain much utility from the success of the project. The people will ask, “Why didn’t you find the oil earlier?” The new revenue will immediately be captured by the defense ministry, the education ministry or some economic development ministry, but not the NOC. Therefore, the decisionmaker in charge of making the decision to invest in the project will not gain anything, even though the country gains a lot! The decision-maker’s utility is only slightly better, it moves from U0 to U2, such that the change in his utility from the income gain is a concave curve. If we put in a probability of success associated with the project – that is, a point between the two outcomes that takes account of the expected chance of success – then even if the expected income change is a net positive change – that is, the country’s expected outcome is I3 – nevertheless, the expected utility for the county’s leader, U3, is lower for doing the project than for not doing the project. The minister in charge of the NOC loses a lot of utility if no oil is found, but gains very little utility if oil is found and therefore his inclination may be to do nothing and keep the status quo, even when there is a net expected gain to the country’s GDP. An alternative plan to finance a project is to have an IOC do it all. The IOC’s utility curve can look like Figure 4.3 based on Friedman and Savage’s (1948) utility under uncertainty, although using certainty equivalent theory, as Main (2002) shows, the Figure 4.3 curve should be a straight line or slightly concave. Nevertheless, the Figure 4.3 curve from I0

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Institutions and the supply of oil  ­113

Utility

Second Possible Outcome: High utility based on NPV gain due to finding oil with high profit

Expected Final Utility and Income: Based on the expected probability outcome of finding oil First Possible Outcome: Low utility based on NPV loss in income due to investing in new production, but not finding oil

I2, U2

Region of risk loving

U3

Region

U0

of risk aversion

Initial Utility and Income

I1, U1

NPV Gain if Investment Pays off

NPV Cost of Investment

0 Expected final income due to NPV of oil investment based on the probability of discovery

Income I3 I0

Initial Income of Firm

Figure 4.3 The classic Markowitz small firm risk utility curve for the development of an oilfield where the field is large relative to the size of the firm to I1 is based on the idea that the IOC can use risk sharing with small oil service companies and individual investors. This suggests that people can be risk averse to losses, i.e. the utility curve from I0 to I1 is concave as long as owners of the IOC are diversified in their investments, which is contrary to the Kahneman and Tversky (2002) utility of loss explained earlier. The utility curve from I0 to I2 is convex, suggesting that firms can be risk loving to gains, due to risk sharing, which sometimes happens with gold rushes. Small firms (mostly individuals) invest every cent they have into obtaining mining claims in the hope of striking it rich, even though their expected gain is negative, rather like a lottery, where there is the possibility of a huge pay-off relative to someone’s current income. The expected utility suggests the possibility that IOCs will take a chance on an investment even with an expected net loss in income. The point of Figures 4.2 and 4.3 is to show the difference between an NOC and an IOC. IOCs will tend to take risks, while NOCs will tend to refrain from taking risks because of the different utility curves they face. This is because the IOC investors get to keep much of their gains, while the NOC decision-maker does not get to keep any gains; that is, it all goes to the national government and other ministries. Clearly, though, the better

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114   Handbook of energy politics the terms of profit sharing agreements for IOCs, and the more stable the country is where the IOCs operate, the more the IOCs are willing to explore for oil.

VII  THE DISCOUNT VS. THE OPULENT STRATEGY We know that oil producing countries, including OPEC members, encounter risk aversion due to having NOC only operations. Yet, after 1970, most OPEC member governments began to change from largely IOC run oil production operations to more NOC run operations. Why? And why did it happen right around 1970? One reason could be that institutional change is a reaction to market shifts, rather than a cause of market shifts, such that as the costs and benefits of a particular institutional framework change so do institutions. Therefore, the oil producers were choosing to change their institutions based on business strategy. There are two general business strategies that corporate managers often use to make money: 1. The Discount Strategy and 2. The Opulent Strategy. The Discount Strategy is characterized by such stores as Walmart, whose goal is to achieve high sales volumes by keeping prices low in order to make money. The Opulent Strategy is characterized by such stores as Neiman Marcus, which is a high-end retailer that makes its profits by selling expensive items even if sales volumes are low. The quantity of sales is low, but the profit per item sold is high. Oil producers can also follow these two strategies, the only difference being that oil is traded internationally, and thus the price of oil is thrust upon them. Nevertheless, when the price of oil changes, a country can adapt to the changing price with either a Discount or an Opulent Strategy. For example, during high price oil eras, oil producing countries have tended to pursue the Opulent Strategy by for example nationalizing oil infrastructure, raising taxes and thereby increasing the government take on each barrel of oil. The country gets more profits per barrel, even though it reduces incentives for new exploration. Still, that Opulent Strategy can enhance that country’s revenue and can even raise the worldwide price of oil. Alternatively, during low price oil eras, oil producers tend to pursue a Discount Strategy by awarding lease concessions and lowering taxes and royalties for IOCs. The country receives less value per barrel, but incentivizes expanded production, which, eventually, increases its oil production and revenue. Thus, governments will tend to change their institutions as the market dictates. High oil price eras tend to induce Opulent Strategies with command and control institutions. Low oil price eras tend to induce a Discount Strategy with more free market institutions.

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Institutions and the supply of oil  ­115 You can even have the strategies switch automatically by, for example, having your taxes and oil policies change autonomously to whichever oil price era is occurring at the time. Therefore, similar to a central bank, the oil producer can either follow a “rule,” or follow “discretion” regarding its oil institutions. A rule is where taxes, royalties or profit shares change automatically depending on the price of oil, and discretion is where the government decides strategically on a case-by-case basis its taxes, royalties or ownership shares. Now consider OPEC’s history (see Reynolds 2011). Looking back, one wonders, why did OPEC production rise 10 percent per year from 1960 to 1970, but then rise only 1 percent per year from 1970 to 1980, even though the price of oil was much higher in the later decade than the former? One reason has to do with switching away from Discount (high volume) Strategies and toward Opulent (high profit per barrel) Strategies. Indeed, in the early years of OPEC, most OPEC members had Discount Strategies, such as joint ownership agreements with IOCs. The arrangements included the foreign company putting up one half or more of the capital costs for new projects but then being allowed to deduct the costs and receive a portion of the profits. However, in 1970 these arrangements started to change. The most likely reason, as new institutional economics might suggest, was due to a change in the market, which compelled a change in business strategy and thus a change in local institutions. Consider closely the oil market just at the beginning of the 1970s (see DeGolyer and MacNaughton 1979). First, an odd thing happened in 1969. From February to March, the West Texas Intermediate price of oil rose from $3.07 to $3.35, about a 9 percent price increase in only two months, which at the time was quite substantial since the price hadn’t ever deviated outside of the $2.90 to $3.07 range for over ten years! Second, all of the major oil exporting countries saw a 30 percent increase in their oil sales prices from 1970 to 1971 with continuing increases after that including the 1973 oil price shock (DeGolyer and MacNaughton 1979). After those initial price rises, institutional changes started occurring across the petroleum-producing world: the Discount Strategy was out and the Opulent Strategy was in. In September of 1970, Libya raised the tax on oil from 50 to 55 percent (Iran and Kuwait followed with their tax increases in November). In January 1971, right after the December 1970 price increases, six oil producing countries and 22 international oil companies met in Tehran, where the OPEC governments said that they would deny any company access to their oil if it didn’t pay the 55 percent tax (the agreement was signed in February). Then on February 24, Algeria nationalized 51 percent of French oil concessions. In April 1971, Libya concluded five weeks of

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116   Handbook of energy politics negotiations with Western oil companies in Tripoli on behalf of itself, Saudi Arabia, Algeria and Iraq. The final agreement raised tax rates from a range of 50–58 percent to 60 percent of posted price. Also in December 1971, Libya nationalized its BP concession. Still, prices continued to rise, so in January 1972, the United Arab Emirates, Iran, Iraq, Kuwait, Qatar and Saudi Arabia concluded ten days of meetings with international oil companies. An agreement was reached to raise the posted price of crude oil by 8.49 percent to offset the loss in value of oil concessions due to the depreciation of the U.S. dollar. Right after this in 1972, Iraq nationalized the Iraq Petroleum Company taking away all assets owned by BP, Royal Dutch Shell, Compagnie Française des Petroles, Mobil and Standard Oil of New Jersey. Also in 1972, OPEC countries supported the Iraqi decision by preventing oil companies whose assets were nationalized in Iraq from expanding their involvement elsewhere. In October 1972, OPEC mandated that all Western oil operations within Kuwait, Qatar, Saudi Arabia and the UAE should have at least a 25 percent government ownership stake, with that government stake rising to 51 percent in 1983. In 1973, with another 100 percent increase in international prices, Iran replaced its equity sharing agreements (a type of PSA) with service contracts, a de facto nationalization even though on paper Iran already had nationalized its oil back in 1951. Now oil companies in Iran had to risk exploration and development with no way to deduct costs if they didn’t find oil. If they did find oil, they could only deduct the cost of the oil that they found, a clear Opulent Strategy for Iran. Also in 1974 after another 100 percent price shock, Saudi Arabia took controlling interest in Aramco. Then in 1980, after the second major oil price shock, Saudi Arabia took 100 percent of Aramco retroactive to 1976. Kuwait also nationalized its oil operations in 1976. Russia, too, followed this strategy as oil prices rose in the early 2000s (Reynolds and Kolodziej 2008). Other oil producing countries and provinces that went from relatively competitive Discount Strategies to relatively less competitive, high tax, Opulent Strategies, were Alaska, USA; Alberta, Canada; the North Sea, UK; and as we shall see Venezuela.

VIII  THE VENEZUELAN OIL HISTORY CASE STUDY To see how countries switch between Opulent and Discount Strategies, one need look no further than Venezuela (see Hults 2012). Venezuela was an original member of OPEC and has exhibited a large variation in its oil production levels compared to its average production output over the

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Institutions and the supply of oil  ­117 last four decades. What is interesting about Venezuela is that the variation in its output seems to go counter cyclical to the price of oil which is counter-intuitive to conventional economic supply theory; that is, unless this counter cyclical reaction is an indication of Venezuela’s institutional changes and market strategy at work. What we would like to do then is to observe if Venezuela looks to exhibit any risk averse behavior and, more importantly, if oil prices are affecting the Venezuelan institutional framework, which is in turn affecting its oil production. Considering Venezuela’s oil history, it is clear that important institutional changes took place at exactly the points in time when oil prices changed, and that the institutional changes created new production trends. When Venezuela put in place an Opulent Strategy, they got more profit per barrel of oil, but there was more risk aversion to expanding production and so production declined. However, when Venezuela changed tactics and put in place a Discount Strategy, oil production improved dramatically, although, Venezuela received less profit per barrel. First, consider Venezuela’s early oil production history. As Figure 4.4 shows, Venezuelan oil production was surging 16 percent per year from 1920 to 1970, although with some fits and starts, and this was mostly when IOCs were working inside its borders and when oil prices were low. However, production started declining in 1971 right when Venezuela’s hydrocarbon law was changed. In July 1971, although with debate occurring for a year or more prior to that time, Venezuela’s hydrocarbon reversion law mandated the transfer to government ownership of all “unexploited concession area” by 1974 and “all their residual assets” by 1983 (Esco-Interamerica Company 1971). One reason for this change was undoubtedly the significant increase in oil prices in 1970 that induced an Opulent Strategy. What was undoubtedly happening was that having the hydrocarbon reversion law in place gave a huge signal to IOCs that they were going to lose their investment capital to nationalization and that at the very least they should halt any new investments. Soon thereafter, Venezuelan production started to decline. Later, in August of 1975 after the big oil price shocks of 1973 and 1974, the Venezuelan congress enacted a true nationalization law that created Petroleos de Venezuela (PDVSA) and limited all activities related to the oil industry to the public sector and rendered all previous concessions to IOCs null and void. Therefore, starting in 1971, and even before that owing to the year-long debate, one reason for Venezuela’s production decline was that there was a slow momentum towards the nationalization of oil and gas assets. The result was an increase in risk aversion. The PDVSA could have increased production as the IOCs had done, but due to the change in risk-taking behavior, the

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118

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Oil Production (Millions Bbls/day)

0

10000

30000

High or Increasing Oil Price 40000

50000

PSAs 1990 to 1998

1999 PSAs stopped

60000

High or Increasing Oil Price

Cumulative Production (Millions of Barrels)

20000

Real WTI Price of Oil (1971-1973 international estimated prices)

1975 Nationalization

1971 Hydrocarbon Reversion Law

Daily Production of Oil

Figure 4.4  Venezuelan oil production versus cumulative production

0

0.5

1

1.5

2

2.5

3

3.5

4

0.00 70000

5.00

10.00

15.00

20.00

25.00

30.00

35.00

40.00

Real Price of Oil (1983 $/Bbl WTI)

Institutions and the supply of oil  ­119 PDSVA couldn’t raise production. Therefore, it appears as if institutional changes caused the production decline of the 1970s, although this was economically efficient. Again, recall that international oil prices rose 30 percent from 1970 to 1971 – a huge increase in prices when you consider that international oil prices had not changed much at all for almost two decades prior to that change. Yet that 30 percent oil price increase reminds one of the U.S. NASDAQ stock price index increasing by 340 percent in the last three years of the 1990s. The NASDAQ spike amounted to a 50 percent equity surge per year, which induced a wild frenzy of stock buying by smalltime investors in the U.S., so one can only imagine a similar excitement for Venezuela’s oil revenues and the desire to capture those increasing revenues. After the downward oil price shock of 1986, and with no clear ability by OPEC to keep oil prices high, Venezuela changed strategies and reinstituted a Discount Strategy. The new policy was developed in 1989 and implemented in the 1990s, where Venezuela opened up its oilfields to IOCs through the use of PSAs which induced new oil exploration. Clearly risk-taking increased. The more attractive PSA oil concession caused oil production to expand by about a 4 percent per year. The PSAs gave the oil companies a profit incentive enough to create competitive bidding for the oil concessions and in turn create greater investment in exploration and more supply. Again, the question is: why could not Petroleos de Venezuela have unilaterally expanded its production without PSAs or without IOCs? If you are going to expand capacity, then just do it yourself. The logical conclusion is that an NOC is highly risk averse and cannot increase production very easily, similar to Figure 4.2, whereas competitive IOCs, with a more risk loving attitude, can expand production, similar to Figure 4.3. Venezuela changed its institutions again after the 1998 presidential election of Hugo Chávez. Right after Chávez’ election, he halted new agreements to expand exploration and production and renegotiated many previous agreements. He also cut production in an effort to help OPEC raise oil prices that had become quite low in that year. So, clearly the government of Venezuela became much more interventionist with a new command and control policy which led to the 2002 oil strike by PDVSA workers. Since 2000, Venezuelan oil production has declined by over 2 percent per year due to Venezuela pursuing an Opulent Strategy. Also, according to Reynolds and Pippenger (2010), it appears that Venezuela was not following OPEC quotas, but rather that OPEC quotas were following Venezuelan oil production levels.

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120   Handbook of energy politics

IX  CONCLUSION Oil producing countries face risk in order to find and extract oil. The level of risk-taking, though, can be made higher or lower depending on the institutional framework of the country. Two extreme institutional frameworks are possible: 1. a command and control system, used in regard to the Opulent Strategy, or 2. a free market system, used in regard to the Discount Strategy. Most countries have a mixed oil market system with elements of both command and control and free markets. However, as oil prices change, countries tend to change their institutions relative to the price toward either one or the other strategy extreme. During high oil price eras, countries tend toward an oil market, command and control, Opulent Strategy using an NOC. During low oil price eras, countries tend towards a more free market, Discount Strategy where IOCs work in tandem with the NOC. This price-induced shift of institutions is only one factor that leads to either a higher or lower production, other factors, such as politics, geology and technology, undoubtedly also play a role. Nevertheless, to argue that either Venezuela or the U.S. has the more efficient oil industry is difficult to substantiate. Efficiency has to take into consideration the size of the oil industry in comparison to other industries within a country. In the U.S., where there are many different industrial sectors, the oil industry may be more efficient to U.S. citizens under a Discount Strategy. In Venezuela, where its oil industry is so dominant, the country’s citizens may gain more economic efficiency under an Opulent Strategy with command and control institutions. What we would expect, then, is that as oil prices rise and fall, institutions within oil producing countries also will ebb and flow, which in turn can exasperate market volatility. High oil price eras will induce Opulent Strategies to dominate causing oil supplies to decline and prices to increase further still. Low oil price eras will induce Discount Strategies to dominate causing oil supplies to increase and oil prices to go down even lower. This means the oil market is likely to be highly volatile in the future due to scarcity, the lack of oil-supply expansion capacity and market reinforcing institutional changes. For example, U.S. shale oil production accounts for only 5 percent of world supplies while conventional oil accounts for over 90 percent. Furthermore, oil shale includes a lot of light carbon, natural gas liquids such as propane, butane and pentene, which are less valuable to the world’s economy. Plus, a number of conventional oilfields are set to decline as Hallock et al. (2014) and Reynolds (2014) show, which suggests that there will not be enough heavy carbon shale oil to overcome conventional oil scarcity. In that case, if supplies become low and oil prices become high, then many oil producers will begin to opt for

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Institutions and the supply of oil  ­121 Opulent Strategies and cause even lower oil supplies with higher prices. Alternatively, if oil demand is low and oil prices are low, then many oil producers will opt for Discount Strategies which can lower oil prices even further. Finally, if oil prices change rapidly from low to high, the strategies could change rapidly and induce extremely volatile oil markets with turbulent effects on the world’s economies and political affairs.

References Acemoglu, D. and S. Johnson (2005) “Unbundling institutions,” Journal of Political Economy, 113 (5), 949–95. Acemoglu, D., S. Johnson and J. Robinson (2001) “The colonial origins of comparative development: An empirical investigation,” The American Economic Review, 95 (5), 1369–401. Arrow, K.J. (1970) Essays in the Theory of Risk-Bearing, Chicago: University of Chicago Press. Banerjee, A. (2002) “Theses of economic theory: Against a purely positive interpretation of theoretical results,” BREAD working paper no 7, MIT, Bureau for Research in Economic Analysis of Development: Cambridge, MA. Banerjee, A. and M. Ghatak, (2005) “Symposium on institutions and economic performance, introduction,” Economics of Transition, 13 (3), 421–5. Charness, G. and M.O. Jackson (2007) “The role of responsibility in strategic risk-taking,” Working paper, UC Santa Barbara and California Institute of Technology. Coase, R. (1937) “The nature of the firm,” Economica, 4 (16), 386–405. Commons, J.R. (1931) “Institutional economics,” The American Economic Review, 21 (4) (December), 648–57. DeGolyer, E.I. and L.W. MacNaughton (1979) Twentieth Century Petroleum Statistics, Dallas TX: DeGolyer and MacNaughton. Diamond, J. (1997) Guns, Germs, and Steel: The Fates of Human Societies, New York: W.W. Norton & Company. Esco-Interamerica Company (1971) “Venezuela: Hydrocarbons reversion law,” International Legal Materials, 10 (5) (September), 1073–81. Frey, B.S. (1997) Not Just for the Money: An Economic Theory of Personal Motivation, Cheltenham, UK and Northampton, MA, USA: Edward Elgar Publishing. Friedman, M. and L. Savage (1948) “The utility analysis of choices involving risk,” Journal of Political Economy, August, 56. Gleaser, E. and A. Shleifer (2004) “Legal origins,” Quarterly Journal of Economics, 117 (4), 1193–229. Hallock Jr., J.L., P.J. Tharakan, W. Wei, C.A.S. Hall, M. Jefferson, (2014) “Forecasting the limits to the availability and diversity of global conventional oil supply: Validation,” Energy, 64, 130–53. Helfand, J., A. Sadeghi and D. Talon (2007) “Employment dynamics: Small and large firms over the business cycle,” Monthly Labor Review, March 2007, U.S. Bureau of Labor Statistics. Hirschleifer, D. and Y. Suh (1991) “Risk managerial effort and project choice,” Journal of Financial Intermediation, 2, 308–45. Hults, D.R. (2012) “Petroleos de Venezuela, S.A. (PDVSA): from independence to subservience,” in D.G. Victor, D.R. Hults and M.C. Thurber (eds) Oil and Governance: StateOwned Enterprises and the World Energy Supply, Cambridge: Cambridge University Press. Kahneman, D. and A. Tversky (2002) Choices, Values, and Frames, Cambridge: Cambridge University Press.

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122   Handbook of energy politics Kogan, N. and M.A. Wallach (1964) Risk-Taking: A Study in Cognition and Personality, New York: Holt, Rinehart and Winston. Main, M.A. (2002) Project Economics and Decision Analysis: Volume II Probabilistic Models, Tulsa, Oklahoma: PennWell. March, J.G. and Z. Shapira (1987) “Managerial perspectives on risk and risk-taking,” Management Science, 11 (11), 1404–18. Markowitz, H. (1952) “The utility of wealth,” Journal of Political Economy, 60, 151–8. Markowitz, H.M. (1959) Portfolio Selection: Efficient Diversification of Investments, New York: John Wiley & Sons (reprinted by Yale University Press, 1970). Newendorp, P.D. and J.R. Schuyler (2000) Decision Analysis for Petroleum Exploration, 2nd edition, Planning Press. Nolan, P.A. and M.C. Therber (2012) “On the states choice of oil company: Risk management and the frontier of the petroleum industry,” in D.G. Victor, D.R. Hults and M.C. Thurber (eds) Oil and Governance: State-Owned Enterprises and the World Energy Supply, Cambridge: Cambridge University Press. North, D.C. (1981) Structure and Change in Economic History, New York: W.W. Norton & Company. Ramsey, J.B. (1980) Bidding and Oil Leases (Contemporary Studies in Economic & Financial Analysis), Greenwich, CT: JAI Press. Ramsey, J.B. (ed.) (1981) The Economics of Exploration for Energy Resources, Greenwich, CT: JAI Press. Reynolds, D.B. (1999). “Modeling OPEC behavior: theories of risk aversion for oil producer decisions,” Energy Policy, 27, pp. 901–12. Reynolds, D.B. (2011) “What is OPEC? It is Saudi Arabia,” in OPEC at 50: Its Past, Present and Future in a Carbon-constrained World, March, 2011, conference proceedings, National Energy Policy Institute, University of Tulsa. Reynolds, D.B. (2014) “World oil production trend: Comparing Hubbert multi-cycle curves,” Ecological Economics, 98, 62–71. Reynolds, D.B., J. Joseph and R. Sherwood (2009) “Risky Shift versus Cautious Shift: Determining differences in risk-taking between private and public management decisionmaking,” Journal of Business & Economics Research, 7 (1), 63–77. Reynolds, D.B. and M.K. Pippenger (2010) “OPEC and Venezuelan oil production: Evidence against a cartel hypothesis,” Energy Policy, 38, 6045–55. Reynolds, D.B. and M. Kolodziej (2008) “Former Soviet Union oil production and GDP decline – Granger Causality and the Multi-Cycle Hubbert Curve,” Energy Economics, 30, 271–89. Stoner, J.A.F. (1961) A comparison of individual and group decisions involving risk, Unpublished Master’s Thesis, Massachusetts Institute of Technology. Stoner, J.A.F. (1968) “Risky and cautious shifts in group decisions: the influence of widely held values,” Journal of Experimental Psychology, 4, 442–59. Wallach, M.A., N. Kogan and D.J. Bem (1962) “Group influence on individual risk-taking,” Journal of Abnormal and Social Psychology, 65, 77–86. Warshaw, C. (2012) “The political economy of expropriation and privatization in the oil sector,” in D.G. Victor, D.R. Hults and M.C. Thurber (eds) Oil and Governance: StateOwned Enterprises and the World Energy Supply, Cambridge: Cambridge University Press. Williamson, O.E. (1985) The Economic Institutions of Capitalism, New York: The Free Press.

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5.  Low oil prices impact on Latin American non-conventionals Alberto Cisneros Lavaller

INTRODUCTION On a crisis situation like the one oil prices confront currently, it is significant to begin with a thorough analysis to understand: 1. the crisis dimension, as well as 2. its impact amidst some other similar international oil market crunches that have taken place in the past. In reviewing those critical situations through a longitudinal analysis, it is possible to historically identify three previous oil price downfalls during the last 30 years. The first one took place from 1983 to 1990. The second one started by late 1997/early 1998 and the third one burst in 2009.

THE FIRST PRICE CRISIS: OPEC ON HER OWN The first oil price crisis during contemporary times erupted in early 1983, due among other factors, to a huge build-up of stocks during 1982. In a relatively short span (eight months), prices plunge from $ 30/b (November 1983) 160 140

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Figure 5.1  Oil prices: downturns compared 123

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Figure 5.2  Oil prices: downturns compared down to $ 12/b by July 1984. That meant a two-thirds downfall equivalent to almost $ 20/b drop. OPEC at that time decided unilaterally on a strategy to prop up prices (Price Defense). That was to support prices through significant production cuts implementing quotas. Within that international oil market environment, the role of the organization was that of a swing producer and within it, Saudi Arabia was the swinger of ultimate resort. As a consequence, in the summer of 1986 Saudi production fell just above 2 Mb/d from a peak production of 10Mb/d in 1980 during the Iranian crisis (hostages taken by Ayatollah’s followers at Tehran American Embassy). Price Defense Strategy articulated by OPEC on its own proved to be successful but in the long run. The organization lost so much market share at expense of non-OPEC producers that OPEC by early 1987 had to reverse her strategy to one of market share recouping. The end result was prices going down as a consequence of incremental production in a seller’s market. Thus, consequential to all those deeds, oil prices took almost five years to recover (see Figure 5.2 above – black line – comparing the first two crises) reaching $ 33/b by September 1990.

THE SECOND PRICE CRISIS: ALL ACTORS CONVERGING The second price crisis was consequence of Asian markets financial crash by late 1997. Prices dwindled at that time by 50 percent. They fell from

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Low oil prices impact on Latin American non-conventionals  ­125 $ 21/b to $ 11/b in 15 months; a net fall of $ 10/b. The market response was completely different at that time. OPEC initiated a consultation initiative leaded by Saudi Arabia and Venezuela to converge the efforts with non-OPEC producers as well (Mexico at that time) to reduce production in a coordinated effort from all the world’s most conspicuous actors. As a consequence, the accords reached among those three aforementioned producers (“The Troika”) were acted upon and confirmed by OPEC and all other suppliers. That strategy of production cuts implemented within the organization through Production Ceiling Accords differed from quotas that were implanted by OPEC alone during the first crisis. The reason they are not quotas is because Venezuela’s thesis within OPEC was successful in the sense that production cuts have to be done from “actual” production (February 1998) and not from quotas established in Jakarta (November 1997). As a consequence, the concerted action of almost all market producers bears fruit and prices recovered quickly and in less than a year reached $ 21/b by August 1999 (as shown in Figure 5.2 – the dotted line).

THE THIRD PRICE CRISIS: MARKET FORCES The third of the most contemporary price crises took place in 2008 when the bubble of North American house mortgages broke up. Although this seems to be the necessary cause nobody mentions another reason  (­“sufficient cause”): oil prices skyrocketing; a trend that  ­afterwards ­experienced an amazing fall. From June 2008 when prices were at $ 134/b (daily price was even higher – ours is a monthly quote) they fell down to $ 39/b by February 2009. That is twothirds downfall in eight months equivalent to a loss of $ 95 in that time span. Key international oil players did not do much about it under the circumstances. They allowed market forces to play out and rescue the crisis. Consequently, prices took almost two years to recover, reaching $ 110/b by end of first quarter 2011. This can be seen in Figure 5.3.

THE PRESENT CRISIS Recently, oil price behavior seems to have been developing in two tiers. The first one was a strenuous fall; the other tier instead seems to be in search for a price floor. Reviewing analytically each one of those patterns, we could describe them as follows:

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Figure 5.3  Oil prices: downturns compared ●

From mid-2014 when prices reached a mark of $ 105/b, its behavior went down to $ 40/b by March 2015. That is $ 65 loss in absolute terms (equivalent to a 55 percent downfall) in nine months. ● While in-depth analyzing last year price behavior and the first quarter of 2016 we could identify that during the first semester of 2015 prices were attempting to shore up at $ 50/b (with a mean of $ 53/b). In the second semester of 2015 and beginning of 2016, price behaviour is still searching for a floor; at lower level, though: lower indeed (at about $ 30/b) but nevertheless a floor. The mean for the last semester has reached $ 43/b. Thus, it seems that oil price behavior is searching for some type of floor but this still remains to be seen. Figure 5.4 shows the most recent behavior for oil prices. There are many positive signs from the demand as well as from the supply side that could be briefly mentioned. However, our analysis is far from traditional and intends to incorporate a creative and innovative methodology to give some ideas on how and approximately by when prices could recoup themselves. Among those (traditional) factors with positive signs from the demand side are: US economic recovery and lower unemployment; economic growth with relative decline of China counterbalanced by a higher growth in India; and Europe and Japan with a recovery growth. All these seem to point to an incremental world demand for 2016 similar to “her Historical trend” that is about 1.2 Mb/d. While that is the case for main consumers,

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Low oil prices impact on Latin American non-conventionals  ­127 65 60 55

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Figure 5.4  Prices searching for a floor: zooming up (2015–16) on the producers’ side Saudi output seems to be cornered at a similar level of current production (shy of 10 Mb/d); Russia and the USA exhibit some decline while Iran is still pending after the lifting of sanctions that could not be implemented immediately but gradually (recall that this country has not experienced new exploratory efforts in the last 35 years). Finally, Iraq with her ISIS threat ameliorating her production revamp. Given those economic fundamentals for the international oil industry, we assessed that oil prices are searching for a floor (price).

WHAT THE FUTURE MAY LOOK LIKE Several methodologies are used in an attempt to forecast price behavior. Nevertheless, this analysis shies away from traditional techniques. It intends to foster a non-deterministic approach based on historical behavior. That is labeled “post-dictions” – meaning that future behavior could be rooted in the past. Under those assumptions then, has been envisioned for the outcome of present crisis three different “scenarios” depending it takes similar paths to those of previous crises. That is: 1. OPEC adopting a Price Defense Strategy (cutting production alone) and then articulating a Market Share Strategy due to production losing ground at the expense of non-OPEC producers, 2. a situation where after concerted action All Producers Cut and 3. market forces “operate” by themselves. If Situation 1 (OPEC CUTS ALONE) unfolds it is quite likely that price recovery would take a long path; let’s say five years to recoup. If situation 2 (ALL PRODUCERS CUT) plays out then a fast recovery is possible in about a year to 18 months. And finally, if the prevailing ­situation

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140 120 $/B

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Figure 5.5  Oil prices: recovery situations resembles that of three (MARKET FORCES) then one can expect prices to recover in approximately two years. As can be seen in Figure 5.5, our model is non-deterministic because it offers ranges for that price recovery (similar to price bands) instead of giving a specific figure for a given time in the future.

IMPACT ON LATIN AMERICAN NONCONVENTIONAL OIL DEVELOPMENTS Within that global oil environment, it is worth analyzing how these trends may impact the development of non-conventional oil developments in Latin America. For the purpose of this chapter we apply the concept of non-conventional to all those oil developments in the region which require harder efforts for exploring or producing oil than traditional and conventional ways. Thus, four cases stand out: Deep waters in the Gulf of Mexico; extra heavy oils in Orinoco (Venezuela); pre-salt in deep waters of Brazil and shale oil in Argentina. One of the most promising but difficult plays that Mexico currently has to tackle in order to cope with the depletion of Cantarell Field (one of the reasons for its steep production decline), is to explore (and produce) from the deep waters of the Mexican Gulf. Reaching those reservoirs is not an easy task; they have to go through a huge column of water from 1500 up to 7500 ft deep. Therefore, this entails a high cost operation that could require around $ 40/b to profitably develop those reservoirs. Technically, if these projects do not see her viability affected by the current low price

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Low oil prices impact on Latin American non-conventionals  ­129 trend, they certainly would impact their profitability. Thus, these projects could possibly become the most expensive of the whole portfolio that Mexico has to offer.1 Relatively successful R 1.4 round Mexican bidding (R 1.4 related to Gulf deep waters) would let us know how successful or deserted the opening up for those areas is. Venezuela bases its oil recovery on the incremental production from the Orinoco Oil Belt. This area “treasures” the heaviest oil in the world (from 8 to 11 degree API) which requires complex extraction technologies. However, many of those technologies have been already successfully developed; they are in the public domain and are not as costly as others needed to develop non-conventionals in the rest of Latin America. At the official level is argued that these plays would require a price of about $13/b. We tend to believe that is relatively more costly, possibly in a band stretching from $ 15 to $ 20/b. Current international price floor seems not to have negative impact on these oil developments, but could distress new investments because they are not going to get large profits if price remains low for the mid to long run. Moreover, the problem Venezuela confronts is political rather than industrial. The lack of due process of law, clear rules of the game for investors and the state oil company going back and forth on their negotiating deals with minority foreign partners (“Equity Control Companies” or “Companias Mixtas” whereas PDVSA is the controlling shareholder) is the model ruling the country nowadays. The pre-salt is a deep waters area that Brazil intends to develop. It comprises Espiritu Santo, Campos and Santos Basins. The reservoir could involve about 25 Mb of reserves which is close to the double conventional reserves the country currently has.2 The technologies for the extraction of this oil encompass several challenges: to cope with a 6000 to 8000 ft column of water and then go deeper (about 6000 ft) to reach the reservoir. Petrobras, the state oil company, has a record of this type of technology and offshore platform. Certainly, this is a very high cost operation, valued at $ 90/b. Petrobras officers have assessed that pre-salt would require merely $ 40/b to develop. According to our own research intelligence,3 it seems that would require at least $ 70/b on average to become profitable when royalties and so on are included. Dwindling oil prices force to delay these projects. This is due to reassessment of cost and profitability. However, some early production is happening because Petrobras invested some time ago when prices were at a much higher level. Finally, Argentina, within this quick overview of lower price impacts on Latin America, intends to develop shale oil (and gas) in Vaca Muerta (Neuquén Province). The importance of these developments stems from

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130   Handbook of energy politics the fact that Argentina is home to the second largest shale gas reservoir in the world (802 TCF) after China, and the largest in Latin America (followed by Mexico and Brazil). The technology to develop these reservoirs is relatively high cost. According to studies and forecasts (YPF – state oil company – and others)4 production originally required about $ 75/b on average to become profitable. Thus, given prices downfall, at first sight, these projects seem unviable, experiencing delays due to reassessment of cost and profitability. However, due to previous investments made by YPF, early shale production is coming in on stream from Neuquén Province. Moreover, the Argentine government has a put a floor to domestic oil markers Escalante and Medanito with a price of $ 60 and $ 55/b, respectively. This subsidy encourages all producers in the country to sell their production domestically instead of exporting it abroad. Local prices entail better prices than at international level. As a consequence, and due to cost reductions, shale production has been trimmed down, currently requiring about $ 60/b and therefore prices are no longer an obstacle to production in Argentina. This seems an ingenious policy that is helping out production in a time of crisis. It remains to be seen when the subsidy burden shared by government, producers and final consumers will end, making the system fragile.

MORALS BY WAY OF AN EPILOGUE From a petroleum economics viewpoint, the impact on some Latin American non-conventional oil developments is relatively low. However, plummeting of prices has had a great impact on certain junior companies in the region and in particular, countries like Colombia. Nevertheless, there is a light at the end of the tunnel. On the one hand, it seems prices are searching for a floor and on the other, there is chance for price recovery in the mid term.

NOTES 1. The other promising Mexican play to be developed is Chicontepec. However, that area is also rather expensive but for different reasons. Given the spread of the area there are huge amounts of monies (and possibly dry wells) that need to be invested until they find commercially viable plays. 2. There have been some unconfirmed reports assessing that reserves on this site could reach over 150 Mb. However, there is no final certification of those reserves. 3. Confidential analysis. 4. Confidential analysis.

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PART II THE FUNDAMENTALS OF THE GLOBAL ENERGY INDUSTRY: THE DEMAND SIDE

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6.  The role of Sino-Russian gas cooperation in China’s natural gas expansion Keun-Wook Paik

Since May 2014, when the Power of Siberia (POS) 1 gas deal was announced, a lot of Western media coverage has been focusing on the delay of POS 1 development, but it is safe to say that there is no change in fundamentals of Sino-Russian oil and gas cooperation. Unlike the ESPO (Eastern Siberia–Pacific Ocean) oil line which started operation in 2009 and made Russia a swing supplier between the European and Asian markets, POS 1 line is still under construction and even after the completion it will not make Russia as a swing supplier. Nonetheless, the impacts of Sino-Russian gas cooperation cannot be underestimated as POS 1 development is only the start of the expanding gas sector cooperation. A recent OIES paper by James Henderson and Tatiana Mitrova (2016) explains where Sino-Russia’s oil and gas cooperation stands.1 The paper’s verdict on the status of energy relations between Russia and China is as follows: There is no doubt that Russia’s pivot to Asia is certainly taking place (the evidence from the oil sector alone is enough evidence of this), we have characterised the developing energy relationship between Russia and China as akin to “playing chess with the Dragon”, by which we mean to imply that from a Russian perspective it is playing a complex and high risk game with a powerful adversary. China, with its much larger economy, its financial firepower and the benefit of Russia’s weakened geo-political status seems set to control the energy relationship with its northern neighbour. However, Russia is not without strengths of its own and is attempting to exploit them wherever it can. China does need Russian oil, and wants access to the Russian Arctic. Overtime (perhaps a decade) it may also come to need Russian gas in great quantities. Nevertheless, with the oil and gas markets becoming more global in nature, it is unlikely that Russia will be able to exploit these opportunities on anything other than competitive terms. The reality is that its assets are, to an extent, stranded in the East with China as their prime market, and as such their output is unlikely to command a premium price, given China’s alternative options. As a result, in order to fully benefit from its energy connection to the East, Russian companies need to create their own diversification options. Rosneft and Novatek have started to do this to a limited extent. It is now time for Gazprom to show the same levels of flexibility, or potentially face significant consequences for its future in the Russian gas sector.

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134   Handbook of energy politics Surely Russia’s pivot to Asia policy is in full swing, but the most important question is whether Sino-Russian oil and gas cooperation will move into the strategic level. No easy answer exists. During the last two years, was there any significant change that signals the strategic level cooperation between Russia and China’s oil and gas cooperation? The short answer is that there was no breakthrough of Altai gas export to China and no CNPC acquisition of Rosneft’s 19.5 percent equity materialized. However, there are a number of important initiatives that will broaden the scope and enhance the level of oil and gas cooperation. This paper will only focus on the role of Sino-Russian gas cooperation in China’s natural gas expansion. During President Putin’s visit to Beijing in June 2016, President Xi Jinping highlighted that 2016 marked the 15th anniversary of the China– Russia Treaty of Friendship and he hoped the two countries might remain “friends forever.” President Xi said that “President Putin and I equally agree that when faced with international circumstances that are increasingly complex and changing, we must persist even harder in maintaining the spirit of the Sino-Russian strategic partnership and cooperation.”2 President Putin said the Russian–Chinese commission on investment cooperation selected 58 commercial initiatives for implementation (some of them are listed below), which require investment amounting in total $50 billion: ●

●

●

●

●

Rosneft and Sinopec have agreed to make a final decision by September regarding the Chinese company participating in the project to develop the Yurubcheno-Tokhomskoye field by acquiring a 49 percent stake in the East Siberian Oil and Gas Company. Rosneft and Beijing Enterprises Group (BEG) signed an agreement on cooperation within the framework of Verkhnechonskneftegaz (VCNG) Rosneft had reached agreement with BEG on the principal terms and conditions of the potential sale of a 20 percent stake in VCNG. The parties expect to sign binding agreements on the matter no later than the fourth quarter of 2016. Chinese national chemical corporation ChemChina will acquire 40 percent of Rosneft’s Far East Petrochemical Company (FEPCO) project. Rosneft and China’s Shandong Kerui Petroleum Equipment signed a memorandum of understanding on strategic partnership in the area of petroleum services. Rosneft and China Petrochemical Corporation (Sinopec Group) plan to build a facility to process annually 5 billion cubic meters (bcm) of gas and 3 million tonnes of polymers in Boguchany in East Siberia. The annual capacity of the new complex near the

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Sino-Russian gas cooperation in China’s natural gas expansion  ­135 administrative center of Boguchany District will be 5 bcm of gas yielding up to 3 million tonnes of polymers and petrochemical products primarily for sale on the Russian and Chinese markets. The resource base of the project comprises Rosneft oil and gas fields of Yurubcheno-Tokhomskoye cluster in East Siberia. ● The Russian–Chinese dialogue in the gas sector is encompassing new areas. The cooperation in the area of underground storage and power generation will facilitate the further deepening of cooperation between the companies and the significant improvement of the environmental situation in China.3 It remains to be seen how many initiatives will be converted into the meaningful transactions, well beyond the media plays. A point that should be highlighted is that the boundary of negotiations among the flagship NOCs from Russia and China – like Rosneft-CNPC, Rosneft-Sinopec, Gazprom-CNPC – is already being redrawn and expanded. The cooperation in upstream, midstream and downstream is being opened to other big state-owned institutions from Russia and China, and the expansion is set to continue. In early September 2016, during the second Eastern Investment Forum at Vladivostok, President Putin said that: Gazprom has plans to connect the Western Siberian deposits and our gas transportation system with the system emerging in the Far East . . . Such plans not only exist, they are also really beginning to plan this work. It is also connected with the internal needs of the Far Eastern regions. It is also connected to Gazprom’s wish to expand its export market. If any problems arise in Europe, we will easily re-direct flows to the East.4

It is a clear indication that President Putin’s intention is to make Russia as swing supplier between European and Asian market, and Russia’s pivot to Asia policy is gearing up. It is not certain how long it will take to witness the tangible consequence of this initiative. In this paper, the focus will be centred on China’s gas expansion and the role of Sino-Russian gas cooperation in this expansion. During the last 12 months, there were two important developments in Sino-Russian gas cooperation which will affect China’s gas expansion in the coming years. The first is indirectly related with POS 1 project and the second is related with the Arctic LNG supply to China in the coming years.

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136   Handbook of energy politics

TAAS-YURIAKH SAGA: RUSSIA’S CHINA VS. INDIA CARD5 The unexpected deal between Rosneft and BGG (Beijing Gas Group) in June 2016 will have a big impact in China’s gas expansion if the gas supply from the project is timely implemented. Without knowing the background of the Taas-Yuriakh saga in March 2016, it could be seen as one of many deals between the two countries. On March 16, 2016, Russia’s Rosneft OJSC agreed to sell bigger stakes in its Siberian oil assets to Indian staterun energy companies, including a $1.28 billion share to a consortium of Indian producers. The group of three Indian companies took a combined 29.9 percent share in Taas-Yuriakh Neftegazodobycha and a 23.9 percent stake in Vankorneft. In April 2016, an article gave quite convincing details on Rosneft’s negotiations with BGG by saying that: According to Russian RBC, Rosneft was yet again trying to undermine Gazprom’s gas export monopoly, this time on the eastern front. RBC’s sources said that several rounds of negotiations have already passed, with the last one taking place during Rosneft president Igor Sechin’s visit to Beijing mid-March 2016.6

It touches the sensitive issue of the third-party access to the POS and the assumption is Rosneft will not give up the attempt to dismantle Gazprom’s monopoly on POS 1 gas supply. That is, the core of this deal is the access of independent gas producers into the POS 1 pipeline, when Gazprom is determined to sustain a “single export channel.” This has been recorded in the protocol of the presidential committee that took place in October 2015. It is difficult to understand and explain why Rosneft has hurriedly decided to sell the asset to the Indian consortium rather than the Chinese investor that can offer a huge gas market directly. It is worth noting that BGG as the main supplier of gas to Beijing and Hebei province was at the final stage of its due diligence to buy 20 percent in Taas-Yuriakh oil and gas field out of a 29 percent interest that was set aside for Dubaibased Skyland Petroleum. In fact, Skyland Petroleum has played a very important role in persuading and convincing BGG to take the 29.9 percent equity jointly to make sure BGG could access the direct gas supply from East Siberia via POS gas line. The initiative of taking 29.9 percent equity by BGG/Skyland Petroleum could give a maximum benefit to the gas consumers in northern China as BGG can effectively reduce the import border price based on their equity stake in the target upstream project. This was the type of equity investment model CNPC had dreamed of achieving with regard to the POS 1 gas line development. While Gazprom

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Sino-Russian gas cooperation in China’s natural gas expansion  ­137 has been firmly rejecting the opening of the upstream for CNPC so far, Rosneft was willing to use the carrot of opening the upstream sector to China’s biggest gas consumer. Rosneft’s decision to use the India card in March 2016 has caused a big confusion. It seems that the Indian consortium had assumed Rosneft had already signed a long-term gas supply deal with BGG based on the Taas-Yuriakh field, considering that people were questioning the wisdom of the Indian deal by mentioning that the Indian consortium had asked the existence of gas SPAs between Rosneft and BGG right after the deal announcement in mid-March. Considering that Rosneft could have allocated Verkhne-Chonskoye field with C1+C2 reserves of 173 mt of oil and condensate and 115 bcm of gas, instead of Taas-Yuriakh field – which is a part of SredneBotuobinskoye oil, gas and condensate field with 167 mt of oil and condensate and 181 bcm of gas to the Indian consortium – it is safe to say that the Indian consortium was forced to take the Taas-Yuriakh field asset first while BGG was finalizing the due diligence. Due to the collapse of rubles value, Rosneft’s top management was under massive pressure to minimize the debt scale and the hurried sales of the assets was the priority. This may explain indirectly why the hurried deal with Indian consortium became the priority. Besides this, Rosneft had to show that Russia’s flagship oil firm cannot bank on one partner and had to build partnerships with several different players to choose from several options. In short, Moscow really wanted to show that Russia’s pivot to Asia policy is not sole dependence on the China market. That may be the case when it comes to the oil sector business, but for the Indian consortium there was no synergy whatsoever when it comes to the gas sector of the deal. Rosneft had almost lost the biggest gas consumers in China by prioritizing the half-baked deal with Indian consortium in March 2016. This explains why the unexpected Verkhne-Chonskoye deal with BGG was announced in June 2016 as Rosneft cannot afford to lose the gas market being offered by BGG. More important to the Verkhne-Chonskoye deal with BGG is the fact that the US$ 12 bn loan from China’s policy banks such as China Development Bank and China Exim Bank was made in April 2016. Moscow had to find an alternative of Taas-Yuriakh for BGG, which was backed by the Beijing authority. It is worth noting that Gazprom’s rigid stance towards its upstream opening in East Siberia or West Siberia looks unlikely to change that easily. The breakthrough of overly advertised Altai gas supply (or POS 2) to China may take more time than Gazprom is hoping for. Interestingly, the Russian analysts argued that in consideration of the financial burden

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138   Handbook of energy politics of POS line construction, the best course of action for Gazprom would be to find the least costly method of backing out of the contract. The second best option would be to invite Chinese contractors to march into East Siberia and build the pipeline at what would likely be much lower cost than the Russian company could offer. The very best solution for Gazprom is to get the loan from Beijing for the POS construction, therefore, not the backing out of the contract.

CHINA’S GAS EXPANSION AND LOAN FOR GAS INITIATIVE Following the May 2014 POS 1 gas line deal, the loan for gas for Novatek’s Yamal LNG was the most important development for Sino-Russian oil and gas cooperation. What was the driving force of this loan for gas initiative? A number of direct or indirect factors such as Beijing’s stance towards global climate change, China’s gas expansion plan, the South China Sea boundary dispute and the regional multilateral gas cooperation. The simple way to grasp the importance of loan-for-gas initiative is to understand China’s gas expansion in the coming decades and the role of LNG and pipeline gas imports. In early March 2016, China announced that a total energy consumption cap of 5 billion tonnes of coal equivalent (btce) by 2020 comes after the success of the 12th Five-Year Plan from an energy perspective, in which energy and carbon targets were met and surpassed. Between 2011 and the end of 2015, energy intensity (that is, energy consumption per unit of GDP) fell by 18.2 percent and carbon intensity declined 20 percent. These declines are due in large part to the drop in coal consumption: down 3.7 percent in 2015, following a 2.9 percent decrease in 2014. The slowed consumption suggests that achieving a 5 billion tonnes energy cap may not be challenging.7 The China Energy Research Society (CERS) said in early 2016 that it expected energy consumption to reach 4.8 billion tonnes of standard coal by 2020 and rise to 5.3 billion tonnes by the end of 2030. As shown in Table 6.1, CNPC Economics and Technology Research Institute (ETRI)’s projection on China’s primary energy demand until 2050 released in July 2016 suggested the figure in 2020 and 2030 will be 4620 mtce and 5300 respectively.8 However, the breakdown of the projection confirms the complacency among the Chinese energy planners. The share of coal in China’s primary energy demand in 2020, 2030, 2040 and 2050 is projected to be 58 percent, 48 percent, 41 percent and 37 percent respectively. That is, coal in China looks unlikely to face with the fast track phase-out.

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Sino-Russian gas cooperation in China’s natural gas expansion  ­139 Table 6.1  China’s primary energy demand Unit: mtoe / mtce Primary Energy Demand Coal Oil Natural Gas Nuclear Hydro Renewables Total (mtoe) Total (mtce)

2000

2010

2015

2020

2030

2040

2050

700 214 23 6 71 1 1015 1449

1748 433 99 25 186 13 2505 3577

1903 544 174 38 280 60 2998 4281

1878 622 270 89 274 101 3235 4620

1799 674 458 193 345 241 3711 5299

1522 616 606 274 369 309 3696 5278

1296 501 640 350 361 373 3520 5026

Note:  mtoe means million tonnes of oil equivalent, and mtce means million tonnes of coal equivalent Source:  CNPC ETRI (2016).9

In an article placed at Trusted Sources website, Stephen O’Sullivan correctly pointed out that gas prices need to fall further to improve Asia’s environment.10 The point was that one of the key routes to improving Asia’s physical environment is the replacement of coal in power generation by natural gas; price alone is unlikely to persuade energy users to switch to a more environmentally friendly fuel like gas. As in Japan and Korea, China plans to introduce a carbon trading system in 2017, although there is no clear view on what the price set for it is likely to be. The most promising solution to achieve governments’ aim of fuel switching and environmental improvement is the introduction of an effective carbon pricing mechanism, which raises the price of coal sufficiently to allow gas to be competitive in the power generation market. Politically and technically, however, this could be a complex and lengthy challenge across Asia. The gas price in China is still not competitive enough to move from coal-for-power to gas-for-power swiftly, and China’s energy planners are struggling to balance the gradual and radical reform for China’s gas expansion. The dilemma had been and is being reflected regularly in the revised China’s gas expansion projections.

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140   Handbook of energy politics

CHINA GAS SUPPLY AND DEMAND PROJECTIONS: 2020 and 2030 Since the West-to-East Gas Pipeline (WEP) project put into operation in 2004, the Chinese gas industry had experienced an impressive expansion. From 2005 to 2013, gas consumption jumped more than threefold from just over 46 bcm to 146 bcm, with an average growth rate of 17.8 percent. The share of gas in China’s primary energy consumption has moved from around 2 percent to 5.6 percent. Around 2012, the Chinese government had no hesitation in projecting 400 bcm gas consumption in China by 2020, taking over 10 percent of the total energy consumption at that time. However, the recent projections on China’s gas expansion by 2020 and 2030 looks much more conservative than the bullish projection made in 2012. Tables 6.2 and 6.3 shows the actual records of production, consumption and imports during 2006–16 H1 period. China’s top three NOCs are still dominating China’s gas production, and Shaanxi province-based Yanchang Petroleum’s increased role in gas production looks interesting. The widened gap of supply and demand confirms the need of a substantial import volume of LNG and pipeline gas. Although many independent and industry observers projected consumption of 2020 around 270–330 bcm/y, state regulator and the NOCs are likely to maintain a gas consumption target above 350 bcm by 2020, as required by national policy to cap carbon emission, limit coal consumption and control urban pollution issues. Table 6.4 serves as a very useful comparison benchmark. (Please check CNPC’s 2012 and 2014 projection from author’s OIES 2015 paper.)11 Tables 6.5–6.8 are based on CNPC’s most recent projections released Table 6.2  China’s gas supply and demand: 2009–15 Unit: bcm/y 2009 2010 2011 2012 2013 2014 2015

CNPC

Sinopec

CNOOC

Yanchang

Total

68.32 72.53 76.62 79.85 88.83 95.46 95.48

  8.33 12.36 14.39 16.66 18.39 19.85 20.22

  7.48 10.17 11.15 11.26 11.10 12.41 13.01

0.00 0.01 0.02 0.26 0.47 0.60 1.72

84.13 95.08 101.18 108.03 118.79 128.32 130.43

Source:  China Petroleum Planning and Engineering Institute (CPPEI) (2016).

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Sino-Russian gas cooperation in China’s natural gas expansion  ­141 Table 6.3  China’s gas supply and demand: 2006–2016 Unit: bcm/y Consumption

Production

Imports

Exports

56.1 70.5 81.3 89.5 107.6 130.5 146.3 170.5 186.9 193.1 99.5

58.6 69.2 80.3 85.3 94.9 102.7 107.2 120.9 130.2 135.0 67.5

1.0 4.0 4.6 7.6 16.5 31.2 42.1 52.5 59.1 61.4 35.6

2.9 2.6 3.3 3.2 4.0 3.2 2.9 2.8 2.6 3.3 n.a.

2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 1H

Source:  National Bureau of Statistics of China (various years covering 2006–2016).

Table 6.4  C  hina’s gas supply and demand: based on CNPC 2015 projection 2015 Conventional Unconventional – Shale gas – CBM – CTG Imported LNG Imported PG Total

2020

2030

c

o

c

o

c

o

132.0 14.9 5.0 7.9 2.0 35.0 40.0 224.9

138.5 18.8 6.5 9.3 3.0 40.0 44.0 241.3

170.0 31.6 10.0 11.6 10.0 60.0 75.0 336.6

185.0 59.7 30.0 14.7 15.0 70.0 80.0 394.7

210.0 57.3 20.0 17.3 20.0 70.0 120.0 457.3

230.0 116.0 60.0 26.0 30.0 80.0 130.0 556.0

Source:  CNPC (2015).

in July 2016. Within CNPC, the two most important subsidiary entities in terms of planning, evaluation and projections are CNPC Economics and Technology Research Institute (ETRI)12 and China Petroleum Planning and Engineering Institute (CPPEI). For example, CNPC ETRI aims at making its annual energy report as the flagship energy report from China. CPPEI is a media-shy entity but all the gas pipeline projects were planned and designed by CPPEI, and WEP is the showcase achievement of CPPEI.

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142   Handbook of energy politics Table 6.5  China’s gas production projection, by CNPC ETRI Unit: bcm Natural Gas Supply Onshore Offshore Tight gas Shale gas CBM Bio gas Others Total

2000

2010

2015

2020

2030

2040

2050

27 1 0 0 0 0 0 28

68 5 20 0 1 1 0 94

83 17 25 4 4 1 1 135

100 32 37 20 14 2 11 216

147 42 59 70 26 4 24 373

150 54 49 94 36 10 33 425

118 73 36 100 42 22 35 426

Source:  CNPC ETRI (2016).13

Table 6.6  China’s gas supply projection, by CPPEI Unit: bcm/y

Conventional Coal-bed methane Shale gas Coal-to-Gas Sub-total Pipe gas import LNG import Sub-total Total

2015 actual

2020 projected

2030 projected

124.1 1.4 5.1 4.4 135.0 35.6 25.8 61.4 196.4

185.0 20.0 30.0 25.0 260.0 83.0 60.6 143.6 403.6

250.0 50.0 50.0 50.0 400.0 150.0 100.0 250.0 650.0

Source:  CPPEI (July 2016).

CNPC’s two institutions, however, show some differences in their 2020 and 2030 projections. CNPC ETRI is more conservative than CPPEI. Presumably, it is due to the fact that CNPC ETRI is more market focused, while CPPEI is more supply oriented. In fact, CNPC ETRI is projecting 216 bcm/y of gas supply by 2020 and 373 bcm/y by 2030, while CPEEI’s projection figure is 260 bcm and 400 bcm respectively. The projections on gas demand by 2020 and 2030 show the similar pattern as CPPEI’s figures

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Sino-Russian gas cooperation in China’s natural gas expansion  ­143 Table 6.7  China’s gas demand projection: CNPC ETRI vs. CPPEI Unit: bcm 2015 Actual Residential Commercial Heating Transportation Industrial Chemical Gas for power Total

35.5 10.0 7.1 22.5 77.2 13.7 27.1 193.2

2020

2030

ETRI

CPPEI

ETRI

52.0 17.5 13.1 29.0 110.0 18.4 60.5 300.5

32.0 16.0 21.1 46.6 124.8 24.8 94.0 359.3

99.5 49.4 21.0 43.5 163.3 25.3 106.7 508.7

CPPEI 152.5 65.7 149.9 23.3 182.0 573.4

Source:  CNPC ETRI and CPPEI (2016).

Table 6.8  China’s gas demand, by sector Unit: bcm Natural Gas Demand Residential Commercial Transportation Heating Industrial Chemical Power Total

2000

2010

2015

2020

2030

2040

2050

4 1 0 4 6 5 4 25

23 5 11 7 37 11 18 110

36 10 23 7 77 14 27 193

52 18 29 13 110 18 61 300

99 49 44 21 163 25 107 509

143 85 52 27 189 28 148 673

156 103 54 30 177 29 162 711

Source:  CNPC ETRI (2016).14

are much higher than CNPC ETRI. As CNPC ETRI’s projection on the LNG and pipe gas import is not available in Table 6.6, it is difficult to compare with the 2015 projection but CPPEI’s projection of 650 bcm in 2030 looks quite high. Both Table 6.7 and 6.8 confirm that China’s gas market expansion will be driven by industrial, gas-for-power and residential sector. Table 6.9 indirectly indicates the role of coal in power generation will not shrink that

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144   Handbook of energy politics Table 6.9  China’s electricity, by source Unit: Terawatt hours Electricity Supply Coal Gas Oil Nuclear Hydro Renewables Total

2000

2010

2015

2020

2030

2040

2050

1108 0 0 17 243 1 1369

3323 76 16 75 687 50 4226

3960 123 5 150 1114 200 5552

4060 275 2 390 1198 440 6365

4800 508 0 930 1661 1160 9059

4200 737 0 1380 1863 1560 9740

3600 843 0 1830 1889 1950 10112

Source:  CNPC ETRI (2016).15

Table 6.10  Pipeline gas supply to China Unit: bcm/y Gas source CACP (Line A/B) CACP (Line C) CACP (Line D) Myanmar Power of Siberia 1 Altai / POS 2 Total

Turkmenistan Turkmenistan Uzbekistan Kazakhstan Turkmenistan Tajikistan Myanmar Russia Russia

2015 Import volume

Pipeline capacity

2020/2030 projection

27.7

30.0

LTT / Stable

1.5 0.4 –

25.0

Stable

30.0

SDP / Stable

3.9 – – 33.6

12.0 38.0 30.0 165.0

LTT / Stable SDP / Stable SDP / ??

Note:  LTT means lower than targeted; SDP means slower than planned. Source:  Author’s database and various reports.

fast, and even in 2040 the share of coal for power will be over 40 percent. In other words, if the policy change is made, there is space for expansion of gas in power generation. Table 6.10 shows the total volume of China’s gas imports will be 165 bcm/y under the current plan. The supply volume from the Central Asian Republics will be 85 bcm/y once all the CACP A/B, C and D lines are fully

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Sino-Russian gas cooperation in China’s natural gas expansion  ­145 operational, and POS 1 and 2’s supply from Russia will be 68 bcm/y, if the breakthrough on the Altai gas deal is made. If the upstream sector is opened, POS 2’s fast track development will be a reality, but there is no sign from Gazprom to change its stance towards the upstream opening yet. Under the normal situation, Altai 1 will be the maximum Gazprom can secure during the 2020s. If South China Sea’s boundary disputes are intensified, however, the chance of Altai 1’s fast track development will be much higher, and the chance of Altai II and III deals cannot be ruled out as Beijing’s leadership will seek the comfort from the maximization of the pipeline gas supply. As shown in Table 6.11, as of 2016 there are 13 LNG terminals with the capacity of 48.3 mt/y (+ 2nd stage volume 6 mt/y, it will be 54.3 mt/y). In 2018, when the currently being constructed terminals (with the capacity of 9.6 mt/y) are complete, the total volume will reach 57.9 mt/y. When the volume of three more approved terminals like Zhejiang Wenzhou LNG (Sinopec, 3.0 mt/y) and Jiangsu Lianyuangang LNG (SINOPEC, 3.0 mt/y), and Jiangsu Binhai LNG (CNOOC 2.6 mt/y) is added, China’s LNG receiving capacity from the 20 LNG terminals will reach to at least 66.5 mt (+ 2nd stage, 70.9 mt/y). The figure will be big enough to make China the second biggest LNG importer in Northeast Asia. It is worth noting that the total volume of LNG imports in 2015 was 26.1 mt, of which 7.2 mt from Australia, 6.5 mt from Qatar, 4.4 mt from Malaysia, 3.9 mt from Indonesia, 2.1 mt from Papua New Guinea, and the remaining 2.0 mt from Trinidad and Tobago, Norway, Russia, Oman, Yemen, Algeria, Nigeria, Equatorial Guinea. As of 2016, the contracted LNG volume is 44.8 mt, of which 20.9 mt by CNOOC, 10.8 mt by Sinopec, 10.3 mt by CNPC, 1.8 mt by Zhongtian, 1.0 mt by Huadian and the remaining 2.8 mt by newcomers. In short, when these LNG terminals and pipelines are all constructed by the early 2020s, the volume of China’s LNG and pipeline gas will be sizable. However, the key is the competitiveness of imported gas price. Many Western observers are repeating the LNG supply glut until the early 2020s, but it will lose the merit of investment as the return rate will not be as good as before. This is why the need and importance of China’s sovereign funds’ provision for overseas gas supply source has to be highlighted.

THE NEED TO MOVE FROM LOAN-TO-COAL TO LOAN-FOR-GAS According to a recent GEGI study, Chinese development banks have provided upwards of US$ 28 billion in financing for global coal projects – projects that accentuate climate change and social risks. Using ­conservative

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146

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Dongguan Hongmei LNG Hebei Tangshan (Caofeidan)   LNG Guangdong Zhuhai Jinwan   LNG Hebei Tianjin FSRU Hainan Yangpu LNG

Zhejiang Ningbo LNG

2013 2013 2014

3.5 2.2 3.0

2012 / uc

2011

2011 / uc

2012 2013

3.0 (+3.0) 6.5

Dalian LNG

2009 / 2011

2006 / 2010 2008 /2011

Operation date

3.0 (+3.0) 1.0 3.5

3.0 + 0.5

Shanghai Yangshan LNG

Jiangsu Rudong LNG

6.8 6.3

Capacity (mtpa)

Guangdong Dapeng LNG Fujian Putian LNG

Project

CNPC (55%), Pacific Oil & Gas Ltd (35%) CNOOC (51%), Zhejiang Energy (29%), Ning Power (20%) Guangdong JOVO Group CNPC, Beijing Enterprises Group & Hebei Natural Gas Co CNOOC (30%), Guangdong Yuedian (25%) CNOOC CNOOC

CNPC (75%), Dalian Port (20%)

CNOOC (45%), Shenergy (55%)

CNOOC (33%), BP (30%) CNOOC (60%), FIDCL (40%)

Company

Table 6.11  China’s LNG import projects, as of December 2014

Operation / Operation / Qatargas

Operation / QatarGas +

Operation Operation

Operation / QatarGas III

Operation / NWS, Australia Operation / Tangguh, Indonesia Operation / Petronas, Malaysia Operation / QatarGas IV & Australia Operation / QatarGas IV

Remarks / LNG Source

147

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2.0 0.6 3.0 57.9 / 63.9

3.0 3.0 48.3 + 6.0 4.0

Source:  Author’s database (based on CNPC, CNOOC, Sinopec websites and various media reports).

CNOOC Guanghui & Shell ENN Group

CNOOC

2016–17 2016–17 2018 2018

Sinopec Sinopec

2014 2016

Note:  FIDCL means Fujian Investment & Development Co Ltd.

Shandong Qingdao LNG Beihei LNG Sub-total Guangdong Shenzhen   Diefu LNG Guangdong Yuedong Jiangsu Qidong LNG Zhejiang Zhoushan LNG Total

Under construction Under construction Under construction

Under construction

Operation / PNG LNG Operation

148   Handbook of energy politics estimates of the climate and local health costs of coal plant emissions, the study authors calculate that the yearly social cost of Chinese overseas coalfired power plants amounts to US$ 29.7 billion. Assuming a power plant lifetime of 30 years, total social cost could range from US$ 117 billion to $892 billion.16 It confirms that China’s energy loans are highly concentrated in fossil fuel extraction and power generation, especially coal. In the same month, a study by CIERP under the Fletcher School, Tufts University elaborated that between 2001 and 2016, Chinese financial institutions supported the construction of more than 50 coal-fired power plants abroad. A majority of these power plants (58 percent) used subcritical coal technology, which is the most energy inefficient form of coal-fired power plant, and therefore the type that is most carbon intensive, and almost all of the rest were supercritical plants, which are approximately 12 percent more efficient than subcritical plants. On an annual basis, this fleet of more than 50 coal-fired power plants is estimated to release 594 million tonnes (mt) of CO2, which is equivalent to 11 percent of total U.S. emissions in 2015 and 6 percent of total Chinese emissions in 2014 (latest year available). Overseas coal plants financed by China’s policy banks (like the China Development Bank and the China Export and Import Bank) would be the eighth largest emitter of carbon dioxide emissions, more on an annual basis than Canada, Brazil, Saudi Arabia or the United Kingdom. If a 30-year lifetime of these plants is assumed, these plants will cumulatively emit 17,828 mt CO2, equal to more than triple total U.S. emissions in 2015, 1.5 times Chinese emissions in 2014, or slightly more than U.S. and Chinese emissions put together on an annual basis.17 If the part of this financing is allocated for the loan for gas, its impact for China’s gas supplies will not be small. Interestingly, when the above study was published, China already made the decision to make the loan for gas to the Yamal LNG project in late April, and in May China decided to finance 85 percent of Pakistan LNG terminal and pipeline projects. The deal was signed between Pakistan’s Inter State Gas System (ISGS) and CNPC. China Petroleum Pipeline Bureau (CPP) will construct the pipeline and will also build LNG terminal at Gwadar. The project cost around US$ 2.0 billion.18

A BOLD LOAN FOR GAS INITIATIVE FOR YAMAL LNG On April 29, 2016, in Beijing, Yamal LNG signed credit agreements with the Export-Import Bank of China (China Exim Bank) and the China Development Bank for the amount of 9.3 bn euros and 9.8 bn yuan

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Sino-Russian gas cooperation in China’s natural gas expansion  ­149 for 15 years. The firm said in a statement that the interest rates for the credit lines are EURIBOR 6M +3.3 percent per annum for the period of construction and 3.55 percent after the full commissioning of Yamal LNG and SHIBOR 6M +3.3 percent and 3.55 percent per annum, respectively. Earlier in the framework of raising project financing, 150 bn rubles were received on a return basis from Russia’s National Welfare Fund (NWF), and also an agreement was signed with Sberbank and Gazprombank about the provision of a credit line in the amount of 3.6 bn euro for 15 years. Yamal LNG CEO Evgeny Kot said: The project is being implemented in accordance with the confirmed schedule, the first train of the LNG plant is 65% ready, and we are in the most intense stage of construction and installation work. The signing of the agreements with the Chinese banks is allowing us to implement the project without raising additional funds from shareholders.19

During the June 2016 Saint Petersburg Economic Forum, Novatek boss Leonid Mikhelson confirmed that the partners in the Yamal LNG project  – Total, CNPC and Silk Road Fund – also show interest in the development of the projected Arctic LNG. Mikhelson added that a technological concept for the project is due to be completed in the course of 2016. This will include LNG output capacity, licenses and equipment. Mikhelson elaborated the capacity of the projected plant could be 6 million tons of LNG per year. The first production phase project could be launched in the year 2022, followed by a second and third phase in 2024 and 2025 respectively. Novatek said that while the production from Yamal LNG is based on long-term supply contract with customers, the gas from the Arctic LNG will be sold on the spot market. The Arctic LNG plant will be based on resources from the Gydan Peninsula, and first of all the Salmanovskoye and Geofizicheskoye fields, both located on the eastern bank of the Ob Bay.20 The loan for gas for Yamal LNG development has opened a new chapter in Sino-Russian gas cooperation. First, the 29.9 percent equity stake acquisition by both CNPC and Silk Road Fund is an indication that Beijing is deeply interested in taking the upstream sector in Russia. In fact, while Gazprom complained about no provision of lending for the POS 1 development after the May 2014 gas deal, it had forgotten why the upfront payment card was suggested by Chinese planners when the border gas price formula was linked with oil price over US$ 100 barrel. As Gazprom had vetoed the upstream equity option, the most effective way to reduce the border price was to utilize the special interest based lending for the POS 1 gas supply to northern China. The indirect message from Beijing to Moscow is that POS 1 and POS 2 can be the beneficiary

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150   Handbook of energy politics of this loan for gas if upstream sector positioning is allowed. It remains to be seen how Gazprom will read between the lines. Secondly, Beijing leadership is very keen on the Arctic area’s resources development and the related supply routes to Asia. The diversification of supply routes is very important for Beijing’s leadership, as the oil and gas supply security is of utmost importance. In particular this will be the case when the South China Sea disputes are intensified. Thirdly, if the large scale lending based on sovereign funds can reduce the production cost of equity gas, Beijing can accelerate the switch from coal-for-power to gas-for-power. The financial burden of using gas in China cannot be reduced based on the current market system, and this is where the sleeping sovereign funds can be utilized most effectively. In short, China has decided to apply for the loan for gas scheme for the Yamal LNG development as a way of strengthening Sino-Russian gas cooperation. Russia is still under U.S. and EU sanctions in the wake of its Crimean Peninsula annexation. Russia’s support of Syria’s brutal Asad regime’s survival is extending China’s isolation from the international community. China is now in a difficult situation as Beijing has refused to recognize the ruling by the Permanent Court of Arbitration that granted the Philippines sovereign rights to access offshore oil and gas fields in July 2016. If the South China Sea territorial disputes intensify, Beijing’s leadership will not hesitate in increasing the role of pipeline gas and LNG supply from the Arctic region. This will strengthen the level of Sino-Russian gas cooperation significantly. One thing is certain, the increased role of imported gas by LNG and pipeline will continue in the coming years in parallel with China’s gas expansion.

ACKNOWLEDGMENT The Japanese version of this paper was published by Mitsubishi Corp’s Diamond Gas Report (DGR) in November and December 2016. The author would like to express his appreciation for DGR’s approval to contribute the English version to the book.

NOTES   1. J. Henderson and T. Mitrova (2016) “Energy relations between Russia and China: Playing chess with the dragon,” OIES Paper, WPM 67, August, available at https://www. oxfordenergy.org/wpcms/wp-content/uploads/2016/08/Energy-Relations-betwe​e​n-Rus​ sia-and-China-Playing-Chess-with-the-Dragon-WPM-67.pdf. Accessed December 12, 2017.

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Sino-Russian gas cooperation in China’s natural gas expansion  ­151   2. The Guardian (2016) “‘Friends forever’: Xi talks up China’s ties with Russia during Putin trade trip,” available at https://www.theguardian.com/world/2016/jun/26/friendsforever-xi-talks-up-chinas-ties-with-russia-during-putin-trade-trip. Accessed December 12, 2017. For an in-depth understanding on Sino-Russian oil and gas cooperation, see K-W. Paik (2012) Sino-Russian Oil and Gas Cooperation: The Reality and Implications, Oxford: Oxford University Press; K-W. Paik (2015) “Sino-Russian gas and oil cooperation: Entering a new era of strategic partnership?” OIES Paper, WPM 59, April, available at http://www.oxfordenergy.org/wpcms/wp-content/uploads/2015/04/ WPM-59.pdf. Accessed December 12, 2017.   3. Interfax Russia & CIS Oil and Gas Weekly (2016) June 23–20, pp. 4–8; D. Khrennikova, E. Mazneva and S. Bierman (2016) “Rosneft’s Sechin says China ties boosted with new deals, routes,” Bloomberg, June 2, available at http://www.bloomberg.com/news/ articles/2016-06-26/rosneft-s-sechin-says-china-ties-boosted-with-new-deals-routes; https://www.rosneft.com/press/releases/item/182765/. Accessed December 12, 2017.   4. Interfax Russia & CIS Oil and Gas Weekly (2016) September 1–7, p. 8.   5. K-W. Paik (2016) “Sino-Russian oil and gas cooperation: Where it stands and how far can it expand?” Geopolitics of Energy, 38 (8), August, pp. 2–10.   6. Economic Calendar (2016) “Rosneft tries to break Gazprom’s monopoly using China,” accessed January 1, 2017 at http://www.economiccalendar.com/2016/04/07/ rosneft-tries-to-break-gazproms-monopoly-using-china/.   7. K. Chen and D. Stanway (2016) “China sets up for energy consumption for first time,” Reuters, March 5, available at http://uk.reuters.com/article/us-china-parliament-energyidUKKCN0W703V; https://www.chinafile.com/reporting-opinion/­environment/howchinas-13th-five-year-plan-addresses-energy-and-environment; http://www.wsj.com/ar​ ticles/china-includes-green-cap-in-economic-blueprint-1457164553. Accessed December 12, 2017.   8. CNPC ETRI (2016) “Energy outlook 2050,” July 12, Beijing, China.   9. CNPC ETRI (2016) “Energy outlook 2050,” July 12, Beijing, China. 10. S. O’Sullivan, “Gas prices need to fall further to improve Asia’s environment,” Trusted Sources, available at http://www.trustedsources.co.uk/blogs/energy/gas-prices-need-tofall-further-to-improve-asia-s-environment. Accessed December 12, 2017. 11. K-W. Paik (2016) “Sino-Russian gas and oil cooperation,” pp. 21–4. 12. CNPC ETRI, accessed December 12, 2017 at http://etri.cnpc.com.cn/. 13. CNPC ETRI (2016) “Energy outlook 2050,” July 12, Beijing, China. 14. CNPC ETRI (2016) “Energy outlook 2050,” July 12, Beijing, China. 15. CNPC ETRI (2016) “Energy outlook 2050,” July 12, Beijing, China. 16. K.P. Gallagher, R. Kamal and Y. Wang (2016) “Fueling growth and financing risk: The benefits and risks of China’s development finance in the global energy sector,” GEGI (Global Economic Governance Initiative) Working paper 002, May, available at http://www.bu.edu/pardeeschool/files/2016/05/Fueling-Growth.FINAL_.version.pdf. Accessed December 12, 2017. 17. K. Sims Gallagher (2016) “The carbon consequences of China’s overseas investments in coal,” CIERP (Center for International Environment & Resource Policy), May, available at http://fletcher.tufts.edu/~/media/Fletcher/Microsites/CIERP/Publications/2016/ CIERPpb_ChinaCoal_HiRes.pdf. Accessed December 12, 2017; S. Snell (2015) “China’s development finance: Outbound, inbound, and future trends in financial statecraft,” US–China Economic and Security Review Commission’s Staff Research Report, December 16. 18. Shardul (2016) “China offers to fully finance Pakistan LNG terminal, pipeline projects,” Natural Gas World, May 14, available at http://www.naturalgasasia.com/ china-offers-to-fully-finance-pakistan-lng-terminal-pipeline-projects-18500. Accessed December 12, 2017. 19. Russia & CIS Oil and Gas Weekly (2016) April 28–May 4, p. 9; N. Buckley (2016) “SinoRussian gas deal: smoke without fire,” Financial Times, May 11, available at http:// www.ft.com/cms/s/0/eea4f2ec-16c0-11e6-b197-a4af20d5575e.html. Accessed December

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152   Handbook of energy politics 12, 2017; J. Marson (2016) “Russian natural-gas project gets funding from China: Move is a hard-fought victory over western sanctions,” Wall Street Journal, April 29, available at http://www.wsj.com/articles/russian-natural-gas-project-gets-fundingfrom-china-1461934776. Accessed December 12, 2017. 20. A. Staalesen (2016) “Big interest in new Arctic LNG – Novatek,” The Barents Observer, June 20, available at http://thebarentsobserver.com/2016/06/big-interest-new-arcticlng-novatek. Accessed December 12, 2017.

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7.  Republic of Korea’s energy security conundrum: the problems of energy mix and energy diplomacy deadlock Se Hyun Ahn

1  INTRODUCTION This chapter explores Republic of Korea (ROK)’s energy security priorities and problems. During President Park’s administration, ROK has faced wide range of energy security problems. Almost all of the nation’s energy diplomatic efforts has virtually stopped to function for mostly domestic political reasons and energy security has been endangered because ROK’s energy security policy has poorly implemented with no concrete goals and no rational choice of energy mix plan. Regardless of ROK’s current energy security policy problems, this study intends to examine ROK’s most urgent energy security agenda at the moment and how the country should response to these specific issues. Before examining the individual energy security issues, this chapter also outlines the exact definition of energy security and how this concept has evolved in the past century. Moreover, this study seeks to highlight ROK’s energy mix policy in detail according to various energy resources. It contends that the current problems of ROK’s energy security and the deadlock of ROK’s energy diplomacy stemmed from the ignorance of the exact definition of energy security at the national level among policymakers, academia, and various political groups including top leadership. In the upcoming decades, ROK’s energy security is likely to experience significant disarray since the nation’s energy security clock has been reset to five years earlier during Park’s administration. There is a grave concern that ROK’s energy diplomacy has lost these five years and will face huge setbacks in the future.

2 ROK ENERGY CONSUMPTION AND DEMAND TREND South Korea is desperately in need of vast amounts of natural resources to keep up with its fast economic growth. Nonetheless, it has very limited 153

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154   Handbook of energy politics domestic sources of energy, and relies almost completely on imports. As an energy-poor country with insufficient natural resources, as Table 7.1 indicates, ROK has an energy import dependency ratio of 96 percent while ranking 10th in the world in energy consumption. Consumption of oil, gas and coal ranks 9th, 16th and 13th in the world respectively, and imports of oil, gas and coal rank 5th, 6th and 3rd in the world. For instance, energy imports as a percentage of total demand rose from 73.5 percent in 1980 to 96.8 percent in 2005. And South Korea imports all of its oil needs. While South Korea remains the world’s fourth largest oil consumer, and at present it is the main fuel used in Korea, demand for oil as a percentage of total energy demand is projected to fall from 53 percent in 2003 to 39 percent by 2030 (Ministry of Trade, Industry and Energy, 2014). 2.1  Global Supply and Demand Conditions Table 7.1 Fossil fuel self-sufficiency rates of the world’s ten largest energy consumers (2011) Ranking

Country

Oil

Gas

Coal

1 2 3 4 5 6 7 8 9 10

China U.S. India Russia Japan Germany France Canada Brazil Korea

0.46 0.46 0.26 3.25 0.00 0.03 0.01 2.12 1.03 0.01

0.78 0.93 0.76 1.41 0.03 0.16 0.01 1.58 0.62 0.01

0.98 1.12 0.77 1.55 0.00 0.60 0.01 1.72 0.14 0.01

Source:  Ministry of Trade, Industry and Energy (2014), p. 52

2.2  Current Energy Consumption The ROK’s average annual growth rate (AAGR) of final energy consumption from 2000 to 2012 was 2.8 percent, as Figure 7.1 suggests. In fact, the AAGR which was 7.2 percent during the 1990s, decreased significantly following the financial crisis in 1998. It is also important to note that the share of energy consumed in the industrial sector has been increasing and currently constitutes more than 60 percent of final energy consumption, whereas the

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Republic of Korea’s energy security conundrum  ­155 100 80 60 40 20 0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 oil

coal

city gas

electricity

heat

others

Source:  Korea Energy Economics Institute (2014).

Figure 7.1  Final energy consumption trend by source portion of the household, commercial, public and transportation sectors decreased steadily (Ministry of Trade, Industry & Energy, 2014). As for oil, the total share of oil in ROK’s final energy consumption reached a record high of 68.2 percent in 1994 but since then began to decrease to 48.4 percent in 2013. Also, ROK’s oil AAGR reached 8.0 percent in the 1990s but also decreased to 1.0 percent in the 2000s. ROK’s oil AAGR by product is as follows: gasoline 1.2 percent, diesel for transportation 1.4 percent, kerosene/light oil 2.9 percent, heavy oil 8.2 percent, naphtha 4.4 percent. Also, oil share by sector is as follows: industry 55.6 percent, transportation 36.3 percent, household/commerce 6.9 percent. Furthermore, excluding feedstock is as follows: industry 14.5 percent, transportation 70.2 percent, household/commerce 13.1 percent (Ministry of Trade, Industry and Energy, 2014). As far as the electricity consumption is concerned, it increased from 10.8 percent in 1990 to 19.3 percent in 2012, primarily because the electricity price in ROK is exceptionally low, compared to other energy resources, and the use of electricity was quite a convenience in ROK. Consumption of city gas in the ROK increased quite dramatically at an AAGR of 30.5 percent in the 1990s, as Figure 7.2 indicates, but this increase also declined somehow to an AAGR of 5.9 percent after 2000 due to saturation of infrastructure. AAGR by sector from 2000 is as follows: industry 9.3 percent, household/commerce 3.6 percent (Ministry of Trade, Industry and Energy, 2014). Coal consumption also gradually began to increase. The share of coal use remained in the 13 percent range in the 2000s, but since then rose up to 15.4 percent in 2012 because industrial coal consumption increased. Moreover,

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156   Handbook of energy politics city gas, 8%

renewable, 2%

renewable, 4% city gas, 12%

coal, 13% electricity, 14%

oil, 63%

coal, 16%

oil, 49%

electricity, 19%

Source:  Ministry of Trade, Industry and Energy (2014), p. 28.

Figure 7.2  Change in energy mix (2001–2012) the share of bituminous coal in total coal consumption, which was 50.4 percent in 1990, increased sharply to 91.8 percent in 2012 due to a decrease in anthracite coal consumption and an increase in the use of bituminous coal for power generation (Ministry of Trade, Industry and Energy, 2014). 2.3  Problems of the Current Energy Policy A general trend of low-price policy motivated by social and economic domestic pressures at the national level has facilitated energy overconsumption patterns and accelerated the social trend toward disproportionate use of certain types of energy, mostly electricity. In particular, exceptionally low electricity price in ROK turned out to be a significant obstacle to the creation of new markets in less economical arenas, such as the renewable energy and smart grid sectors. The current energy mix is also problematic because it did not fully take external environment into account. In this regard, there should be many considerations of external factors including environmental pollution caused by nuclear and coal-fired plants, public safety concerns, opposition from local residents, security costs and so on (Ministry of Trade, Industry and Energy, 2014). 2.4  Basic Direction of the Second Energy Master Plan Transition to demand management policy The ROK’s second energy master plan aimed at demand management policy, more specifically, adjustment of domestic energy prices. Due to the ROK

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Republic of Korea’s energy security conundrum  ­157 1,800 1,600 1,400 1,200 1,000 800 600 400 200 0

heavy oil

Korea

Japan

U.S.A.

Canada

U.K.

Germany Finland

LNG

Mexico

electricity

OECD average

Source:  Ministry of Trade, Industry and Energy (2014), p. 56.

Figure 7.3  International prices for heavy oil, LNG and electricity government’s price liberalization policy, as Figure 7.3 indicates, the price of electricity has consistently been lower than the price of oil, which was taxed at a rate of up to 50 percent, worsening distortions in energy consumption. Another explanation of energy price distortion in energy consumption is that electricity rates do not sufficiently reflect the environmental and social costs of power generation in Korea. For example, even though bituminous coal used for power generation emits more greenhouse gas and pollutants than LNG, LNG is taxed at a rate of 16 percent, while bituminous coal is not taxed at all. Therefore, ROK clearly needs to readjust energy taxation policy. It is essential to impose a consumption tax on bituminous coal used in power generation, and lower the tax on LNG, which is an alternative to electricity. In this respect, industrial uses, such as steel making and cement production, will be exempted from the tax to avoid hampering industrial competitiveness (Ministry of Trade, Industry and Energy, 2014). Enhancement of energy security The ROK government also stressed the reinforcement of overseas resource development, in order to strengthen resource development capability. ROK has been relatively successful in achieving energy quantitative growth. In other words, the amount of oil and mineral resources ­successfully secured increased over a short period of time, as Figure 7.4 illustrates. Nonetheless, there are still limitations such as excessive ­emphasis on quantitative growth; weakened investment efficiency and insufficient infrastructure for growth. Therefore, ROK’s second energy master plan focuses on the following four specific goals, in order to enhance its national energy security:

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158   Handbook of energy politics Table 7.2  Current and new policy paradigm Current Policy Paradigm

New Policy Paradigm

Policy Target

Secure larger amounts of overseas resources [enlargement of public enterprises]

Key Player Funding

Public enterprises Financed mainly by public enterprises M&A buying shares in production fields

Improve the government’s capability to develop resources [strengthening industrial competitiveness and creating jobs] Public and private enterprises Financed mainly by the private sector Securing operating licenses in exploration fields

Method

Source:  Ministry of Trade, Industry and Energy (2014), p.110

1. Enhancing capabilities for long-term energy security 2. Strengthening the foundation of public energy enterprises 3. Promoting private sector investment in overseas resource development 4. Strengthening industrial infrastructure by training high-quality workers and conducting practical R&D (Ministry of Trade, Industry & Energy, 2014). Establish a stable supply system for each energy source The ROK government’s energy plan also emphasizes the establishment of a stable supply system for each energy resources. ROK relatively, as illustrated in Figure 7.4, secured a stable supply of conventional energy sources, such as oil and gas. More specifically, the second energy master plan aims at diversifying the existing energy routes and expanding domestic stockpiling capacity. As for oil, ROK hopes to reduce dependence on certain oil exporting countries by diversifying oil import routes, and also to improve the industrial structure by establishing a Northeast Asia oil hub within the Korean Peninsula. The ROK government also focuses on the following goals: responding aggressively to changes in the global market, such as the emergence of shale gas, and expansion of the supply infrastructure for domestic stockpiling (Ministry of Trade, Industry and Energy, 2014). Nonetheless, the government also needs to keep up with five megatrends of the global energy market.

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Republic of Korea’s energy security conundrum  ­159 Self-sufficiency rate in oil and gas (%) 16 14 10.8

10 9

8 6 4 2 0

13.8

13.7

12

5.7 4.1 2005

3.2 2006

4.2 2007

2008

2009

2010

2011

2012

Self-sufficiency rate in major mineral resources (%) 35 30 25 20 15 10

16.6

14.6

18.5

23.1

25.1

27

29

32.1

5 0

2005

2006

2007

2008

2009

2010

2011

2012

Source:  Ministry of Trade, Industry and Energy (2014), p. 110.

Figure 7.4  Self-sufficiency rate 2.5  Oil and Gas Supply and Demand Projection Oil Global short-term oil supply and demand is anticipated to improve, and mid- to long-term supply and demand is expected to remain stable. ROK’s future oil supply–demand balance is expected to remain stable in the mid- to long-term. In the domestic context, for the short-term oil demand increase is due to an increase in the use of feedstock, such as naphtha, for industrial purposes and an increase in demand from the transportation sector with about 1.1 percent growth in 2014, despite the downward trend in demand for oil for heating and power generation. In the mid- to long-term, meanwhile, as Table 7.3 and Table 7.4 ­illustrate, due to a continuous decrease in demand from non-transport sectors, total oil demand is projected to fall from 2020 at an average

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160   Handbook of energy politics Table 7.3 Forecast by source: Total primary energy demand (business-asusual (BAU)) (million toe) Source

Coal (share %) Oil Natural gas Hydro Nuclear Renewable &   others Total

2011

2025

2030

2035

Average Annual Growth Rate (%)

83.6(30.3) 100.2(28.3) 107.7(29.1) 112.4(29.7) 105.1(38.1) 111.0(31.3) 107.1(29.0) 101.5(26.9) 46.3(16.8) 64.8(18.3) 69.8(18.9) 73.3(19.4) 1.7(0.6) 1.7(0.5) 1.9(0.5) 2.0(0.5) 32.3(11.7) 59.6(16.8) 65.3(17.7) 70.0(18.5) 6.6(2.4) 16.8(4.7) 18.0(4.90) 18.8(5.0)

1.24 –0.15 1.93 0.70 3.28 4.44

275.7(100.0) 354.1(100.0) 369.9(100.0) 377.9(100.0)

1.32

Source:  Ministry of Trade, Industry and Energy (2014), p. 44.

Table 7.4 Forecast by source: Final energy consumption (business-asusual (BAU)) Source

(million toe) 2011

2025

Coal (share %) 33.5(16.3) 37.4(15.0) Oil 102.0(49.5) 109.1(43.9) City gas 23.7(11.5) 32.5(13.1) Electricity 39.1(19.0) 59.7(24.0) Heat energy 1.7(0.8) 2.9(1.2) Renewable 5.8(2.8) 7.1(2.9)  (nonelectricity) Total 205.9(100.0) 248.7(100.0)

2030

2035

Average Annual Growth Rate (%)

38.8(15.3) 105.1(41.3) 34.4(13.5) 65.6(25.8) 3.1(1.2) 7.4(2.9)

38.6(15.2) 99.3(39.1) 35.3(13.9) 70.2(27.6) 3.3(1.3) 7.4(2.9)

0.58 −0.11 1.68 2.47 2.82 1.01

254.3(100.0) 254.1(100.0)

0.88

Source:  Ministry of Trade, Industry and Energy (2014), p. 45.

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Republic of Korea’s energy security conundrum  ­161 annual rate of 0.15 percent to approximately 773.9 million barrels by 2035. For example, ROK’s domestic oil dependency is decreasing, as Table 7.3 suggest, 52.0 percent (2000) → 38.1 percent (2011) → 34.1 percent (2020) → 26.9 percent (2035) (Ministry of Trade, Industry & Energy, 2014). Natural gas In general, the Asian natural gas demand is expected to grow, and the supply of natural gas is also expected to increase due to shale gas revolution in North America. As Table 7.3 indicates, ROK’s domestic demand for natural gas has also gradually increased at an annual rate of 7.9 percent over the past ten years due to increasing popularity of city gas and increased gas demand for power generation and industrial use. For example, ROK’s domestic natural gas demand increased as follows: 18.45 million tons (2003) → 23.50 (2006) → 24.64 (2009) → 36.55 (2012). ROK’s mid- to long-term gas demand will be much increased because of high demand for the industrial and transport sectors use. Moreover, gas demand will be very attractive because ROK’s domestic gas demand for the power generation sector will depend on greenhouse gas emission reduction aims, base load power reserve ratios and so on (Ministry of Trade, Industry and Energy, 2014). 2.6  Alternative Energy During the 1970s, Korea invested in “Alternative Energy” but failed to proceed due to a number of limitations (Kim et al., 2012). In 1987, Korea enacted the “Alternative Energy Development Promotion Act,” and launched the new renewable energy technology development projects in 1988 (So, 2011). Yet the IMF crisis in 1998 downgraded the importance of alternative energy and delayed nation’s alternative energy program. Recently, however, in 2008 Korea has reestablished the “third basic energy plans for renewable energy technology development,” and increased the government budget for renewable energy, as illustrated in Table 7.5. Moreover, the government is currently developing various plans for the promotion of renewable energy industry, as Table 7.6 demonstrates. The plan set the goal of boosting the use of alternative energy with 3.5 percent in 2012; 6.1 percent in 2020 and 11 percent in 2030 respectively. Until 2030, the core strategy of the plan was to promote R&D related to industry, to expand industrial infrastructure by enhancing fuel efficiency as well as maintaining low cost. The ROK Ministry of Trade, Industry and Energy has been in charge of the renewable energy program and the Alternative Energy Center for the task of the office of Energy and Resources within the Korea Energy Agency has been also supporting this program.

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162   Handbook of energy politics Table 7.5  ROK Government budget for alternative energy Project name

(Won: a hundred million) 2007 2008 2009 2010 2011 2012

Total Alternative energy technology development Supply business for alternative energy Support for development differences Supply loan

4,350 5,326 6,877 7,958 9,283 8,309 1,326 2,079 2,445 2,520 3,125 2,306 1,541 1,431 1,637 1,202 1,290 1,340 270 513 1,492 3,318 3,950 3,950 1,213 1,303 1,303 740 918 713

Source:  Kim et al. (2012), p. 80.

From 2011 to 2015, photovoltaic (PV) and wind power oriented investment plan launched with 33 trillion Won. This plan includes PV with about 20 trillion, wind power with about 10 trillion, fuel cell with about 1 trillion, as well as bioenergy with about 1 trillion Won. As Table 7.6 ­indicates, in particular, the supply portion of PV between 2005 and 2013 has astronomically increased. Moreover, the third basic plans aimed at establishing grounds for short-term commercialization of renewable energy within five to ten years, and replacing energy sectors by renewable energy with securing core technology in the long term. Also, another objective of third basic plans is to promote private led of renewable energy industry (So, 2011). In fact, RPS (Renewable Portfolio Standards) which was a government’s mandatory policy of substituting alternative energy for certain amount of electric power production came into effect in 2012. This policy focused upon reducing CO2 emission and expanding the market size, while enhancing competitiveness for alternative energy. In 2012, the electricity supplier had to substitute alternative energy for 2 percent of the total electric power production. And this ratio must be increased by 10 percent until 2020. It is expected that the electricity supplier must abide by the rules in order to increase the proportion of renewable energy for the national power generation (see http://www.ecotiger.co.kr/news/ articleView.html?idxno=14499 9 September 2015). Besides that, RPS is demanding the supplier’s obligation through the policy improvement, gathering opinions from experts and managing the market with the supply certificate, monitoring the proper use or illegal abuse of equipment (Nam, 2013).

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163

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4,879.20 2.1 34.7 3.6 181.3 3,705.50 918.5 32.5 2.6 0.5 –

5,225.20 2.2 33 7.8 274.5 3,975.30 867.1 59.7 6.2 1.7 –

2006 5,608.80 2.4 29.4 15.3 370.2 4,319.30 780.9 80.8 11.1 1.8 –

2007 5,858.50 2.4 28 61.1 426.8 4,568.60 660.1 93.7 15.7 4.4 –

2008

2009 6,086.20 2.5 30.7 121.7 580.4 4,558.10 606.6 147.4 22.1 19.2 –

Source:  http://www.index.go.kr/potal/main/EachDtlPageDetail.do?idx_cd=1171.

Supply Supply percent Solar heat PV Bio Waste Water power Wind power Geothermal Hydrogen fuel cell Marine resources

2005

Table 7.6  The present state of alternative energy supply

6,856.30 2.6 29.3 166.2 754.6 4,862.30 792.3 175.6 33.4 42.3 0.2

2010 7,582.80 2.8 27.4 197.2 963.4 5,121.50 965.4 185.5 47.8 63.3 11.2

2011

8,850.70 3.2 26.3 237.5 1,334.70 5,998.50 814.9 192.7 65.3 82.5 98.3

2012

2013 9,879.20 3.5 27.8 344.5 1,558.50 6,502.40 892.2 242.4 87 122.4 102.1

(thousand toe)

164   Handbook of energy politics 2.7  Natural Gas In the mid-1980s Seoul introduced governmental tax incentives to promote widespread use of natural gas. In the course of fast expansion of South Korea’s natural gas industry from 1987 to 2002, ROK established a nationwide trunk pipeline network, which has made ROK one of the global most dynamic gas markets. Natural gas continued to grow in ROK, both because of its convenience and because of environmental merit. Accordingly, it is anticipated that gas demand in ROK is to grow by 150 percent, from 20 billion cubic meters (bcm) in 2000 to 53 bcm by 2020. Currently, ROK is the second largest importer of liquefied natural gas (LNG) next to Japan. And ROK is also home to the world’s largest LNG importer, Korean Gas Corporation (Kogas). Kogas has a monopoly over all of ROK’s gas imports, which thus far are entirely in the form of LNG. This generates some social agenda at home from the energy security aspect. Thanks to privatization efforts started in 1999, ROK has allowed POSCO (a large steel maker) to make a rare “spot” purchase of 500,000 tons of LNG in 2006. POSCO and K-Power have also signed a long-term LNG contract in 2004 for 550,000 and 600,000 million tons respectively of LNG from Indonesia’s Tangguh project delivered by the end of 2008. KOGAS’ imports have traditional came from Southeast Asia, but purchased a great deal of volume from Qatar and Oman, and additionally made a contract with the U.S. shale gas in 2012 (Ahn and Jones, 2008). KOGAS’ purchase of Southeast Asian volume has gradually decreased. For example, Indonesia is an example of such doubt. Much of ROK’s LNG in the 1990s came from Indonesia; however, the future of Indonesia’s LNG industry is uncertain. Due to a lack of favorable investment policies and general resource nationalism, this OPEC country became a net importer of oil in 2004 and plans to further develop its LNG for export is currently in limbo. An overall push to develop a domestic gas market is emerging to make up for this energy gap. Indonesia already has to import LNG from other countries in order to meet its existing long-term supply contracts. Therefore, ROK decided to increase the LNG volume from the Middle East. South Korea began to import LNG from Oman, Yemen and Qatar in the late 1990s. By 2020 a significant portion of Korea’s LNG imports will be delivered from the Middle East, especially Qatar volume. Accordingly, it is important to point out that South Korea’s LNG will increasingly have to travel long distances through world energy choke points such as the Hormuz and Malacca straits. Moreover, the Middle Eastern liquefaction capacity is short these days. In other words, ROK’s traditional LNG sup-

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Republic of Korea’s energy security conundrum  ­165 pliers such as Yemen, Oman and the United Arab Emirates have all virtually exhausted new supplies. And even Qatar, which is the world’s largest LNG exporter, allegedly has already produced approximately 80 percent of its potential LNG supplies. These shaky Middle Eastern options make the U.S. and Russia extremely attractive sources of gas for ROK. At the moment, ROK purely relies on LNG, so the Russian gas pipeline and the U.S. shale gas would definitely help South Korea diversify its sources of gas. For Korea, the Russian PNG is extremely attractive as it could diminish risk among the multiple parties involved (both government and private), compared with bilateral LNG deals. Both Russian and the U.S. gas can balance its reliance on tanker gas coming from Qatar (Ahn and Jones, 2008).

3  THE NEW ENERGY SECURITY CONCEPT It is essential to point out that not many people realize the exact meaning of the concept of energy security. This is considered to be one of the major energy security threats both inside and outside the country. The ignorance of this particular term generates for the national leader to take irrelevant and irrational energy security decision-making, and this also leads to the failure of domestic energy policy and energy diplomacy. Energy security is an important element of national and regional security today. It is a strategic factor in ensuring the economic development and stability of states. Because of the “increasing importance of traded energy, increasing dependence on Middle East Oil, no sign of slackening demand rise, continuing volatility of oil prices, and environmental and sustainability concerns,” energy issues are an increasingly important part of the security agenda in international relations in general (Andrews-Speed, 2003). Energy security is defined as the securing of reliable and affordable energy supplies that are sufficient to support social, economic and military needs, while at the same time being environmentally sustainable (Doh, 2003; Willrich, 1975). Willrich defines energy security as, first, the guarantee of sufficient energy supplies to permit a country to function during a war; and second, and more broadly, the assurance of adequate energy supplies to maintain the national economy at normal levels. He argues that the first definition is too restrictive, and the second too permissive and expansive. Therefore, he proposes that for most purposes, the definition of energy security as the securing of reliable and affordable energy supplies that are sufficient to support social, economic, and military needs, while at the same time being environmentally sustainable is the most plausible approach (Willrich, 1975). More specifically:

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166   Handbook of energy politics in a state which enjoys energy security, consumers and their governments are able to believe that there are adequate reserves from sources at home or abroad, and production and distribution facilities available to meet their requirements in the near future, at costs that do not put them at a competitive disadvantage or otherwise threaten their well-being. (Lieber, 1980; Deese, 1979)

In other words, energy security emphasizes economic factor, which is namely, affordable prices. On the other hand, energy insecurity arises when the welfare of citizens or the ability of governments to pursue their other normal objectives are threatened, either as a result of physical failure of supplies or as a result of sudden and major price changes (Belgrave et al., 1987). In this sense, it can be argued that energy security constitutes an important part of economic security because it is the core prerequisite for sustainable development (Doh, 2003). In traditional terms, one way to estimate the level of energy security is to measure the extent to which a country is dependent on particular types of energy and whether these can be obtained within its territory or must be imported. In the latter case, a second question emerges relating to the level of the dependency, the diversity of foreign sources, the relative vulnerability of the source areas to political turmoil and hostile control. Similar questions apply to transportation routes and carrying systems. In the end, as most people realize, the energy security of a state is evaluated by its level of self-sufficiency and its ability to adapt to temporary and prolonged supply interruptions without serious economic and military consequences (Stares, 2000). More specifically, a useful distinction can be made between energy importing and exporting countries. An importing country is primarily concerned with the security of its energy supplies. However, each ­importing country tends to view foreign energy supplies as more or less vulnerable to interruption (Willrich, 1975). Although interruptions, disruptions and manipulations of existing supply arrangements can be caused by accidents and natural disasters, they are more vulnerable to potential political instability, economic coercion, military conflict and terrorist acts. These concerns apply not only to the source of energy supplies but also to the routes and means by which they are transported (Yergin, 1998; Stares, 2000). Energy exporters, on the other hand, are concerned with access to markets and security of demand. An exporting country may perceive energy security as national sovereignty over its energy resources, or it may view it more broadly as sovereignty over resources plus guaranteed access to foreign markets (Willrich, 1975). Moreover, an exporter may view security as sovereignty plus market access plus financial security for the assets it receives in exchange for energy raw materials. An exporter may

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Republic of Korea’s energy security conundrum  ­167 adopt, as a result of sovereignty over its basic raw materials, a concept of energy security that includes guaranteed access to foreign markets. In short, demand security may be as important to energy exporters as supply security is to importers. As Willrich notes: this raises possibilities for mutually beneficial negotiations between exporters and importers, based on overlapping areas of interest in stability and equilibrium. In addition to sovereignty and market access, an exporter may extend the concept of energy security to cover financial security for the investments made with its export earnings. This scenario may seem exaggerated but energy resources below ground are a precious national heritage. Once extracted, that heritage can easily be lost by an improvident government or eroded by ­inflation. (Willrich, 1975)

What seems to be more important about energy security these days is that the concept of energy security is no longer confined to the term “access” or “diversification.” These two concepts were the primary issues during the 1920s and 1960–70s, as previously mentioned. The millennium concept of energy security stretches far beyond access and diversification. It expands up to the resilience, integration, not to mention information. Moreover, the national government’s energy diplomatic skill is also another important component of energy security these days. This includes the political leaders’ basic knowledge about energy security and tactics of energy diplomacy and energy mix plan. It is quite stunning to point out that a number of national leaders are not quite familiar with the exact concept of energy security, which is considered to be national energy security threat for the longer term. More important, energy diplomacy is a part of energy security these days. In other words, the notion of energy security is no longer separate from energy diplomacy.

4  ROK’S ENERGY SECURITY OBJECTIVES 4.1 What is the Most Important Current Issue and How is the Country Trying to Solve it? From the ROK perspective, the primary objectives of energy security are as follows: 1) The ROK government hopes to implement the nation’s smart future power mix plan. ROK has promoted the use of nuclear power and renewable energy in the past few years despite the Fukushima disaster. Nonetheless, this has turned out to be a major policy failure. This is

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168   Handbook of energy politics the prevailing consensus among energy experts in Korea. It is essential for the ROK government to turn to more natural gas use considering the recent dramatic increase of micro dust in the nation in the past few years. Also, the country must reconsider its most recent energy policy of building additional nuclear power plants, and definitely should cut down the use of coal. ROK’s energy mix policy will be more elaborated in the later part of this chapter. 2) How to frame DPRK energy security and thus how to prepare for the energy security framework for the possible reunified Korea is one of the ROK government’s most important energy security objectives. DPRK’s energy security has completely broken down for the past several decades and is desperately in need of foreign assistance at the moment. Accordingly, natural gas remedy seems to be a perfect solution to DPRK due to its diverse supply options either from Russia or from the North American states. It is essential to point out that DPRK’s energy security issue should not be accounted from the commercial perspective but the larger geopolitical framework in the longer term (Ahn, 2013c). 3) Accessing the Russian oil and gas in the Eastern Siberian region is another key component of ROK’s major energy security priority. In fact, ROK is located between energy continental power group and sea power. And following the recent shale gas revolution, ROK was actively courted by both sides to join their alliance. In particular, Eastern Siberia is a very promising region because of its short distance advantage, just as Russian–German energy rapprochement demonstrated in the past few decades. Recently, natural gas pipeline project linking two Koreas and Russia has been actively brought to the diplomatic table, and still remains the focal point of Northeast Asian energy security cooperation. At the same time, Sino-Russian energy relations should be carefully examined and analyzed in detail to understand the current Northeast Asian energy flow. It is crucially important to point out that Korea is the perfect energy partner for Russia more than China, Japan and India. Energy cooperation between Russia and South Korea is extremely important but both sides are not moving as fast as they should be. Gas from Russia’s Eastern Siberian field has the potential to not only drastically reduce Northeast Asia’s energy shortage but also help diversify Northeast Asia’s traditional sources of energy from the Middle East and Southeast Asia.   Until now, however, the potential for Russian natural gas reaching any Northeast Asian country including ROK, however, has been delayed for almost two decades due to the following reasons:

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Republic of Korea’s energy security conundrum  ­169











● Delayed

gas price negotiation between Russia and China in 2007 and 2008: oil cooperation is relatively smooth yet gas still remains problematic in Northeast Asia. Nonetheless, gas flow is more important to Korea, China, Japan and Russia than oil, since gas is a global and regional energy phenomenon. ● Asset disputes between Gazprom and BP-TNK; and Gazprom and Rosneft: the Korean government welcomed Gazprom’s complete takeover of Kovykta’s asset because it would facilitate the government to develop of gas project more quickly. And yet, power struggles within the Kremlin turn out to be the key delay to Russian gas reaching to Northeast Asia. In fact, Putin prefers Rosneft with Igor Sechin to Gazprom with Alexey Miller. ● Global economic crisis was the major hurdle for energy cooperation between Russia and South Korea in the late 1990s. ● The politics of route determination and the primary discussion of Russian gas transfer to Northeast Asia have been very sensitive issues. Although to route the pipeline via North Korea and Mongolia would economically make more sense, government and private sector sensitivities have led to proposed routes that circumvent the two countries thus driving up costs of any such pipeline. And yet transit country discussion still remains the focal point of pipeline gas mechanism. ● Confidence and gas investments. Natural gas is genetically more difficult to trade than oil and requires much more confidence, guarantees and money from investors and governments. In this respect, the lack of confidence among states in the region diminishes the possible natural gas collaboration. ● China factor. China’s market is key to Russian PNG success but not a necessary condition. Despite plans for further gas market development, however, China’s reliance on Turkmenistan, Kazakhstan, Myanmar and Australia has led to a soft market for relatively high-priced gas. And yet, China–Russian gas cooperation is the main key for Russian gas transfer to Asia. In other words, it is highly unlikely to anticipate Russian gas flow to Asia without the Chinese market (Ahn and Jones, 2008). ● The Kremlin’s resource diplomacy. Rising oil prices have traditionally given Russia impetus to use energy as a political weapon. In Eastern Europe, the near abroad or elsewhere except Western Europe, Russia tended to pull political strings in the course of gas diplomacy. East Asia still perceives Russia as a bugbear in the gas transfer.

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170   Handbook of energy politics 4) How to build further strong energy alliance with the U.S.: ROK and the U.S. could elevate current strong alliance beyond the level of special energy alliance through free trade agreements between the two sides. In particular, two sides could tighten energy alliance with the transfer of the U.S. natural gas and crude oil. Perhaps the U.S. could use Korean natural gas terminals to expand its Asian export market in the longer term. Moreover, South Korean nuclear technology transfer to the U.S. has emerged as promising energy cooperation between the two sides. And bilateral cooperation over electric and natural gas vehicle production and technology transfer also remains one of the greatest potentials. 5) How to establish a global oil and gas hub in the Korean Peninsula: Korea is where a massive amount of Russian gas and North American gas will be imported simultaneously in the future. It posits a perfect location to build a global scale of natural gas import and export station, especially on the east coast of country. Despite the harsh competition from China and Singapore, and domestic skepticism, the ROK government still considers this opportunity as the focal point of its regional energy cooperation initiative. 6) How to design the nation’s energy diplomacy and  security policy effectively: a proper energy security program should be introduced at each level of energy governance: presidential leadership, congress, ministry and military. Leaders in the Korean Peninsula are clearly lacking in the exact concept of energy security and this often misleads national energy policy. Otherwise, it is highly likely that ROK’s energy diplomacy momentum will be completely lost for five years. 4.2  What are the Biggest Foreseen Challenges in the Near Future? Within the realm of energy cooperation in Northeast Asia, the major concern is that politics always outplay economics. In other words, political huddles including the inherent complexities of Northeast Asian relations such as the balance of power relations among China, Russia and the U.S.; the lack of mutual trust between nations; DPRK nuclear proliferation; estranged ROK–Japan relations, all hinder further energy cooperation in the region. Moreover, the general lack of understanding of the proper concept of energy security among Northeast Asian top leaders is also prevalent. The new threat of nuclear power plants as well as nontransparency of the energy industry and market in certain countries still remain potential challenges for the region to ensure future energy security.

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Republic of Korea’s energy security conundrum  ­171 4.3 What Role does the U.S.–Japan–Korea Alliance Play in the Country’s Energy Security? In comparison with the Sino-Russian energy alliance or the potential SinoRussian-Korean energy alliance, the U.S.–Japan–Korean energy alliance could create a more reliable and predictable energy market system based upon the decades of strong political and military cooperation. Specific elements of energy alliance cooperation may include natural gas (shale gas) transfer and the collaboration over the gas related industry such as gas automobile industry. In this sense, it is essential to anticipate possible U.S crude oil transfer to Japan and Korea through free trade agreement settings. 4.4  Off-Shore Resource Development There is also interest in development of offshore energy resources in Japan and the ROK. What impact does this have on energy policy and cooperation among the three countries (and others)? Quite frankly, there is no active offshore energy resource development in the Korean offshore area at this stage. Indeed, there are massive gas hydrate reserves in Dokdo Island in the East Sea and Sector 7. Unless the current conflict between ROK and Japan resolves, however, it is quite difficult to see further energy cooperation between the two sides. Nonetheless, the U.S. is very keen on Sector 7 development since this project could give Korea more impetus to engage in both the East China Sea and South China Sea. There was also a brief idea of a natural gas co-buying scheme right after the Fukushima disaster, yet the plan was abandoned because of no actual practical benefit. Perhaps the three nations could work on framing energy security in the DPRK including oil exploration in the DPRK offshore area instead. Furthermore, they could work on energy transport related sea route safety regulation activities or sea lane communication issues as well as nuclear safety regulation in the future. Finally, once again, it is essential to examine the current development of and obstacles to Sino-Russian energy relations as well as the possible energy transfer among China, Russia and the Korean Peninsula. The U.S., Japan and Korea need to implement a proper energy strategy in order to form a new energy alliance among them.

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5  ENERGY DIPLOMACY There are a number of problems for South Korea’s energy diplomacy. Under Park Geun-hye’s administration, most energy diplomacy activities virtually stopped. There are two explanations for this failure. First, energy security is simply missing from the agenda of top leadership including the legislative, judicial body and the presidential office. ●

An energy security education program must be introduced. Politicians are seriously in need of learning the true concept of energy security. ● Energy security should not be a part of party politics or election agenda, even though it is a tempting and lucrative political agenda. ● It is the most important element of national security. ● Yet, Korean leadership seem as though they are unaware of the importance of energy security. Second, energy was highly politicized in South Korea. From the beginning of her term, President Park really wanted to distance herself from the former Lee Myung-bak administration in terms of energy policy, after which there were a number of energy related scandals and corruption charges revealed. Accordingly, a number of energy companies are still under government inspection and every energy business activity led by state energy companies are primary targets for annual government inspection. From an energy security perspective, excessive government intervention in energy diplomacy or activities are not considered to be desirable because with too much government inspection and regulation, it is highly likely that the energy market or energy diplomacy will begin to malfunction. Nonetheless, South Korea’s primary objective of energy diplomacy is diversification of the energy import market. This comes in the form of four different channels: the Middle Eastern oil and gas; Southeast Asia; Russia and the former Soviet Union; and the new North American gas market. It is essential to point out that the ROK government desperately needs to keep up with the five megatrends of the global energy market. At the same time, it recently also set up a few specific energy policy goals for Northeast Asian energy cooperation: 1. How to frame or ensure energy security in North Korea. 2. How to establish Northeast Asian oil and natural gas hub facilities in the Korean Peninsula.

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Republic of Korea’s energy security conundrum  ­173 3. How to set up multilateral framework for the safety of nuclear power generation: TRM (Top Regulators’ Meeting) and TRM plus. TRM guides nuclear power safety among China, Japan and South Korea.

6  ENERGY POWER MIX Korea’s most recent energy power mix plan is too much oriented toward nuclear power generation and renewable energy. Korea, just like Japan, depends on foreign energy resources: the rate of current energy independence is only 3 percent. This includes hydropower, anthracite and a small segment of renewable energy. Other than that, as previously mentioned, Korea imports most of its energy including oil, coal and natural gas. Nonetheless, Korea’s current energy mix is generally perceived as stable for the global standard because energy resources for power generation were diversified, compared with the early 1980s when oil was the primary energy. Now, coal, nuclear power and natural gas replaced oil for power generation. In short, external factors, mostly the global energy market situation and specifically energy price have been the most dominating forces or variables to determine Korea’s energy power mix plan. Most recently, however, four domestic constraints have caused problems for the energy power mix: 1. Korea’s overdependence on nuclear power generation. 2. The Korean government did not keep up with the megatrends of the global energy market. It did not consider the natural gas boom, underestimating the importance of natural gas. 3. It overvalued the capacity of renewable energy, which is neither base load energy like nuclear power or coal nor peak load energy like LNG. 4. The lack of energy reform, specifically regarding energy price and energy taxation. Korea’s energy reform is much outdated. In other words, the energy industry needs to be restructured and significantly reform (Ryu and Ryu, 2013). Moreover, in Korea there are too many government-directed energy plans such as basic energy planning; power supply and demand basic planning; long-term natural gas supply and demand planning; renewable energy planning; energy utilization basic planning; and global energy diplomacy strategic planning. And the problem is that each of these energy planning initiatives are not interconnected: they were planned separately with no consideration of other planning. Therefore, the ROK government

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174   Handbook of energy politics ­ esperately needs to bring all of these plans together. In the most recent d Korean basic national energy power mix plans (numbers six and seven), natural gas use was not even taken into consideration (Ryu and Ryu, 2013).

7  ENERGY SCANDAL South Korea depends heavily on its self-generated nuclear power. However, a nuclear scandal took place in South Korea, when the country faced a series of nuclear reactor shutdowns because of fake warranty documents a few years ago. This incident was exposed to the public during September 2013’s nationwide blackout period. This scandal demonstrates corruption at the Korea Hydro and Nuclear Power (KHNP), the state-run company that was responsible for the operation of the country’s nuclear power plant. Through this nationwide scandal, the deep ties between KHNP and the related industry was revealed. And these were labeled as the nuclear mafia, generating serious social and technology problems. Specifically, a number of illegal activities such as putting fake warranties into substandard parts of reactors and failed safety checks of control cables for emergency shutdown reactors were exposed. The fake documents dated back to 2012. During November 2012, two nuclear reactors were suspended after it was discovered that the parts were supplied with these fake certificates. Also, on October 10, 2013, South Korea indicted about 100 people, including a top former state utility official with the charges of scandal. Officials further noted that they will take those reactors that were suspended for inspection and replacement of parts. Moreover, on February 7, 2014, the Nuclear Safety and Security Commission declared that during its investigation, they found eight cases out of 2,075 samples of foreign manufactured reactor components that were supplied with fake documents. The names of dealing countries remains undisclosed. It is equally interesting to point out that this phenomenon is prevalent throughout the world. After the Fukushima disaster, many energy experts had already anticipated that nuclear power will eventually return to favor because of strong ties between the state and industry which had persisted for several decades. In fact, a nuclear Watergate incident is just the tip of the iceberg of energy industry corruption throughout the world. Traditionally, there has been a strong bond established between politics and the energy industry. It is really difficult to crush this invincible fortress which had been consolidated over the last century. It substantially

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Republic of Korea’s energy security conundrum  ­175 controls the global energy market and politics, and is deeply engaged in many energy related activities: creating energy companies, deciding oil and electricity price, controlling national power plants and energy company mergers and acquisitions. Most importantly it is deeply involved in all kinds of national election processes. And it is striking to point out that some environmental groups actually support nuclear power generation since nuclear power plants produce low CO2 emissions. Despite the Fukushima disaster, especially in East Asia and the United States, with the help of notions of climate change, nuclear power generation has become fashionable again because of its zero greenhouse gas emission.

8  CONCLUSION This chapter reviewed the ROK’s current energy security priorities and problems as well as its energy mix plan. This study revealed that under President Park’s administration, ROK has faced a number of energy security problems at the national level. The nation’s energy diplomacy has virtually stopped for mostly domestic political reasons. Furthermore, the ROK’s policy has endangered its energy security, for example, an energy master plan was poorly executed with no concrete set of goals and with no rational choice of which energy is more important than another. Nonetheless, this study outlined the ROK’s most urgent energy security task and how the country should respond to these specific issues. This paper argues that the current problems of ROK’s energy security and the recent deadlock of ROK’s energy diplomacy stemmed from the general ignorance of the exact definition of energy security at the national level among energy policymakers, political groups including top leadership, interest groups, academia as well as media. In the face of harsh political turmoil and perhaps at the time of the most divided national public opinion in ROK’s history, energy security has also become the most sensitive and provocative political agenda in domestic politics. Hence, not a single national energy company dares to expand its new energy business abroad at the moment. Nor do relevant energy policymakers in the ROK’s government want to discuss energy security policy. This is even more depressing when we see how Japanese and Chinese leaders are aggressively pushing their energy diplomacy, especially given the current low global oil price. ROK top officials are simply concerned with CO2 emission and renewable energy, while not realizing the importance of natural gas and the true meaning of energy security. Unless there is a

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176   Handbook of energy politics revolutionary change in the thinking of the new energy security concept, it is highly likely that ROK will face significant disarray in the next few decades. It is essential to point out that national leaders, parliament members and energy policymakers should keep up with global energy megatrends. And most importantly, energy security policy and energy diplomacy should be depoliticized in the ROK as soon as possible. It is even more worrying to see national leaders in the Blue House, the National Assembly and the prosecutor’s office regarding energy security issue as a political decoy or public hatred issue. In conclusion, it is even more important to understand that energy diplomacy is the continuation of domestic energy security, and energy diplomatic skill is an important component of today’s national energy security. It is equally important for political leaders to remember that the notion of energy security does not any longer only mean diversification or access. It should also include national leaders’ basic knowledge, vision and the capacity to understand the nexus between energy and security.

ACKNOWLEDGMENT This chapter is reprinted in Se Hyun Ahn (2015) “Republic of Korea's energy security conundrum: The problems of energy mix and energy diplomacy deadlock,” Journal of International Area Studies, 22 (2), 67–87.

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178   Handbook of energy politics Lee, S.K. (2011) “Russian energy expert, Korea Energy Economics Institute, Seoul, Korea,” personal interview, Seoul, September 19. Lee, Y-S. (2011) “A study on activation strategies of mass energy business with new and renewable energy,” Energy Economics Institute. Lieber, R.J. (1980) “Energy, economics and security in alliance perspective,” International Security, 4 (4). Ministry of Trade, Industry and Energy (2014) “Korea energy master plan: outlook & ­policies to 2035,” Ministry of Trade, Industry and Energy. Nakano, J. (2015) “Center for International Strategic Studies, Washington, DC, USA,” personal interview, Washington, DC. December 4. Nam, G-W. (2013) “A policy on new and renewable energy,” The Korean Solar Energy Society. Normal, J. (2009) The Oil Card: Global Economic Warfare in the 21st Century, Walterville, OR: Trine Day LLC. Paik, K.W. (2013) “Interview,” Oxford Energy Institute. Oxford. January 30. Reisinger, W. (1992) Energy and Soviet Bloc, Ithaca: Cornell University. Ryu, J.C. and K.H. Ryu (2013) “Policy implication on stable mid-term and long-term energy mix,” The Institute for the Future of the State Policy Report, October 15, available at http://www.ifs.or.kr/modules/board/bd_view.asp?no=114&ListBlock=&gotopage=1&Pa gecount=1&sk=bd_title&sv=&id=research&ca_no=16&mncode=&left=&top=&author =&top=2, accessed October 19, 2013. So, J-Y. (2011) “A study on improvement strategies of regional supportive policy on new and renewable energy,” Energy Economics Institute. Stares, P.B. (2000) “Introduction and overview,” in P.B. Stares (ed.) Rethinking Energy Security in East Asia, Tokyo: Japan Center for International Exchange. Venn, F. (1986) Oil Diplomacy in the Twentieth Century, New York: St. Martin’s Press. Willrich, M. (1975) Energy and World Politics, New York: The Free Press. Yergin, D. (1988) “Energy security in the 1990s,” Foreign Affairs, 67 (1), 111–32. Yergin, D. (2008) The Prize: The Epic Quest for Oil, Money and Power, New York: Free Press. Yergin, D. (2006) “Ensuring energy security?” Foreign Affairs, 85 (2). Yergin, D. (2011a) Author’s interview, Washington, DC, July 5, 2011. Yergin, D. (2011b) The Quest, New York: The Penguin Press. Statistics Korea (2014) “The present state of alternative energy supply,” available at http:// www.index.go.kr/potal/main/EachDtlPageDetail.do?idx_ cd=1171, accessed September 9, 2015.

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8.  China’s evolving energy policy: the case of electricity Philip Andrews-Speed and Sufang Zhang

INTRODUCTION This chapter examines the evolution of China’s energy policy since 1949 using the electricity industry as an example. This industry provides key insights into energy policymaking and implementation on account of its central role in supporting the nation’s modernization and economic growth, as well in addressing other key priorities such as poverty alleviation, environmental protection and market reform. Applying a public policy framework, the paper examines the processes of agenda setting, of policy design and decision-making and of implementation and learning. These policy processes are illustrated by reference to structural reform, power generation, intermittent renewable energy as well as sulphur dioxide emissions and demand-side management. The aims of the analysis are to show how domestic and external events contribute to setting the policy agenda, to identify the factors that render policy design and decisionmaking highly path dependent and to illustrate the ability of policymakers to learn from experience. Whilst the bulk of the account is focused on the period since the early 1990s, we have devoted some space to the previous decades in order to provide the context for explaining the more recent policy processes. We identify four distinct periods, as follows: ●

The early years: 1949 to late 1970s. Modernization: late 1970s to early 1990s. ● Revitalizing reform: early 1990s to early 2000s. ● New agendas: early 2000s onwards. ●

The first two periods are described relatively briefly. For the latter two periods, the analysis addresses, in turn, the policy agenda, structural reform, power generation, intermittent renewable energy and sulphur dioxide emissions and demand-side management. The account begins with a brief overview of key relevant concepts from the public policy literature. 179

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1.  KEY ELEMENTS OF PUBLIC POLICY It has long been recognized that the making and implementation of public policy are processes that are far from being mechanical, rational and logical. Rather these processes are shaped by a wide range of factors such as the bounded rationality of the individuals involved, the complexity of many policy problems, the scarcity of available attention within the policy community, the dispersal of knowledge and expertise, the variety of interests and the distribution of agency (Jones, 2003; Hayes, 2013). As a result, policymakers tend to focus on limited aspects of a problem and to make incremental adjustments in a way that Lindblom (1959) called ‘muddling through’. This incrementalism leads, in turn, to a high degree of path dependency in public policy as each new policy builds on previous ones and veto points become established (Pierson, 2004). Nevertheless, governments are capable of taking significant policy initiatives under certain conditions. Windows of opportunity can be created by exogenous shocks that draw the attention of policymakers to a challenge that may be new or that may have already been recognized but not adequately addressed (Baumgartner et al., 2009). This combination of shocks and incrementalism leads to a pattern of punctuated equilibrium in public policy, in which sustained periods of gradual change are interrupted by significant policy changes. Five stages may be identified in the public policy process: ●

Agenda setting. Policy formulation and design. ● Decision-making. ● Implementation. ● Evaluation and learning. ●

The arrival of an issue on the agenda of the policymakers is arguably the most important step, because otherwise no new policy will be enacted. Shocks and focusing events play a key role in the process, possibly supported by policy entrepreneurs or public opinion, depending on the political system (Kingdon, 2011; Boushey, 2013). The power of such events to grab the attention of the policymakers will also depend on their values and beliefs (Rochefort and Donnelly, 2013), on the institutional systems (Jones, 2001), as well as on the distribution of power among the elites (Schattschneider, 1960). In this respect, a change of leadership by itself can bring an issue onto the policy agenda (Kingdon, 2011). Most policy issues arise in specific policy subsystem that relates to an individual sector such as energy, health, education or defence. Incremental

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China’s evolving energy policy: the case of electricity  ­181 policy adjustments can often be made within the subsystem itself, by the relevant government agencies. However, a major policy change will require the issue to rise above the subsystem to a level where coordination can be achieved across multiple actors and sectors (Boushey, 2013). Nevertheless, the problem may not remain on the agenda unless there are solutions available and the political context is supportive (Kingdon, 2011). The processes of policy formulation and design may involve a broad policy community that comprises government agencies, companies, the professions, international organizations, non-governmental organizations, as well as epistemic communities that provide knowledge. The wider public tends to be less deeply engaged than at the stage of agenda setting, because of the need for specialist knowledge. Conversely, the policy community may be dominated by a small number of powerful actors in competing policy networks (Howlett and Giest, 2013). In any political context policy design involves a number of standard elements including setting goals, identifying target populations, agreeing rights and obligations, allocating responsibilities for implementation, designing policy tools and, if necessary, creating new administrative structures (Schneider and Ingram, 1988). Howlett and Ramesh (2003) classified policy tools into four types: ●

Nodality: for example, through information or exhortation. Authority: for example, through command and control regulation, or standard setting. ● Treasure: for example, through grants, loans, user charges or taxes. ● Organization: for example, through direct provision by government or state-owned enterprises, or by the creation of markets. ●

To a certain extent, the choice of policy tools will arise from a logical analysis of the problem and assessment of policy options drawing on comparisons and analogues from other sectors within the country as well as from other nations (Schneider and Ingram, 1988). Administrative cost, the availability of resources and the applicable laws may provide additional constraints (Howlett and Ramesh, 2003). However, bounded rationality, cognitive bias, previous experience and the prevailing policy and political environment together provide the context in which such analysis takes place (Schneider and Ingram, 1988; Howlett and Ramesh, 2003). In political systems other than dictatorships, the final policy decision arises from bargaining and negotiation amongst the powerful actors within the policy community that will result in trade-offs and compromises (Jones, 2003; Howlett and Giest, 2013). If the problem is complex and poorly understood, the policymakers may reach for tried

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182   Handbook of energy politics and tested ­solutions, regardless of the fit to the problem at hand (Jones, 2003). The result is incremental change and satisficing (Lindblom, 1959). Non-incremental change is only possible if there is agreement amongst policymakers on the nature of the problem and on the objectives of the policy initiative (Hayes, 2013). The academic study of policy implementation has yielded a variety of perspectives, all of which have some merit. Principal–agent theories have been developed in the disciplines of economics, politics and sociology (Kiser, 1999). The underlying theme is that the principals face a challenge in ensuring that the agents carry out their obligations. Agents not only have their own interests but also have greater access to information. On the other hand, the existence of multiple principals can undermine monitoring. Success in implementation can be enhanced if principals and agents share a common value set, through membership of the same political party for example, or through third-party monitoring. Such ‘top-down’ analyses require the central government to find ways to limit the scope for power level agents to modify or obstruct the policy programme through processes such as the appointment of officials, the garnering of stakeholder support and the application of sanctions (Sabatier, 1986). Proponents of a ‘bottom-up’ approach argue that the ‘top-down’ model ignores political realities and the necessity of allowing agents to adapt policy to local conditions (Matland, 1995). In addition, there is the challenge of understanding horizontal coordination and competition between local actors with different interests, skills and resources. As with policy formulation and design, the processes of policy evaluation and learning are both subjective and political (McConnell, 2013). An assessment of a policy programme must not only measure outcomes against goals, but should also evaluate positive and negative side-effects as well as the relevance of the outcomes to the underlying objectives of the programme (Vedung, 2013). The reaction of a government to partial or total policy failure will depend on the political importance of the policy issue at the time of assessment and on the options and risks of modifying the policy. Even the complete failure of a programme may be tolerated or masked if necessary (McConnell, 2013). On the other hand, the government may choose to learn from the experience either through internal bureaucratic deliberation or by drawing on the wider policy community (Howlett and Ramesh, 2003). Nevertheless, the process of policy learning is constrained by the same factors that shape policy formulation, notably bounded rationality, cognitive bias, previous experience and political context (Marier, 2013).

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China’s evolving energy policy: the case of electricity  ­183

2.  THE EARLY YEARS: 1949 TO LATE 1970s During the 30 years from 1949 to the late 1970s, the energy sector was dominated by the state, with ministries not companies being directly responsible for energy production and transformation and the State Planning Commission undertaking the planning of production and consumption as well as setting prices. During much of this time, political power lay in the hands of one man, Mao Zedong, and a few key individuals around him. Two priorities brought energy to Mao’s agenda: the need for energy to support rapid reconstruction and industrialization (Dorian, 1994) and the desire to electrify the countryside (Pan et al., 2006). At the time of Liberation in 1949, the total electricity generating capacity in China amounted to less than 2 GW (Yang and Yu, 1996) and the capacity of rural, small-scale hydroelectric plants was just 33 MW (Pan et al., 2006). The Soviet Union played a central role in helping the country build its generating capacity, until the breakdown in diplomatic relations occurred in 1960 when the Soviet advisers were withdrawn. The capacity of coalfired plants that could be manufactured in China rose from 6 MW to 100 MW by 1956 (Carin, 1969) and a number of large-scale dams were constructed, including the Sanmenxia Dam with a design capacity of 1.1 GW (Xu, 2002). By 1960, total generating capacity had reached 12 GW. The disruptive effects of the Great Leap Forward (1958–61) and the Cultural Revolution (1966–76) resulted in a highly erratic rate of growth in the 1960s and early 1970s. Nevertheless, total generating capacity rose to 60 GW by the late 1970s, of which 70 per cent was thermal and 30 per cent hydro (Thomson, 2003). The one positive side effect from these disruptions was the construction of 90,000 small-scale hydroelectric plants totalling 6.3 GW (Xu, 2002). One negative consequence was the rise of air pollution, notably sulphur dioxide (SO2) and soot from the growing use of coal in power generation and heavy industry, as well as for winter heating in the north of the country (Smil, 1984). The possibility of developing nuclear power was mentioned in the first five-year plan of 1953, but then was dropped as attention switched to developing an atomic bomb (Sovacool and Valentine, 2012). The 1960s saw the development of reactors to power submarines, but only in 1970 did a power supply crisis in Shanghai bring civil nuclear power back onto the agenda. Even then, progress remained slow because neither of the two key agencies responsible for nuclear matters were interested in switching their focus from military to civil uses and the Ministry of Water Resources and Electrical Power was not supportive of nuclear power. In 1974, Prime Minister Zhou Enlai gave the instruction to develop a 300 MW

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184   Handbook of energy politics pressurized water reactor (PWR) based on the design used by the naval submarines (Xu, 2002).

3.  MODERNIZATION: LATE 1970s TO EARLY 1990s The death of Chairman Mao in 1976 and the rise to power of Deng Xiaoping allowed China to move into a new era of economic policy. Whilst private ownership and free markets were not yet terms used in formal government rhetoric, the 1980s saw a remarkable transformation of the economy in a number of ways: land was decollectivized; enterprises outside the formal state-owned sector were allowed to blossom, notably the township and village enterprises which were key drivers of economic growth at this time; and prices for some goods began to more closely reflect market forces. Whilst liberalization was not a priority of the leadership, modernization was. Deng revitalized the ‘Four Modernizations’ slogan first used by Zhou Enlai in 1964: modernizing agriculture, industry, defence and science and technology. This involved three key reforms to the governance of the economy: the progressive delegation of authority to the provincial and lower levels of government, the gradual corporatization of state-owned enterprises and the cautious liberalization of prices. These changes led to the steady transformation of the system for economic and energy policymaking and implementation from one that was, in principal if not in practice, highly centralized and planned, to one which became was much more fragmented. However, the ability of the Communist Party to retain some degree of control in the midst of fragmentation, led to the style of governance being characterized as ‘fragmented authoritarianism’ (Lieberthal and Oksenberg, 1988). During the 1980s the government took a number of steps to corporatize the state-owned enterprises. In the energy sector, this included the creation of the creation of three national oil companies (NOCs), the China National Offshore Oil Corporation (CNOOC) in 1982, the China National Petrochemical Corporation (Sinopec) in 1983 and the China National Petroleum and Gas Corporation (CNPC) in 1988 (Wang, 1999). In 1988, the Ministry of Coal Industries was dissolved and its assets were transferred to the newly created China National Coal Corporation (CNNC), but this move was reversed in 1993 (Thomson, 2003). However, the electrical power industry remained under direct ministerial control, despite the frequent changes in the structure and name of the relevant ministry (Xu, 2017). The industrialization programme needed a sustained increase in energy supply, including of electricity and boosting investment in energy

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China’s evolving energy policy: the case of electricity  ­185 i­nfrastructure was a key government priority. Whilst the production of coal grew rapidly, investment in power generation lagged behind the rising demand, leading to blackouts (Johnson, 1992). The gradual liberalization of coal prices in the early 1980s, together with a requirement that new power plants had to repay central government loans with interest, greatly dampened the economic incentives of provincial governments to invest in new thermal capacity. In response and in line with other sector reforms, the government delegated more power for planning and financing electricity infrastructure to provincial governments, introduced a two-tier tariff mechanism for power plants which allowed them to sell at market prices output that exceeded the plan, and allowed end-user tariffs to rise (Xu, 2002). These moves triggered a programme of investment which drove thermal power capacity from 45 GW in 1980 to 126 GW by 1992 (Figure 8.1; State Planning Commission, 1995). Hydroelectricity was also a key source of energy, and the 1980s saw a shift back to the construction of large-scale dams. This period was also characterized by the entry into the political elites of individuals with engineering rather than political backgrounds. Notable among these was Li Peng who spent his entire career in the power sector, rising to become Minister of Electrical Power in 1983 and Prime Minister from 1988 to 1998 (Yeh and Lewis, 2004). This technocratic leadership was determined to take advantage of the country’s vast hydro resources, estimated to be the largest in the world (Xu, 2002). As a result, total hydroelectric generating capacity doubled from 20 GW in 1980 to 40 GW in 1992 (Figure 8.1; State Planning Commission, 1995). After the vacillation that characterized the earlier period, 1978 saw the formal announcement that China would develop civil nuclear energy (Xu, 2010). Nevertheless, the political struggles continued between different agencies over the choice of technology between PWR and pressurized heavy water reactor (PHWR) and between imported versus indigenous technology (Ramana and Saikawa, 2011). The first was decided in favour of PWR, at least in the short-term, and the second was resolved by a compromise which allowed one of each to be built. This led to the construction of the 300 MW Qinshan I plant in Zhejiang based on Chinese design, though with key imported components, and the two 944 MW units at Daya Bay in Guangdong Province, of French design, with China Light and Power of Hong Kong as the joint-venture partner (Xu, 2010). These plants came into commercial operation in 1994. The desire to promote rural electrification and alleviate poverty led the government to promote the construction of small-scale, off-grid wind turbines in areas with no hydroelectricity potential (Lew, 2000; Pan et al., 2006). The government provided low interest loans to turbine

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186   Handbook of energy politics 1,000 900 800 700

GW

600

Thermal

500 400 300

Hydro

200 100

Wind & solar Nuclear

0 1980

1985

1990

1995

2000

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2010

2015

Sources:  Thomson (2003), National Bureau of Statistics (various years), BP (2016).

Figure 8.1  I nstalled power generation capacity in China for different types of fuel, 1978–2015 ­ anufacturers and subsidies to households. A large proportion of these m projects were in Inner Mongolia. By mid-1990s there were about 140,000 small turbines in China totalling 8.7 MW (Fang et al., 1998). The government also encouraged the construction of a number of demonstration projects for larger-scale wind energy, using imported equipment and foreign loans. By the mid-1990s the total capacity of wind power had reached 30 MW (X. Zhao et al., 2016). Throughout this period of early modernization, the emphasis in the electricity sector was on constructing new infrastructure to support economic growth, industrial development and poverty alleviation. Rather less attention was paid to energy efficiency and air pollution. The efficiency of thermal power stations did increase dramatically during the early 1980s as a result of the rise in coal prices, but later the rate of increase declined as the economic pressures on the plants reduced (Figure 8.2; Johnson, 1992). At the other end of the supply chain, the concept of demand-side management had yet to be introduced. Rather, the power companies managed the supply–demand balance by rationing end-users without consultation and through direct load control (Zeng et al., 2013). In addition, the electricity consumers faced little incentive to constrain their demand because of the

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China’s evolving energy policy: the case of electricity  ­187 500

gce/kWh

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400

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Source  China Electricity Council (2016).

Figure 8.2 Mean annual net coal consumption of thermal power plants in China, 1978–2015 low level of tariffs and the tradition of charging by capacity rather than by actual use (Yang and Yu, 1996). Although energy efficiency did not reach the government’s agenda, air pollution was a growing concern, notably soot and SO2 from coal combustion. Rapid industrialization had led to a doubling of national coal consumption between 1977 and 1988, with annual coal use in the power industry rising from 90 to 250 million tonnes (State Planning Commission, 1995). A trial Law on Environmental Protection had been introduced in 1979, but the first direct assault on SO2 emissions came in 1982 with the Interim Procedure on Pollution Charges which set a levy of 0.04 RMB/kg on SO2 emissions above national standards. The government promulgated an Air Pollution Prevention and Control Law in 1987 and for the first time set emission limits for thermal power plants in 1991. However, these measures had little effect as the levy was lower than the abatement cost and the local environmental bureaux had little incentive or authority to monitor and enforce (Finamore and Szymanski, 2002; Schreifels et al., 2012). These two factors remained endemic to the nation’s regulatory system for environmental protection until 2008 when the Environmental Protection Agency was elevated to ministerial status.

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4. REVITALIZING REFORM: EARLY 1990s TO EARLY 2000s 4.1  The Policy Agenda The period 1988–91 was characterized by political turmoil and economic slowdown. In his last major public act, Deng Xiaoping visited Guangdong Province in 1992 to emphasize his support for renewed economic growth and reform. This stimulated five years of rapid GDP increase ending with the Asian Financial Crisis in 1997. More importantly, it ushered in a more reformist mood amongst the political leadership. This was epitomized by Zhu Rongji who, as vice-premier and then as prime minister from 1998 to 2003, was the main driving force behind substantial reforms to ­government, state-owned enterprises and markets, as well as for closer engagement with the international community, exemplified by China’s accession to the World Trade Organization (WTO) in 2001. The economic reform agenda was heavily influenced by international organizations such as the World Bank, including in the energy sector. At the same time, the leadership was concerned with the high cost of government and the large scale of financial losses being incurred by many state-owned enterprises, including those in energy production and transformation. Although the economy and the consequent demand for energy continued to grow, the rate of growth declined in the late 1990s as a result of the Asian Financial Crisis. Following China’s participation in the UN Conference on Environment and Development in Rio de Janeiro in 1992, the government formally recognized that sustainable development should form an important part of the national policy agenda (Geall and Ely, 2015). Thus, the 1990s was the first time that the quality of economic growth and energy supply became a priority for government, rather than the sheer quantity. This resulted in the massive structural reforms launched in 1998 and in the publication of the National Agenda 21 in 1994 and the first National Sustainable Development Report in 1997. At the same time, the government was proclaiming a new strategy of creating large corporations which could complete internationally and become ‘pillar industries’ (Nolan, 2001). Along with the appearance of these three new priorities in the energy sector, rural electrification and poverty alleviation remained firmly on the government’s agenda. 4.2  Structural Reform It was within this context of nationwide industrial reform, of new ideas from abroad and of specific challenges in the energy sector, that the

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China’s evolving energy policy: the case of electricity  ­189 reform of the energy sector and of other industrial sectors was launched in 1998. That year saw the abolition of a number of industrial ministries, the creation of new companies and the restructuring and commercialization of existing state-owned enterprises. Over the next five years the energy sector was completely transformed. The key elements of the reform were: (1) the corporatization of the energy enterprises and the further removal of government from the management of these enterprises; (2) the restructuring of these enterprises; (3) the commercialization and, in some cases, public listing of these newly corporatized entities; (4) the transfer of many of the remaining regulatory functions from enterprises to government and (5) further changes to the systems for pricing energy. An implicit, and occasional explicit, goal of these reforms was to pave the way for the introduction of competition. Given the differing nature of the supply systems and differing existing structures of the industries, the oil and gas, power and coal industries followed different reform trajectories. The reform of the power industry in 1998 was more limited in extent than that applied to the petroleum and coal industries. The assets of the Ministry of Electrical Power were simply transferred to the newly created State Power Corporation of China (SPCC) which, as a result, owned most of the transmission and distribution infrastructure and about 50 per cent of the nation’s generation capacity. The rest of the assets continued to be owned by a wide variety of state-owned enterprises linked to different levels of government (Xu, 2002). The decision not to break up the SPCC at this time appears to have received the support of both ex-premier Li Peng and the then prime minister Zhu Rongji on account of their belief that centralized control of the power sector was necessary. Nevertheless, the government charged the SPCC with reforming the power sector (Xu, 2017). It soon became apparent that the new structure was deeply unsatisfactory and that the SPCC was making no effort to reform the industry. Intense debates took place involving the highest levels of government and with senior officials publishing their arguments for further reform in the press (Xu, 2017). This culminated in the decision, at the end of 2002, to dismantle the SPCC in order to separate generation from transmission and distribution and to reduce the concentration of ownership of power generating capacity. The generating assets of the SPCC were unbundled from the grid and, together with those of the pre-existing Huaneng Group, were assigned to five large companies whose sole business was to be power generation: the Huaneng, Datang, Huadian and Guodian Corporations and the China Power Investment Corporation. These have since been listed on stock exchanges (Andrews-Speed and Cao, 2005). Although these five companies nominally lay at arm’s length from the government, their

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190   Handbook of energy politics connection with the political elite was exemplified by the ­appointment of the son and daughter of the previous prime minister, Li Peng, to senior management positions in Huaneng and China Power Investment Corporation respectively (Yeh and Lewis, 2004). The transmission and distribution assets of the SPCC were divided between two new companies. The State Grid Corporation retained the majority of the regional grids in the country, as well as the inter-regional transmission lines, on the basis that central control of the grid was essential. The Southern China Power Grid Company took over the assets in the far south of the country. The two new grid companies were required to progressively sell off most of their generating capacity. Few changes were made to the structure of tariffs. The wholesale tariff and annual operating hours for each plant continued to be set at provincial level. A number of experiments in wholesale competition through a power pool were carried out, but no steps were taken towards the systematic introduction of competition in power generation (International Energy Agency, 2006). In 2003, the government proposed further reforms to the system for electricity pricing which would lead to three separate sets of tariffs, for generation, with both capacity and energy components, for transmission and distribution, and for retail, with the eventual separation of transmission and distribution tariffs. But a decade later, these proposals had not yet been implemented. 4.3  Power Generation Energy shortages continued throughout the 1990s until the Asian Financial Crisis hit economic growth in 1997. The need for investment in the electrical power industry remained high, yet the central government was short of funds and contributed a progressively smaller share of the capital needed (Xu, 2002). As a result, and in line with the more open approach to international engagement, the government accelerated a trend of attracting foreign funding which had begun in the late 1980s. Most of this inward investment took the form of loans from the World Bank, the Asian Development Bank, the Japanese government and other bilateral agencies (Li and Dorian, 1995). Private foreign direct investment in power generation was also permitted, though this never achieved the scale envisaged by the government on account of regulatory uncertainty (Andrews-Speed, 2004). Local governments and power enterprises played a growing role in funding power generation as the fiscal decentralization carried out in the 1980s gave them access to more capital than the central government (Xu, 2002). These different sources of funds allowed the rate of investment to be sustained during the 1990s, lifting total generating

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China’s evolving energy policy: the case of electricity  ­191 capacity at a rate of about 20 GW per year from 167 GW in 1992 to 357 GW in 2002. Whilst the aggregate capacity of thermal plants rose from 125 GW to 265 GW over this period, the main challenge facing thermal power was to raise its fuel efficiency which had seen little improvement in the late 1980s (Figure 8.2). In the early 1990s, there were too many small and inefficient plants, few with a capacity greater than 300 MW and too few cogeneration units (Zhang, 1998). In order to upgrade the fleet, the short-lived Ministry of Energy, which was then responsible for the power industry, decreed that all new coal-fired plants should have capacities of 300 MW or 600 MW, and a net coal consumption of less than 330 gce/kWh. Some 18.5 GW of small inefficient plants were identified for closure or retrofitting. The overall aim was to reduce average net coal consumption from 427 gce/kWh in 1990 to 355 gce/kWh by the year 2000 (Li and Dorian, 1995; Zhang, 1998). These measures did meet with some success. By 2002, about 300 plants with a capacity in excess of 300 MW were in operation, of which 26 were of 600 MW (Sun, 2010). Although the reforms had increased the incentives for power companies to enhance commercial efficiency, the greatest improvements occurred in labour and capital productivity, rather than in fuel efficiency (Du et al., 2013; Meng et al., 2016). The average fuel consumption fell to 400 gce/kWh by 2000 (Figure 8.2), but well short of the target of 355 gce/kWh. One of the reasons was that local governments continued to build plants of 200 MW or below in order to avoid having to seek central government approval for larger plants (Li and Dorian, 1995). Investment in hydroelectricity capacity also continued, with total capacity rising from 42 GW in 1992 to 86 GW in 2002. It was during this period, and under the guidance of Premier Li Peng, that approval was eventually given for the construction of the 22.5GW Three Gorges Dam on the Yangtze River (Yeh and Lewis, 2004). The opposition to the project was so great, both inside and outside China, that the World Bank refused to provide financial support. The creation of the reservoir caused more than 1.2 million people to be resettled, a process that was plagued by delays and corruption, and the pollution of the waters has been much greater than expected (Economy, 2004). After the commissioning of the country’s first nuclear power plants in 1994, a decision was made to build four more plants under the slogan of moderate development of nuclear power in order to sustain technical expertise but limit capital requirements (Xu, 2010; Sang, 2011). Prime Minister Li Peng was once again a key supporter. The political context of the decision-making on reactor design was even more complex than before on account of the fragmentation of government, the rise in the number of corporate actors and the increasing interaction with foreign

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192   Handbook of energy politics governments and vendors. The result was that the four new plants were built with four designs from four countries: Qinshan II with Chinese technology supplemented by US turbines; Qinshan III using the Canadian PHWR Candu design, a departure from the earlier decree to deploy only PWR; Tianwan in Zhejiang Province applying Russian VVER technology; and Lingao, near Daya Bay, continuing with the French design (Xu, 2010). This fragmented strategy ran against the conventional wisdom that standardization of reactor design reduces costs and enhances efficiencies of construction, operation and maintenance, and leads to greater safety (Ramana and Saikawa, 2011). In 1999, Prime Minister Zhu Rongji placed a moratorium on the construction of all new thermal, hydro and nuclear power plants, in part because of the growing surplus of capacity arising from the impact of the Asian Financial Crisis on energy demand. 4.4  Intermittent Renewable Energy The new emphasis on sustainable development combined with the longterm need for energy led to a more sustained effort by the central government to promote investment in wind and solar energy. In 1994, the Ministry of Electric Power published the country’s first Strategic Development Plan for Wind Energy in China 2000 and 2020, which set goal of 1,000 MW of capacity to be installed by 2000. The same year saw the promulgation of the Regulation on Grid-Connected Wind Farms. This required that the grid should purchase all the wind power generated and pay a tariff that reflected cost, interest and reasonable profit (X. Zhao et al., 2016). The State Planning Commission and the State Economic and Trade Commission formalized the national strategy for renewable energy in their Programme for Development of New and Renewable Energy Sources in China 1996–2010, but downgraded the wind energy target for 2000 to 300–400 MW. In 1997 the State Development and Planning Commission launched the Riding the Wind Programme to promote the establishment of joint ventures with foreign manufacturers of wind energy equipment. This programme was undermined by the Ministry of Electrical Power which waived import duty for turbines for grid-connected wind farms. The result of this and other forms of poor coordination was that only two joint ventures were formed, and installed capacity reached just 769 MW by the end of 2004 (Lema and Ruby, 2007; Zhang et al., 2013b). Additional constraints included the high cost of the imported equipment which made wind energy uncompetitive, the paucity of financing available from either domestic or foreign sources, the frequent refusal of the local grid company to purchase

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China’s evolving energy policy: the case of electricity  ­193 the electricity generated, and the slow growth of the domestic capacity to manufacture the equipment (Liu et al., 2002; Lema and Ruby, 2007). The development of solar PV in China lagged well behind wind energy, mainly on account of the former’s higher costs. The first coordinated initiative was the Brightness Programme launched in 1996 and supported with 10 billion RMB with the aim of providing solar PV to remote communities in western China (Pan et al., 2006; Zhang and He, 2013). This was followed in 2002 by the Township Electrification Programme that extended the Brightness Programme as part of the wider national strategy to develop the western parts of the country. Total investment amounted to 4.7 billion RMB (Zhang and He, 2013). Within 20 months, 721 solar PV stations totalling 15 MWp had been built, supplying electricity to some 340,000 people. The success in constructing capacity was not matched by technical or financial sustainability. Key constraints included a lack of skills and funds for system repair and maintenance, and the challenge of charging a tariff which was both affordable and matched the high cost of the equipment. As a result, the actual use of electricity was not commensurate with the installed capacity of solar PV (Shyu, 2012). Other projects in remote areas were developed as part of bilateral aid programmes (Zhang et al., 2014). Together these efforts allowed the installed capacity of solar PV in China to rise from 6.6 MWp in 1995 to 55 MWp in 2003. 4.5  Sulphur Dioxide Emissions and Demand-Side Management The 1990s saw a flurry of measures by the central government to constrain the rise of air pollution, including that from the power sector (Finamore and Szymanski, 2002; Schreifels et al., 2012). SO2 emission standards for thermal plants were tightened but not made legally binding until 2000 when the Law on Air Pollution Prevention and Control was amended yet again. A programme of total emissions control was developed that set targets for local governments relating to the emissions of 11 pollutants including SO2. The importance of sustainable development in the power sector was given an additional boost by the publication in 1997 of a World Bank report which identified, among other issues, the problem of air pollution in China from coal combustion and the costs to human health, agriculture and the wider economy (World Bank, 1997). In response, the government raised the levy for SO2 discharge to 0.21 RMB/kg (Schreifels et al., 2012) and developed a plan to close small and inefficient thermal plants, install flue-gas desulphurization (FGD) equipment, and constrain the mining of high-sulphur coal (Finamore and Szymanski, 2002). Whilst the annual quantity of SO2 emissions from the power sector was estimated to have

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194   Handbook of energy politics declined from 23.7 million tonnes in 1995 to 19.95 million tonnes in 2000, most of this reduction could be attributed to the economic slowdown and the closure of small-scale plants, rather than to the installation of FGD equipment (Finamore and Szymanski, 2002). Demand-side management (DSM) started to be introduced as an energy saving strategy in the 1990s by the Ministry of Electrical Power and its successor the State Power Corporation. However, the measures deployed built on past practices that were administrative in nature, such as compulsory load shifting and power rationing. Few economic tools were deployed and little technical support was given. The Energy Conservation Law promulgated in 1997 did not even mention DSM. Nevertheless, a reduction of peak load by 3.8 GW was achieved (Zeng et al., 2013).

5.  NEW AGENDAS: EARLY 2000s ONWARDS 5.1  The Policy Agenda The period from 2002 to the time of writing (late 2016) has arguably been the most challenging for the Chinese government in terms of changing priorities within the energy sector and the need to balance priorities between sectors. The surge in economic growth that started in 2002, the second year after China’s accession to the WTO, rapidly led to a shortage of electrical power across much of the country in 2003. The duration of this shortage was exacerbated by the ban that had been imposed in 1999 on constructing new power generating capacity. The ban was lifted in 2002. Tackling this energy crisis took priority over market liberalization in the electrical power industry. The rise in air pollution from soaring coal combustion pushed air pollution higher up the agenda. From 2005 onwards, the environment became an increasingly important topic of public debate and of official pronouncements as both global climate change and domestic environmental degradation were being seen as threats to national security and societal well-being (Nyman and Zeng, 2016). By this time, rural electrification had slipped off the agenda as the rate of electrification had already exceeded 99 per cent of the population. In contrast, the emphasis on energy technology development was progressively emphasized as part of the government’s push to make China a technologically advanced nation. In the background lay the long-term programme of developing the western regions of the country that dated back to the beginning of the century. In the case of energy, this involved producing more energy in west and transporting it to the east. The global financial crisis of 2008 brought about significant consequences for China’s energy policy priorities, but with a time lag. The

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China’s evolving energy policy: the case of electricity  ­195 government’s short-term response to the financial crisis was to support the economy with a four trillion RMB stimulus over two years, 2010 and 2011. Whilst this boosted economic growth in the short-term, it worsened air pollution to such a degree that the government was forced to act more decisively than before. Secondly, the economic slowdown in the west dramatically curtailed demand for China’s exports, including for renewable energy technology. Finally, when China’s own economy started to slow down in 2012 and the government launched its drive to rebalance the economy away from heavy industry, a sharp decline in the rate of increase of electricity demand led to a surplus of generation capacity for the first time since the beginning of the century. It was in this context that President Xi Jinping proclaimed in 2014 the need for the nation to undergo four energy revolutions, in energy supply, consumption, technology and system. 5.2  Structural Reform The government largely suspended the process of reforming the energy sector between 2004 and 2010, mainly because of the shortage of domestic energy supply that was experienced from 2003 as economic growth soared. In the case of the electrical power sector, the government’s reluctance to press on with reform can also be attributed to external events. The years 2000 to 2005 saw severe blackouts and politically unacceptable price volatility in a number of liberalized power markets in the USA, Canada, the UK, Scandinavia and Italy. China’s government took from these experiences the lesson that electricity sector liberalization was fraught with risks, and that such risks would be exacerbated in an environment with weak regulatory and legal systems (Yeh and Lewis, 2004; Andrews-Speed, 2013). The slowdown in the economy since 2011 provided the opportunity for the State Council to revitalize its reform efforts which had been suspended since 2003, by issuing Document Number 9 in March 2015. The new round reform was characterized as ‘controlling the middle and deregulating the two ends’. This meant that while competition would be gradually introduced into the upstream (generation) and downstream (retail) ­segments, the midstream (transmission and distribution) would remain regulated (National Development and Reform Commission, 2015). The central element of these reforms was to set transmission and distribution tariffs on the basis of ‘allowable cost plus reasonable profit’ (National Development and Reform Commission and National Energy Administration, 2015). Pilot transmission and distribution tariff reforms were implemented in more than 20 provincial grid companies, among which, pilot reforms scheduled to be launched in 14 provincial grid ­companies in 2017 were brought forward to September 2016.

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196   Handbook of energy politics A second key element of the reform was to open electricity retail to c­ ompetition. This should progressively allow companies other than the main state-owned enterprises to gain access to the electricity retail market and end-users to choose their retailers (National Development and Reform Commission, 2015). The first step of the retail reform was to restart an experiment that was abandoned several years ago to allow large power consumers to purchase electricity directly from generating companies. However, such direct power transactions face many challenges, including the level of transmission and distribution tariffs, the eligibility criteria for generators and the ongoing monopoly position of the grid companies. A further element of the reform has been to establish relatively independent electricity trading bodies. As of late 2016, there has been no public announcement of any intention to break up the State Grid Corporation either along geographic lines or to separate transmission from distribution. 5.3  Power Generation The electricity supply crisis of the early 2000s brought up a succession of measures to curb energy consumption across the economy, with a particular emphasis on heavy industry including the power sector. These included the Medium and Long-Term Energy Conservation Plan (2004), the Top1000 Energy Consuming Enterprises Programme (2006), a revised Energy Conservation Law (2007) and the National Programme for Medium and Long-Term Scientific and Technological Development 2006–2010. These supported an overall objective to reduce national energy intensity by 20 per cent between 2005 and 2010 and by a further 16 per cent by 2015, and to reduce the intensity of carbon dioxide emissions by 40–45 per cent between 2005 and 2020. Measures specific to coal-fired power generation were wide ranging and had the aim of reducing average coal consumption from 392 gce/kWh in 2000 to 320 gce/kWh in 2020 as well as reducing air pollution (Ma and Zhao, 2015; Yuan et al., 2016a): ●

Banning the construction of plants with a capacity of less than 135 MW. ● Decommissioning plants below 100 MW capacity and replacing small plants with large ones. ● Prioritizing the construction of plants of 600 GW capacity or larger, and the deployment of supercritical and ultra-super critical technologies.

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China’s evolving energy policy: the case of electricity  ­197 ● ●

Upgrading older plants that were not closed. Building more combined heat and power capacity.

The policy instruments were mainly administrative in nature, for example through the centralized approval process for investment and through energy efficiency benchmarking (Na et al., 2015). Financial support was provided through compensation for plants closure and loans for new capacity that met the technological requirements (Yuan et al., 2016a). These measures met with a high degree of success. By the end of 2015 more than 100 GW of small-scale plants had been closed, a total of 219 GW of supercritical and 155 GW of ultra-supercritical plants had been commissioned and average net coal consumption had declined to 315 gce/ kWh (Figure 8.2; Myllyvirta and Shen, 2016; Yuan et al., 2016a; Yeager, 2016). A growing proportion of the coal-fired plants were being built in the north and west of the country, near the coal mines, in order to support economic development in these regions and to constrain air pollution in the south and east (Myllyvirta and Shen, 2016). However, this success has been undermined by a separate policy decision in 2013 to relax the need for central government approval for many types of infrastructure project, including thermal power plants. This led to a surge of construction approved by provincial governments that brought 170 GW of coal-fired capacity online between 2012 and 2015, just as annual demand growth was slowing from 12 per cent in 2011 to 0.5 per cent in 2015 (Yuan et al., 2016b). As a result, the average load factor of thermal plants declined from 62 per cent in 2011 to less than 45 per cent in 2015 (Figure 8.3). By this time, a further 200 GW of coal-fired capacity was under construction and permits had been issued for an additional 55 GW. In response, the central government took back the approval process by issuing instructions to provincial governments to delay projects which had not broken ground and to stop approving new projects unless there was a clear need. At the same time, the National Energy Administration (NEA) issued a further list of some 70 GW of plants to be decommissioned by 2020 (Myllyvirta and Shen, 2016). Natural gas is a cleaner and more efficient feedstock for thermal power than coal. The consumption of natural gas in China has grown substantially since the year 2000, sourced by rising domestic production and imports. However, industry and the households account for more than 50 per cent of national gas consumption and natural gas provides only a small share of total power supply, just 2.2 per cent in 2013 (Li, 2015). Gas-fired power stations are most common in the energy-poor coastal provinces where they provide valuable peaking services, but they are not competitive against coal-fired plants (International Energy Agency, 2015).

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198   Handbook of energy politics % 65.0

60.0

55.0

50.0

45.0

40.0 1980

1985

1990

1995

2000

2005

2010

2015

Source:  China Electricity Council (2016).

Figure 8.3  M  ean annual load factor for thermal power plants in China, 1978–2015 The construction of large-scale hydroelectric dams continued to be a priority, not just to increase the nation’s generating capacity but also to address the twin challenges of air pollution and carbon emissions as well as to develop the western regions of the country. By 2015, seven major dams had been completed along the Lancang River in southwest China with a total capacity of 15.5 GW and an estimated 58,000 people displaced (Tilt, 2015). In the same manner, plans were drawn up in the early 2000s to build up to 13 dams on the Nu River, totalling 21.3 GW. The level of controversy was so great that the government suspended these plans in 2004 (Tilt, 2015). The push to increase the share of non-fossil fuels in the energy mix appeared to result in a reversal of this decision in 2013 as part of the Twelfth Five-Year Energy Plan 2011–15. Nevertheless, as of late 2016, no construction of large dams along the Nu River had received approval and, instead, provincial officials were talking of creating a national park (Fawthorp, 2016). The need for large-scale, low-emission base load triggered a revival of interest in nuclear power. The Medium to Long Term Plan for Nuclear Energy Development 2005–2020 presented the aim of having 45 GW in operation by 2020, with new plants both along the coast and at inland

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China’s evolving energy policy: the case of electricity  ­199 locations with rapid economic growth (Xu, 2010). The target for the year 2020 was raised to 80 GW in the Five-Year Plan for 2011–2015. The National Guidelines for the Medium and Long Term Plan for Science and Technology Development 2006–2020 identified high-temperature gas cooled reactors and fast breeder reactors as priorities and the Scientific Development Strategic Plan for Nuclear Enterprises gave support for Chinese nuclear technologies to be exported (Xu, 2014). By this time there were three Chinese companies developing and investing in nuclear power and the government was providing a feed-in tariff for nuclear power that was significantly above that for thermal power (Rutkowski, 2013). The Fukushima Daiichi disaster in 2011 brought a temporary halt to this programme. Construction of all new plants was suspended, all plants in operation or under construction were subject to a safety inspection and plans to construct plants at inland locations were set aside. The government permitted the construction of coastal plants to restart in late 2012, but it reduced the target for 2020 to 58 GW, down from 80 GW (Xu, 2014). Nevertheless, some 25 GW of the 33 GW of this ‘third wave’ of nuclear plants was in operation by November 2016 (World Nuclear Association, 2016). A large proportion of these plants are CPR-1000s which are Chinese indigenous upgrades of the French designs used at Daya Bay. In addition, two Westinghouse AP-1000s and one EDF EPR reactor were in the final stages of construction as at the end of 2016. The government shaped the nature of the ‘fourth wave’ of nuclear energy capacity in China by decreeing in 2013 that all new plants must be of Generation III designs (King and Ramana, 2015). As of late 2016, some 14.5 GW of capacity is under construction with another 47 GW due to start construction by 2018. A large proportion of these plants are AP-1000s, with some Chinese ACPR-1000s and CAP-1000s, and one Hualong-1. Feasibility studies are also under way for sites inland (World Nuclear Association, 2016). Whilst China has certainly made massive progress in building nuclear energy capacity and developing its own technologies, a number of concerns remain over its ability to manage safety and security. These relate to the fragmented structures of government, the number of companies active in the industry, the short amount of time taken for inspections after the Fukushima disaster, the rapidity of capacity growth, the speed at which new designs are developed and approved and the availability of skilled manpower (Zhou et al., 2011; Xu, 2014; King and Ramana, 2015; Thomas, 2016).

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200   Handbook of energy politics 5.4  Intermittent Renewable Energy The period from 2003 saw a sustained effort by the central government to promote renewable energy. The motivations included boosting total electricity supply, increasing the share of clean energy, encouraging ­technological development and exports and supporting local development and employment. The National Development and Reform Commission (NDRC) launched the first concession bidding round for wind energy in 2003. In this and successive rounds, the lowest bid generally won the concession, but the award decision was also based on the extent of local content (Zhang et al., 2013a). The immediate consequences of the concession programme were to reduce costs, to allow new actors to invest in wind farms, to increase the scale of the wind farms, and to encourage domestic manufacturers (Lema and Ruby, 2007; Wang, 2010; Zhang et al., 2013a). The pace of installation increased so that total capacity reached 2.6 GW by the end of 2006. The Renewable Energy Law of 2005 marked a turning point for China’s renewable energy industry. The new law was reinforced by a number of subsequent policies such as the establishment of a Special Fund for Renewable Energy Development, successive five-year plans for renewable energy development with targets for capacity, the Medium and LongTerm Plan for Renewable Energy Development 2007 and an update of the Catalogue of Chinese High-Technology Products for Export. The Renewable Energy Law itself was revised in 2009 (Zhang et al., 2013b). Together, these and other policies provided a wide range of incentives for actors along the full supply chains for wind energy and solar PV (Zhang et al., 2013b; Andrews-Speed and Zhang, 2015). The Special Fund provided support for research and development and for manufacturing. The Ministry of Science and Technology targeted their funding at the development of progressively larger wind turbines, from 600 kW in Ninth Five-Year Plan (1996–2000) to 2–3 MW in Eleventh Five-Year Plan (2006–2010). Targets were set for installed capacity. Subsidies were available to project developers for constructing wind farms and to the grid companies for integrating renewable energy. The Renewable Energy Law introduced the concept of mandatory market share for any generating company with more than 5 GW of total capacity. Grid companies were mandated to provide access to the grid, not just connection but also dispatch and ancillary services. In return, additional costs could be shared between the grid and end-users. The initial scheme for on-grid tariffs allowed the tariffs to set by the NDRC or through concession bidding. This approach was modified by the revised Renewable Energy Law of 2009 which introduced feed-in tariffs for the first time. Finally, this period saw an increasing use of the Clean Development

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China’s evolving energy policy: the case of electricity  ­201 200 180 160 Consumption TWh

140 120 100 80

Capacity GW

60 40 20 –

2000

2005

2010

2015

Source:  BP (2016).

Figure 8.4  I nstalled wind energy capacity in GW and electricity consumption in TWh in China from 2000 to 2015 (common vertical axis scale) Mechanism which had been applied to 568 wind power projects in China by end of 2010 (Zhang, 2011). As a result of these and other measures, China quickly became a world leader in installed wind power capacity, with 145 GW by the end of 2015 (Figure 8.4), and in wind turbine manufacturing. Notwithstanding this success, actual generation of wind energy was disappointing. Between 2006 and 2009, the share of capacity that was connected to the grid fell from 81 per cent to 68 per cent. The same period saw a rise in wind turbine disconnection and breakdown (Zhang et al., 2013a). The rate of curtailment has generally been above 10 per cent since 2011, and in 2015 reached 15 per cent or 34 TWh (Zhang et al., 2016). The sources of these deficiencies were multiple and lay in the policy and planning processes, in certain characteristics of the nation’s electricity sector, and in the interests of the various actors. At the most basic level, the nationwide data on wind resources has remained inadequate, resulting in the poor siting of many wind farms (Z.Y. Zhao et al., 2016). Although planning is carried out by central government, final project approvals are issued at local level, and local economic interests led to

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202   Handbook of energy politics wind farm construction outstripping grid capacity (Davidson et al., 2016). These challenges were exacerbated by the focusing of planning targets on installed capacity rather than electricity delivered, and by the low level of coordination between the grid companies and the project developers, with the NDRC failing to exert its authority (Zhang et al., 2013a). Two fundamental features of China’s power industry contributed to the high level of curtailment of wind energy. The first was the paucity of flexible power to match the intermittency of wind energy, arising from the shortage of gas-fired power stations and pump storage hydro, and the lack of incentives for coal-fired stations to increase their flexibility (Zhang et al., 2015, 2016; Z.Y. Zhao et al., 2016). Secondly, it is difficult to trade power across the country between balancing areas, as planning and dispatch tends to be carried out at provincial level (Davidson et al., 2016). However, it is the local governments which have played the most active role in the implementation of wind energy policy on account of their prioritization of local economic development, employment and tax revenues. They have provided over-generous support for manufacturing and installation, but have given too little backing for grid connection and dispatch. In particular, some local governments have given preference to dispatching thermal plants over wind farms in order to support local interests (Zhao et al., 2013). Despite the introduction of the Renewable Energy Law and other related measures, the priority for solar PV in the early years of the century remained the export market. Funding for research and development was continued and tens of billions of RMB of low-cost loans were extended to PV manufacturers. Local governments gave these enterprises various forms of assistance including preferential prices for access to land, reduced electricity tariffs, direct investment and various other subsidies (AndrewsSpeed and Zhang, 2015; Gruss and ten Brink, 2016). Until 2009, there were no specific incentives for solar PV installation because the Renewable Energy Law of 2005 emphasized the importance of economic viability (Zhang et al., 2014). The global financial crisis of 2008 led to massive reduction of demand for Chinese PV exports from 2009. With falling international demand, the equipment manufacturers faced an existential crisis. Renewed government support led to the further expansion of production capacity for solar panels to 55 GWp, about 150 per cent of global demand (Zhang et al., 2014). This overcapacity and subsequent cut-throat competition resulted in a sharp decline in module prices from 36 RMB/Wp to 4.5 RMB/Wp between 2007 and 2012 (Lv et al., 2013). The industry reached a crisis in 2013 as Suntech, one of the country’s leading manufacturers of PV equipment, became insolvent and

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China’s evolving energy policy: the case of electricity  ­203 the EU and the USA brought an anti-dumping case against China to the World Trade Organization (Zhang et al., 2014). In order to promote the domestic deployment of solar PV the government launched a series of programmes in 2009 such as the Rooftop Subsidy Programme and the Golden Sun Demonstration Programme (Zhang and He, 2013). To support large-scale solar PV installations, the government introduced a concession bidding programme, similar to that run previously for wind power (Zhang and He, 2013; Zhang et al., 2014). However, these tariffs were too low to provide long-term invectives for project developers. As a consequence, the government introduced the first feed-in tariff scheme for solar PV in 2011. Though an improvement on concession bidding, this scheme failed to take into account variability of solar resource. So the government created a variable feed-in tariff in 2013 to address this deficiency (Zhang et al., 2014). A new package was introduced in 2012 to supplement existing policies for distributed solar PV (Zhang, 2016). However, this package provided insufficient financial compensation to the grid company for connecting and dispatching this distributed energy. Other obstacles included difficulties connecting to the grid and accessing finance. The first half of 2014 saw only 1 GWp of distributed solar PV installed, so the government introduced new policies in 2014 and 2015. These included new models for tariffs, encouragement for banks to make loans and coordination between the NEA and the State Council Leading Group Office on Poverty Alleviation and Development to support the installation of distributed PV in China’s poorer regions (Zhang, 2016). These various incentive schemes for solar PV were successful in that the total installed capacity rose from 0.3 GWp in 2009 to 6.7 GWp in 2012 and to 43.5 GWp by the end of 2015 (Figure 8.5), with 15 GWp installed in that year. Consumption of energy from solar PV increased from 0.3 TWh in 2009 to 39 TWh in 2015, similar to that in the USA and slightly larger than in Germany (BP, 2016). Nevertheless, the full potential of the installed capacity was not achieved for a number of reasons, namely a combination of preferential dispatch of other fuels, grid congestion, low technical standard of the equipment, shortage of trained technicians and ineffective operation of the logistics chain (Kayser, 2016). The combined result of the policies supporting nuclear, wind and solar energy has been to raise the share of non-thermal electricity supply from 17 to 19 per cent in the period before 2005 to 26 per cent and rising in 2015 (Figure 8.6).

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204   Handbook of energy politics 50.0 45.0 40.0 35.0 Capacity GWp

30.0 25.0 20.0 15.0

Consumption TWh

10.0 5.0 – 2005

2010

2015

Source:  BP (2016).

Figure 8.5  I nstalled solar PV capacity in GWp and electricity consumption in TWh in China from 2005 to 2015 (common vertical axis scale) 5.5  Sulphur Dioxide Emissions and Demand-Side Management The Tenth Five-Year Plan (2001–2005) specified the aim of reducing total national SO2 emissions by 10 per cent. To support this target, the government progressively increased the levy on SO2 emissions, introduced a subsidy for plants that installed FGD equipment, and set emission standards for old and new plants. However, the surge in economic growth and in the use of thermal power led to a substantial rise in SO2 emissions rather than a reduction, despite the decline in SO2 intensity of the thermal power industry. This failure to curb emissions was exacerbated by the lack of incentive for local government officials to enforce policy and the high cost of installing and operating FGD equipment (Schreifels et al., 2012). The subsequent five-year plan for 2006–2010 again envisaged a 10 per cent decline in total SO2 emissions, but was accompanied by a specific National Plan for Acid Rain and SO2 Pollution Control. This new approach resulted in closer coordination between the NDRC and the newly created Ministry of Environmental Protection. The emission levy was raised to 1.26 RMB/kg of SO2, for the first time exceeding the cost

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China’s evolving energy policy: the case of electricity  ­205 % 30.0

25.0

Wind and solar Nuclear

20.0

15.0

10.0

Hydro-electricity

5.0

0.0 1990

1995

2000

2005

2010

2015

Source:  Thomson (2003), National Bureau of Statistics (various years), BP (2016).

Figure 8.6  S  hares of non-thermal electricity generation in China, 1990–2015 of mitigation, and the task of collecting the levy was transferred from the local Environmental Protection Bureaus to the Ministry of Finance. Technological advance allowed the continuous monitoring of emissions from thermal power plants and a subsidy of 0.015 RMB/kWh was paid to those plants using the FGD equipment for 90 per cent of the time or more. In addition, local government officials were assessed on their performance against a wide range of environmental objectives, including SO2 emissions targets. As a result of these measures, total SO2 emissions for the power sector peaked in 2006, as did the SO2 emissions intensity, and 90 per cent of China’s thermal power plants had installed FGD equipment by 2011 (Schreifels et al., 2012; Zhao, 2016). However, the economic stimulus of 2010 and 2011 led to a slowing of the rate of decline of total national SO2 emissions at that time (Schriefels et al., 2012), and even an increase over the North China Plain (Krotkov et al., 2016). The public outcry at the worsening air pollution in some of China’s major cities appeared to threaten the legitimacy of the Communist Party. The government responded in 2013 with a National Action Plan on Air Pollution Control, which further tightened emissions standards. As a

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206   Handbook of energy politics result, total SO2 emissions over the period 2011–15 fell 18 per cent, well in excess of the target of 8 per cent (Seligsohn and Hsu, 2016). Further amendments to the Environmental Protection Law in 2015 and to the Law on Air Pollution Prevention and Control in 2016 placed greater responsibilities on local governments as well as enhancing their power, and allowed NGOs to take legal action against polluters. The Ministry of Environmental Protection increased its own powers, not least by obliging local Environmental Protection Bureaus to report to Provincial level departments rather than to their own local governments (Finamore, 2016). As a result, the outlook for further improvements looks bright, though it has been argued that the financial incentive for SO2 abatement remains too low for many plants, depending on location, the quality of the coal used and the number of operating hours (Dong et al., 2015; Liu et al., 2016). Despite the energy shortages at the beginning of the century, the government was slow to apply DSM as an energy-saving strategy. Although both the Medium and Long Term Energy Conservation Plan of 2004 and the revised Energy Conservation Law of 2007 mentioned DSM, little progress was made for a variety of reasons: responsibility for implementing DSM was not clarified after the sector reforms of 2002; there was no funding for DSM nor any economic incentives to pursue DSM and technology, skills and awareness were lacking (Hu et al., 2005). Clear guidance and instruments to support DSM only started to appear from 2010 onwards. Most importantly, the NDRC placed the responsibility for DSM on the provincial grid companies. Financial incentives included loans and tax breaks for energy service companies (ESCOs), subsidies for pilot DSM projects, time-of-use tariffs for industrial and commercial customers and tiered pricing for households. Despite these measures, progress in implementation was slow because the economic incentives were inadequate, ESCOs continued to have difficulty accessing capital, and awareness and skills remained at a low level (Kostka and Shin, 2013; Zhang et al., 2017). The power industry reform policy launched in 2015 made explicit mention of DSM, but did little to adjust the economic incentives (Zhang et al., 2017).

6.  CONCLUSIONS This account of China’s policy processes for the electrical power sector has highlighted a number of significant trends since 1949 that reflect changes within China and the rest of the world. These can be seen in the evolution of the policy agenda, policy design and policy implementation. Whilst the agenda has changed dramatically, the approach to policy design has changed only gradually and the challenges of policy implementation have

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China’s evolving energy policy: the case of electricity  ­207 multiplied. Analysis of this evolution through the lens of public policy theory provides insights into how the policy processes for the electricity industry has been shaped by wider political and economic forces. The policy agenda for energy in China has become progressively more complex, in reaction to changing domestic priorities, external events and ideas from abroad. The number of actors has grown in the energy sector in general, and the power industry in particular. In combination with the decentralization of authority to local governments, this has made the process of policymaking more complex and the coordination of implementation more difficult. In the design of policy, the government has been reluctant to give up the tried and tested administrative instruments in favour of economic instruments. Rather, officials have preferred to stick to what they know, namely deploying exhortation, command and control regulation, direct financial support and state ownership. Market forces have played only a subordinate role in China’s electricity industry. Economic instruments such as subsidies, fines and feed-in tariffs have been deployed but often at too low a level to provide the incentive to change behaviours. This has led to frequent adjustments of policy instrument in order to achieve a programme’s objectives as the agencies learn from experience. For these reasons, China’s electrical power industry over nearly seven decades has been characterized by incremental reform and path dependency. Changes of leadership, shocks and new ideas have led to adjustments of priority but only rarely to changes in approach to policy design and implementation. Nevertheless, the achievements have been substantial. The country now has the largest electrical power industry in the world in terms of total generating capacity as well as renewable energy of different types. It has the largest fleet of supercritical and ultrasupercritical plants, and the largest construction programme of nuclear power. The share of thermal power in the mix is now declining, as is the SO2 intensity of the thermal plants. Further, China has developed a strong indigenous technological prowess in mist forms of electricity generation. All national governments are faced with a complex energy policy agenda that requires careful balancing of economic, environmental and social priorities, as well as the ability to react to external events such as energy market shocks and to public pressure. The fragmented nature of energy governance in China combined with the country’s large size and diversity, renders these challenges especially daunting. However, the staff of the agencies are well used to experimenting, learning and adjusting, and, to use Lindblom’s (1959) term, ‘muddling through’. The problem is that constant adjustment leads to unpredictability, especially if it involves an outright reversal of previous policies. Examples in 2016 include the reimposition of controls over coal prices and the re-centralization of

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208   Handbook of energy politics authority over power plant construction approvals. These two measures reflect a continuing unwillingness to let market forces work in the electricity sector in case power companies go bankrupt and a reluctance to impose stronger pollution charges in order to discourage the construction of thermal plants. At present, China’s electrical power sector remains stranded between the plan and the market, despite the reforms announced in 2015.

REFERENCES Andrews-Speed, P. (2004), Energy Policy and Regulation in the People’s Republic of China, London: Kluwer Law International. Andrews-Speed, P. (2013), ‘Reform postponed. The evolution of China’s electricity markets’, in F. Sioshansi (ed.), Evolution of Global Electricity Markets. New Paradigms, New Challenges, New Approaches, Amsterdam: Elsevier. Andrews-Speed, P. and Z. Cao (2005), ‘Prospects for privatisation in China’s energy sector’ in S. Green and G.S. Liu (eds.) Exit the Dragon? Privatization and State Ownership in China, London: Royal Institute for International Affairs, pp. 196–213. Andrews-Speed, P. and S. Zhang (2015), ‘Renewable energy finance in China’, in C.W. Donovan (ed.), Renewable Energy Finance, London: Imperial College Press, pp. 175–94. Baumgartner, F.R., C. Breunig, C. Green-Pedersen, B.D. Jones, P.B. Mortensen, M. Nuytemans and S. Walgrave (2009), ‘Punctuated equilibrium in comparative perspective’, American Journal of Political Science 53, 603–20. Boushey, G. (2013), ‘The punctuated equilibrium theory of agenda setting’, in E. Araral Jr., S. Fritzen, M. Howlett, M. Ramesh and X. Wu (eds.), Routledge Handbook of Public Policy, London: Routledge, pp. 138–52. BP (2016), BP Statistical Review of World Energy, London: BP. Carin, R. (1969), ‘Power industry in communist China’, Communist China Problem Research series EC44, Union Research Institute, Hong Kong. China Electricity Council (various years), Annual Data, available at http://www.cec.org.cn/ guihuayutongji/tongjxinxi/niandushuju/ (accessed 21 September 2016). Davidson, M.R., F. Kahrl and V. Karplus (2016), ‘Towards a political economy framework for wind power. Does China break the mould?’, Working Paper 2016/32, United Nations University, World Institute for Development Economics Research. Dong, L., H. Dong, T. Fujita, Y. Geng and M. Fujii (2015), ‘Cost-effectiveness analysis of China’s sulphur dioxide control strategy at the regional level: regional disparity, inequity and future challenges’, Journal of Cleaner Production 90, 345–59. Dorian, J.P. (1994), Minerals, Energy and Economic Development in China, Oxford: Clarendon Press. Du, L., Y. He and J. Yan (2013), ‘The effects of electricity reforms on productivity and efficiency of China’s fossil fuel power plants: An empirical analysis’, Energy Economics 40, 804–12. Economy, E. (2004), The River Runs Black. The Environmental Challenge to China’s Future, Ithaca, NY: Cornell University Press. Fang, D., D. Lew, P. Li, D.M. Kammen and R.Wilson (1998), ‘Strategic options for reducing CO2 in China: Improving energy efficiency and using alternatives to fossil fuels’, in M.B. McElroy, C.P. Nielsen and P. Lydon (eds.), Energizing China. Reconciling Environmental Protection and Economic Growth, Cambridge, MA: Harvard University Press. Fawthorp, T. (2016) ‘Saving the Salween: Southeast Asia’s last major undammed river’, The Ecologist, 13 June 2016. Available at http://www.theecologist.org/News/news_analy​ sis/2987798/saving_the_salween_southeast_asias_last_major_undammed_river.html (accessed 5 October 2016).

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China’s evolving energy policy: the case of electricity  ­209 Finamore, B.A. (2016), ‘Tackling pollution in China’s 13th five-year Plan: emphasis on enforcement’, National Resource Defence Foundation, 11 March 2016, available at https://www.nrdc.org/experts/barbara-finamore/tackling-pollution-chinas-13th-five-yearplan-emphasis-enforcement (accessed 2 December 2016). Finamore, B.A. and T.M. Szymanski (2002), ‘Taming the dragon’s head: Controlling air emissions from power plants in China – An analysis of China’s air pollution policy and regulatory framework’, Environmental Law Reporter 32 (11439). Geall, S. and A. Ely (2015) ‘Innovation for sustainability in a changing China: Exploring narratives and pathways’, STEPS Working Paper 86, Brighton: STEPS Centre. Gruss, L. and T. ten Brink (2016), ‘The development of the Chinese photovoltaic industry: An advancing role for the state’, Journal of Contemporary China 25, 453–66. Hayes, M.T. (2013), ‘Incrementalism’, in E. Araral Jr., S. Fritzen, M. Howlett, M. Ramesh and X. Wu (eds.), Routledge Handbook of Public Policy, London: Routledge, pp. 287–98. Howlett, M. and S. Giest (2013), ‘The policy-making process’, in E. Araral Jr., S. Fritzen, M. Howlett, M. Ramesh and X. Wu (eds.), Routledge Handbook of Public Policy, London: Routledge, pp. 17–28. Howlett, M. and M. Ramesh (2003), Studying Public Policy. Policy Cycles and Policy Subsystems, second edition, Oxford; Oxford University Press. Hu, Z., D. Moskovitz and J. Zhao (2005), ‘Demand-side management in China’s restructured power industry’, ESMAP Report, World Bank, Washington, DC. International Energy Agency (2006), ‘China power sector reforms. Where to next?’ Paris: OECD/IEA. International Energy Agency (2015), ‘Gas. Medium-term market report 2015. Market analysis and forecasts to 2020’, Paris: OECD/IEA. Johnson, T.M. (1992), ‘China’s power industry, 1980–1990: Price reform, and its effect on energy efficiency’, Energy 17, 1085–92. Jones, B.D. (2001), Politics and the Architecture of Choice: Bounded Rationality and Governance, Chicago: University of Chicago Press. Jones, B.D. (2003), ‘Bounded rationality and political science: Lessons from public administration and public policy’, Journal of Public Administration Research and Theory 13, 395–412. Kayser, D. (2016), ‘Solar photovoltaic projects in China: High investment risks and the need for institutional response’, Applied Energy 174, 144–52. King, A. and M.V. Ramana (2015), ‘The China syndrome? Nuclear power growth and safety after Fukushima’, Asian Perspective 39, 607–36. Kingdon, J.W. (2011), Agendas, Alternatives, and Public Policies, updated second edition, Boston: Longman. Kiser, E. (1999), ‘Comparing varieties of agency theory in economics, political science, and sociology: An illustration from state policy implementation’, Sociological Theory 17, 146–70. Kostka, G. and K. Shin (2013), ‘Energy conservation through energy service companies: Empirical analysis from China’, Energy Policy 52, 748–59. Krotkov, N.A., C.A. McLinden et al. (2016), ‘Aura OMI observations of regional SO2 and NO2 pollution changes from 2005 to 2015’, Atmospheric Chemistry and Physics 16, 4605–29. Lema, A. and K. Ruby (2007), ‘Between fragmented authoritarianism and policy coordination: Creating a Chinese market for wind energy’, Energy Policy 35, 3879–90. Lew, D.J. (2000), ‘Alternatives to coal and candles: wind power in China’, Energy Policy 28, 271–86. Li, B. and J.P. Dorian (1995), ‘Change in China’s power sector’, Energy Policy 23, 619–26. Li, X. (2015), ‘Natural gas in China: A regional analysis’, OIES Paper NG 103, Oxford: Oxford Institute of Energy Studies. Lieberthal, K.G. and M. Oksenberg (1988), Policy Making in China. Leaders, Structures and Processes, Princeton: Princeton University Press.

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210   Handbook of energy politics Lindblom, C.E. (1959), ‘The science of “muddling through”’, Public Administration Review 19, 79–88. Liu, W.Q., L. Gan and X.L. Zhang (2002), ‘Cost-competitive incentives for wind energy development in China: institutional dynamics and policy changes’, Energy Policy 30, 753–65. Liu, X., B. Lin and Y. Zhang (2016), ‘Sulfur dioxide emission reduction of power plants in China: current policies and implications’, Journal of Cleaner Production 113, 133–43. Lv, F., H. Xu and S. Wang (2013), ‘National survey report of PV power applications in China, 2012’, Paris: International Energy Agency. Ma, C. and X. Zhao (2015), ‘China’s electricity market restructuring and technology mandates: plant-level evidence for changing operational efficiency?’,  Energy Economics 47, 227–37. Marier, P. (2013), ‘Policy feedback and learning’, in E. Araral Jr., S. Fritzen, M. Howlett, M. Ramesh and X. Wu (eds.), Routledge Handbook of Public Policy, London: Routledge, pp. 401–14. Matland, R.E. (1995), ‘Synthesizing the implementation literature: The ambiguity-conflict model of policy implementation’, Journal of Public Administration Research and Theory 5, 145–74. McConnell, A. (2013), ‘Learning from success and failure?’ in E. Araral Jr., S. Fritzen, M. Howlett, M. Ramesh and X. Wu (eds.), Routledge Handbook of Public Policy, London: Routledge, pp. 484–94. Meng, M., S. Mander, X. Zhao and D. Niu (2016), ‘Have market-oriented reforms improved the electricity generation efficiency of China’s thermal power industry? An empirical analysis’, Energy 114, 734–41. Myllyvirta, L. and X. Shen (2016), ‘Burning money. How China could squander over one trillion yuan on unneeded coal-fired capacity’, Beijing: Greenpeace. Na, C., J. Yuan, Y. Xu and Z. Hu (2015), ‘Penetration of clean coal technology and its impact on China’s power industry’, Energy Strategy Reviews 7, 1–8. National Bureau of Statistics (various years), China Statistics Yearbook, Beijing, China Statistics Press. National Development and Reform Commission (2015) ‘Interpretation of power sector reform’ (Beijing: People’s Publishing House) (in Chinese). National Development and Reform Commission and National Energy Administration (2015) ‘Trial measures for cost supervision and examination for the determination of transmission and distribution tariffs’, NDRC Price Document [2015] No. 1347. Available at http://jgs. ndrc.gov.cn/zcfg/201506/t20150619_696575.html (accessed 20 October 2016) (in Chinese). Nolan, P. (2001), China and the Global Business Revolution, Basingstoke: Palgrave. Nyman, J. and J. Zeng (2016), ‘Securitization in Chinese climate and energy politics’, WIRES Climate Change 7, 301–13. Pan, J., W. Peng et al. (2006), ‘Rural electrification in China, 1950–2004, Program on Energy and Sustainable Development’, Working Paper No. 60, Stanford University. Pierson, P. (2004), Politics in Time. History, Institutions and Social Analysis, Princeton: Princeton University Press. Ramana, M.V. and E. Saikawa (2011), ‘Choosing a standard reactor: International competition and domestic politics in Chinese nuclear policy’, Energy 36, 6779–89. Rochefort, D.A. and K.P. Donnelly (2013), ‘Agenda setting and political discourse’, in E. Araral Jr., S. Fritzen, M. Howlett, M. Ramesh and X. Wu (eds.), Routledge Handbook of Public Policy, London: Routledge, pp. 189–203. Rutkowski, R. (2013), ‘The economics of nuclear power in China’, China Economic Watch, Petersen Institute for International Economics, available at https://piie.com/blogs/chinaeconomic-watch/economics-nuclear-power-china (accessed 6 December 2016). Sabatier, P.A. (1986), ‘Top-down and bottom-up approaches to implementation research: a critical analysis and suggested synthesis’, Journal of Public Policy 6, 21–48. Sang, D. (2011), ‘Nuclear energy development in China’, in Yi-chong Xu (ed.), Nuclear Energy Development in Asia. Problems and Prospects, Basingstoke: Palgrave Macmillan, pp. 43–67.

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China’s evolving energy policy: the case of electricity  ­211 Schattschneider, E.E. (1960), The Semisovereign People: A Realist’s View of Democracy in America, Hinsdale Illinois: Dryden Press. Schneider, A. and H. Ingram (1988), ‘Systematically pinching ideas: A comparative approach to policy design’, Journal of Public Policy 8, 61–80. Schreifels, J.J., Y. Fu and E. Wilson (2012), ‘Sulfur dioxide control in China: Policy evolution during the 10th and 11th Five-year Plans and lessons for the future’, Energy Policy 48, 779–89. Seligsohn, D. and A. Hsu (2016), ‘How China’s 13th Five-year Plan addresses energy and the environment’, ChinaFile, 10 March 2016, available at https://www.chinafile.com/ reporting-opinion/environment/how-chinas-13th-five-year-plan-addresses-energy-andenvironment (accessed 2 December 2016). Shyu, C.W. (2012), ‘Rural electrification program with renewable energy sources: An analysis of China’s Township Electrification Program’, Energy Policy 51, 842–53. Smil, V. (1984), The Bad Earth. Environmental Degradation in China, Armonk, NY: M.E. Sharpe. Sovacool, B.K. and S.V. Valentine (2012), The National Politics of Nuclear Power, Abingdon: Oxford. State Planning Commission (1995), ‘95 Energy Report of China, Beijing: State Planning Commission. Sun, G. (2010), ‘Coal in China: Resources, uses, and advanced coal technologies’, White Paper series, Pew Centre on Global Climate Change, Arlington VA. Thomas, S. (2016), ‘China’s nuclear export drive: Trojan Horse or Marshall Plan?’, Energy Policy, in press. Thomson, E. (2003), The Chinese Coal Industry: An Economic History, London: RoutledgeCurzon. Tilt, B. (2015), Dams and Development in China. The Moral Economy of Water and Power, New York: Columbia University Press. Vedung, E. (2013), ‘Six models of evaluation’, in E. Araral Jr., S. Fritzen, M. Howlett, M. Ramesh and X. Wu (eds.), Routledge Handbook of Public Policy, London: Routledge, pp. 387–400. Wang, H.H. (1999), China’s Oil Industry and Market, Amsterdam: Elsevier. Wang, Q. (2010), ‘Effective policies for renewable energy – the example of China’s wind power – lessons for China’s photovoltaic power’, Renewable and Sustainable Energy Reviews 14, 702–12. World Bank (1997), Cost of Pollution in China. Economic Estimates of Physical Damages, Washington, DC: World Bank. World Nuclear Association (2016), ‘Nuclear power in China’, updated 30 November 2016, World Nuclear Association, London. Xu, Y.C. (2002), Powering China. Reforming the Electrical Power Sector in China, Aldershot: Ashgate. Xu, Y.C. (2010), The Politics of Nuclear Energy in China, Basingstoke: Palgrave Macmillan. Xu, Y.C. (2014), ‘The struggle for safe nuclear expansion in China’, Energy Policy 73, 21–29. Xu, Y.C. (2017), Sinews of Power. Politics of the State Grid Corporation of China, Oxford: Oxford University Press. Yang, M. and X. Yu (1996), ‘China’s power management’, Energy Policy 8, 735–57. Yeager, B. (2016), ‘Pushing the ultra envelope: advanced power reactor technologies are mainstream in China’, Power, 11 January 2016. Available at http://www.powermag.com/ pushing-ultra-envelope-advanced-power-technologies-mainstream-china/ (accessed 11 November 2016). Yeh, E.T. and J.I. Lewis (2004), ‘State power and the logic of reform in China’s electricity sector’, Pacific Affairs 77, 437–65. Yuan, J., C. Na and M. Yang (2016a), ‘Energy efficiency and conservation in China’s power sector: progress and prospects’, in B. Su and E. Thomson (eds.), China’s Energy Efficiency and Conservation. Sectoral Analysis, Singapore: Springer, pp. 5–21.

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212   Handbook of energy politics Yuan. J., P. Li, Y. Wang, Q. Liu, X. Shen, K. Zhang and L. Dong (2016b), ‘Coal power overcapacity and investment bubble in China during 2015–2020’, Energy Policy 97, 136–44. Zeng, M., S. Xue, M. Ma, L. Li, M. Cheng and Y. Wang (2013) ‘Historical review of demand side management in China: management content, operation mode, results assessment and relative incentives’, Renewable and Sustainable Energy Reviews 25, 470–82. Zhang, S. (2016), ‘Analysis of DSPV (distributed solar PV) power policy in China’, Energy 98, 92–100. Zhang, S. and Y. He (2013), ‘Analysis on the development and policy of solar PV in China’, Renewable and Sustainable Energy Reviews 21, 393–401. Zhang, S., P. Andrews-Speed, X. Zhao and Y. He (2013a), ‘Interactions between renewable energy policy and renewable energy industrial policy: A critical analysis of China’s policy approach to renewable energies’, Energy Policy 62, 342–53. Zhang, S., X. Zhao, P. Andrews-Speed and Y. He (2013b), ‘The development trajectories of wind power and solar PV power in China: A comparison and policy recommendations’, Renewable and Sustainable Energy Reviews 26, 322–31. Zhang, S., P. Andrews-Speed and M. Ji (2014). ‘The erratic path of the low-carbon transition in China: Evolution of solar PV policy’, Energy Policy 67, 903–12. Zhang, S., P. Andrews-Speed and P. Perera (2015), ‘The evolving policy regime for pumped storage hydroelectricity in China: A key support for low-carbon energy’, Applied Energy 150, 15–24. Zhang, S., S. Yin, P. Andrews-Speed and W. Li (2016), ‘Economic and environmental effects of peak regulation using coal-fired power for the priority dispatch of wind power in China’, under review. Zhang, S., Y. Jiao and W. Chen (2017), ‘Demand-side management (DSM) in the context of China’s on-going power sector reform’, Energy Policy 100, 1–8. Zhang, Z. (1998), The Economics of Energy Policy in China. Implications for Global Climate Change, Cheltenham, UK and Northampton, MA, USA: Edward Elgar Publishing. Zhang, Z. (2011), Energy and Environmental Policy in China. Towards a Low-Carbon Economy, Cheltenham, UK and Northampton, MA, USA: Edward Elgar Publishing. Zhao, X. (2016), ‘Issues in greening China’s electricity sector’, in L. Song, R. Garnaut, C. Fang and L. Johnson (eds.), China’s New Sources of Economic Growth. Vol. 1. Reform, Resources and Climate Change, Canberra: Australian National University Press, pp. 449–78. Zhao, X., S. Zhang, Y. Zou and J. Yao (2013), ‘To what extent does wind power deployment affect vested interests? A case study of the Northeast China Grid’, Energy Policy 63, 814–22. Zhao, X., S. Li, S. Zhang, R. Yang and S. Liu (2016), ‘The effectiveness of China’s wind power policy: An empirical analysis’, Energy Policy 95, 269–79. Zhao, Z.Y., R.D. Chang and Y.L. Chen (2016), ‘What hinder the further development of wind power in China? – A socio-technical barrier study’, Energy Policy 88, 465–76. Zhou, Y., C. Rengifo, P. Chen and J. Hinze (2011), ‘Is China ready for nuclear expansion?’, Energy Policy 39, 771–81.

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9.  Natural resource-led development in Sub-Saharan Africa: a role for local content and small, medium enterprises Rene Roger Tissot

INTRODUCTION Such is the importance of industrialization on productivity and economic growth that it is often taken as synonymous with economic development (Szirmai et al. 2013).1 States in Sub-Saharan Africa (SSA)2 have failed to industrialize despite numerous efforts and strategies adopted since they achieved independence over the period 1950–70 (Whitfield et al. 2015).3 Meanwhile, the development of global value chains is reducing opportunities for SSA’s industrialization and, without it, the region is at risk of remaining at the margins of the global economy. Over the last decade, however, SSA’s economies have achieved historic levels of growth resulting from high commodity prices. This boom has led to a growing interest among policymakers and economic researchers in formulating a natural resource-based industrialization strategy for the region. One of the policies considered by SSA countries in their natural resource industrialization efforts is the adoption of local content requirements. The objective of local content policies (LCP) is to increase linkages between the multinational companies (MNCs) and the rest of the economy. As suggested by Hansen, “If African countries are to benefit fully from the current boom in foreign direct investments (FDI) in extractives (i.e., mining and oil/gas) it is essential that the foreign investors foster linkages to the local economy” (Hansen et al. 2009).4 The paper is organized as follows: The first section provides a short historic perspective of Sub-Saharan Africa’s difficulties in achieving industrialization. The second section discusses the attraction of a natural resource-based industrialization strategy for SSA by using local content policies, as an alternative to previous failed industrialization strategies. The third section introduces the idea of the “missing middle” referring to the lack of formal small and medium-sized firms in SSA and points to the fact that to achieve industrialization, SSA must address the missing middle problem. The fourth section introduces three emerging trends that offer an opportunity for SSA to close the missing middle if proper policies are 213

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214   Handbook of energy politics adopted. These trends are: rapid urbanization, demographic changes and the surge of Chinese private investments in manufacturing. This document is the result of an extensive review of literature, numerous meetings with government officials, international oil companies (IOCs) and local entrepreneurs and conference participation.

FAILED INDUSTRIALIZATION, A SUB-SAHARAN AFRICAN STORY SSA’s industrialization efforts have shown disappointing results. According to Page “Africa’s industrial sector is in many ways less advanced than in the first decade following independence” (Page 2011).5 Despite some incipient efforts during the colonial period, it was only after independence that the emerging nations of SSA developed a concerted effort toward industrialization. Most countries adopted import substitution strategies inspired by the examples of rapid industrial transformation in Latin America and other emerging economies at the time (Mendes et al. 2014).6 However, there were numerous challenges facing the new nations of SSA at the beginning of their industrialization efforts. The countries lacked a local business elite, impoverished governments did not have access to capital or experienced institutions to implement policies and a large percentage of the population lacked basic skills, access to technology and was engaged in traditional subsistence farming. Nascent governments opted to attract foreign capital by offering tax advantages to investors. Most of the resulting new factories concentrated on non-durable consumer products and/or products for the construction sector. Inadequate infrastructure, local currency volatility, significant human resource capability deficits and the small size of local markets eroded the ability of these fledgling industries to produce goods at competitive prices and/or to foster necessary connections with the rest of the economy. Despite these challenges, SSA achieved a certain level of industrialization. For example, Eastern African countries attained some manufacturing diversity by the mid-1960s, producing goods including foodstuffs, drinks, tobacco, textiles, shoes, clothing and paper (Mendes et al. 2014).7 Governments, however, grew unhappy with the high cost of importing the intermediate and capital goods required by local manufacturers. Some governments opted for a more direct state role in the industrialization process by means of nationalization and the creation of state-owned enterprises. This nationalistic phase of the import substitution process in Africa focused more on job creation and large-scale state-sponsored

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Natural resource-led development in Sub-Saharan Africa  ­215 investment projects. State enterprises grew significantly in terms of jobs, but productivity lagged behind. They also failed to nurture a local entrepreneurial elite. A constraint in SSA during its import substitution phase was the failure to increase agricultural output so as to provide the surplus required to feed the industrialization effort. This resulted in higher imports of food and the raw materials required by local manufacturers. Moreover, efforts to keep local currencies strong to reduce inflationary pressures further weakened the ability of the agricultural sector to compete with cheaper imports, or to increase its exports. The policy of import substitution was abandoned by the 1980s when governments opted instead for economic structural reforms (Whitfield et al. 2015).8 Over the following decades, SSA countries implemented market liberalization policies redirecting the industrialization strategy toward a more export-oriented model. Despite limited successes, such as agro-industrial flower production in Kenya and Ethiopia, most of the export-oriented efforts in SSA failed to produce the desired changes. First, labor costs, even if low, were not as competitive as those in China and other Asian nations. Second, the Asian export-oriented model relies on a low-cost but relatively skilled workforce, which was not readily available in SSA (Takahashi et al. 2007).9 The deficiencies of the transport infrastructure posed another problem for export-oriented efforts. In addition, trade liberalization and market opening policies resulted in a realignment of economic activity favoring foreign direct investments (FDI) in the extractive activities where SSA countries had a competitive advantage, which led to a slump in manufacturing. This strategic realignment resulted in a decline in efforts toward industrialization in SSA by the 1990s. Economic theory and empirical evidence both suggest that the expected evolution of development from an agrarian economy to a post-industrialized one implies a decline in employment in the agricultural sector while employment in the service sector increases. Employment in the industrial sector tends to follow an inverse U-shaped curve, at first increasing rapidly but declining as the country achieves high-income status. However, countries that have achieved high levels of economic development have generally done it by first developing a strong manufacturing sector. The history of modern economic development is in fact the history of industrialization (Szirmai et al. 2013).10 This did not take place in SSA because the region failed to industrialize. As shown in Figure 9.1, the share of manufacturing in Africa has stagnated since the 1950s at around 10 percent of gross domestic product (GDP). Figure 9.1 also shows the share of manufacturing as a percentage of GDP in developed nations falling dramatically. This is due both to the rise of a highly productive service sector and to the outsourcing of

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216   Handbook of energy politics 35

Average 15 Asian countries Average 18 African countries

% manufacturing to GDP

30

Average 21 advanced economies 25 20 15 10 5 0

1950 1955 1960 1965 1970 1975 1980 1985 1990 1995 2000 2005

Source:  From author based on data from International Monetary Fund (2017).11

Figure 9.1  S  hare of manufacturing in GDP. Average of selected countries in three groups: Asia, Africa and advanced economies at 2009 prices ­ anufacturing activities to Asia and other emerging industrialized econom mies. Africa has neither attracted massive industrial activities outsourced from advanced nations, nor developed a highly productive service sector that is able to compensate for the low productivity of its agricultural sector. On the contrary, in SSA people are switching from low productivity agriculture to low productivity service sector activities. To reverse that trend SSA would have to find a different way to industrialize. A number of organizations and experts have suggested a new industrialization strategy based on its geographic competitive advantage in having natural resources, whose exploitation will continue to bring billions of dollars of investments. A number of organizations such as the United Nations Economic Commission for Africa (UNECA 2013) and experts have suggested the benefits of implementing such a strategy.12

LOCAL CONTENT AND NATURAL RESOURCE-LED/ BASED INDUSTRIALIZATION The wealth of Africa’s natural resources is substantial: the continent holds 30 percent of known reserves of minerals in the world, about 10 percent

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Natural resource-led development in Sub-Saharan Africa  ­217 of global oil and 8 percent of gas. These riches constitute a substantial competitive advantage for the continent, and their exploitation has a significant impact on the countries’ economies. Natural resources accounted for 77 percent of Africa’s exports and 42 percent of government revenues in 2012, according to the African Natural Resource Center (ANRC). That year, mining, oil and gas alone represented 28 percent of the continent’s GDP (ANRC 2016).13

Sources: Raw Materials Data, IntierraRMG, 2013 World Bank, Africa Pulse October 2012, Volume 6 IMF, Fiscal Regimes for Extractive Industries: Design and Implementation, 2012 U.S. Geological Survey, Mineral commodity summaries 2013 *Estimates are intended to show order of magnitude. Revenue projections are highly sensitive to assumptions about prices, phasing of production, and underlying production and capital casts **Data represents annual revenue at peak production

Source:  http://environmentalpeacebuilding.org/library/multimedia/infographics/show/ libraryitem-1488.

Figure 9.2 Mapping Africa’s mineral wealth: selected countries and commodities

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218   Handbook of energy politics Not surprisingly, when commodity prices boomed during the last decade, SSA enjoyed high rates of economic growth. According to McKinsey, real GDP rose by 4.9 percent per year from 2000 through 2008, more than doubling the rate of growth achieved in the 1980s and 1990s (Leke et al. 2010).14 Subsequently, in 2015 when commodity prices collapsed foreign direct investments declined sharply, contributing to the fall in economic activity. RMB Global Markets reports15 that the total value of capital expenditures in SSA dropped from $88.5 billion in 2014 to $77.1 billion in that year alone. However, despite the lower investment level, capital expenditures were still higher than the $68 billion annual average achieved between 2010 and 2014. It is expected that in future despite a decline in commodity prices, natural resource activities will continue to be one of the key drivers of economic growth in SSA. MNCs will continue to pour large sums of capital into the hydrocarbon and mining sectors. Most entrepreneurs agree about the likely level of future activity in SSA’s natural resource sector. According to a 2015 Ernst & Young survey,16 46.5 percent of its respondents said they thought oil, gas and minerals were the sectors with the highest growth potential in SSA. The driver of natural resource-based industrialization is through linkages that can be created as a result of the investments made from the exploitation of the natural resources. There are basically three types of linkages: 1. fiscal, 2. consumption and 3. production (Hirschman 1981).17 Fiscal linkages refer to those created by the revenues gained by the government from the payment of taxes and royalties. These could be used for industrial development. However, the impact of doing so would depend on the ability of political elites to identify the correct sectors or areas in which to invest the revenues. Consumption linkages refer to those that arise from the growth of aggregated demand in the local economy as a result of the exploitation of natural resources. The lower the manufacturing base of an economy, the higher the likelihood that income used for consumption will be spent on imports, particularly if the exploitation of resources leads to a rapid currency appreciation. Production linkages are those emerging as a result of the consumption of goods and services by firms exploiting natural resources. These are the linkages that are important for the industrialization strategy (Kaplinsky 2011).18 There are two types of production linkages: 1. “backward linkages,” which refers to the demand-side connections a firm has with other ­existing firms. In the case of an oil, gas or mining project, it refers to the ­procurement done by the operating company with local firms. 2.  “Forward linkages” refers to the supply-side connections a firm has with other existing firms (Hefner and Guimares 1994).19 In the case of an

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Natural resource-led development in Sub-Saharan Africa  ­219 oil or mining project, forward linkages are the sales of petroleum, natural gas or raw minerals to local refining, petrochemical or mineral processing firms that transform the raw material into final products. The impacts of backward and forward linkages depend on the level of concentration of an industry supply chain (Hansen et al. 2009).20 A supply chain can be described as a set of activities “organized around the flow of materials from source of supply to finished products, after-sale services, and often also recycling” (Nordas et al. 2003).21. The higher the concentration of the supply chain, the lower the possibilities for linkages. In recent years, supply chains have become more global, resulting in the physical separation of management and manufacturing activities. Firms are able to offshore or outsource many tasks. This physical separation has resulted in the emergence of global supply chains in which firms outsource specific activities to local suppliers in countries that offer competitive advantages. Developing countries can enter into specific niches of the global supply chains, but it is more difficult for them to create local ones, limiting policy options for industrialization. In developing countries with large mineral or hydrocarbon resources, policymakers believe that some of those limitations can be addressed through LCP. Typically, LCP seeks to promote local participation by directing the utilization of local companies in the procurement of good and services, employment of locals and use of local raw materials by foreign investors from MNCs (Tordo et al. 2013).22 As shown in Figure 9.3, ­developing linkages from natural resource exploitation activities has an obvious attraction because of the high level of spending on procurement that is involved. The larger the share of the spending that stays in the country, the higher the opportunities for economic linkages, job creation and economic growth. One key goal of a natural resource-based industrialization strategy is to diversify the type of goods a country exports in order to increase the level of sophistication of its exports. If a country’s exports are dependent on a narrow range of primary products, we consider that country to lack “sophistication” in its export base. This concept is important since there is a correlation between the level of “sophistication of exports” of a developing nation and its growth rate (Hausmann et al. 2005).23 Countries that produce and export a high proportion of products that are also produced by richer economies grow faster. SSA countries lack sophistication in their exports; that is, countries are dependent on a narrow range of primary products. Increasing the sophistication of exports in SSA is more likely to succeed if the entities involved in the natural resource activity are able to foster strong linkages with local firms. LCP’s goal is to promote the development of those linkages.

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220   Handbook of energy politics 60

Mining Oil and Gas

40 20 0

Employment, Infrastructure and procurement

Government Revenue

Investor returns

Social Investment

Average distribution of spending in extractive projects

Mining

Oil and Gas

Government Revenue

15%–20%

30%–40%

Social Investment

1%

1%

Employment, Infrastructure and procurement

50%–65%

40%–50%

Investor returns

15%–20%

20%–30%

Adapted from Source:  Flagship Report Series. Paper 6. “Creating Local Content for Human Development in Africa’s New Natural Resource Rich Countries.” Africa Development Bank, Bill & Melinda Gates Foundation (2015).

Figure 9.3  Average distribution of spending in extractive projects However, the adoption of LCP in SSA appears to have achieved, until now, modest results. Most of the linkages in SSA arising from LCP are very thin in “breadth” – the proportion of inputs sourced locally or outputs processed locally – and “depth,” or the extent of domestic value that is added locally (Morris et al. 2011).24 One reason for this poor performance is due to the challenging business environment in which local firms operate, reflected by the low ranking by most of SSA on the “Cost of Doing Business” indicators published by the World Bank. In the list of the 50 worst performing countries, 38 are from SSA (Gelb et al. 2014).25 The “Cost of Doing Business” is often used as an indicator of the business environment in a country. This poor business environment encourages a situation where there are only two groups of firms capable of surviving. The first is a large group of micro firms, able to cope with the poor business environment by operating informally, minimizing costs and not investing in capital expansion. The second group is the large well-established firms, which tend to enjoy dominant or even monopolistic positions in their own small domestic markets; as such they can compensate for the poor business environment by capturing high rents. If SSA is going to consider a natural resource-based industrialization strategy using local content policies as a mechanism to develop linkages

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Natural resource-led development in Sub-Saharan Africa  ­221 with local firms, it must also address the difficult environment in which local firms operate, which gives rise to the missing middle problem.

THE MISSING MIDDLE: A CHALLENGE FOR SSA INDUSTRIALIZATION Economic evolution in the SSA area does not follow the classical transition of an agrarian economy to manufacturing and finally to a service economy. One reason for this particular development could be the composition of companies, and in particular the makeup of those in the manufacturing sector. SSA is characterized by having two very different types of companies occupying the same small national market. First, a small number of large firms, which tend to capture a high percentage of the value added generated by the manufacturing sector. In Kenya, for example, the five largest companies account for 58 percent of the total value added in that country (Gelb et al. 2014).26 Second, there exist a very large number of micro firms with low productivity, often operating informally. Many of these are the result of a labor force growing at a higher rate than the formal economy can absorb (Fox and Sohensen 2012).27 What seems to be missing in SSA is a large and competitive group of small and medium-sized enterprises (SMEs). These are companies operating in the formal sector, employing 10 to 250 employees, with a turnover of more than $200,000 per year (Sveinung et al. 2010).28 The reasons for the missing SMEs in SSA are 1. difficult business environment, and in particular financial consequences of corruption; 2. problematic electric power supply; 3. ownership structure of firms; and 4. limited options for SMEs to access credit (Gelb et al. 2014).29 The financial impact of corruption is of particular importance when assessing the lack of SMEs in SSA. Large firms are able to pass the costs of corruption on to their customers due to their monopolistic power. Micro firms operate informally; as such they do not pay taxes and are less exposed to bureaucratic scrutiny. By contrast, formally established SMEs are exposed to constant harassment from unscrupulous bureaucracy since they have to comply with the laws and regulations of the country (Ousman and Hallward-Driemeier 2012).30 Poor power supply is often mentioned as one of the major challenges for businesses seeking to grow and expand in SSA (Gelb et al. 2007).31 The negative impact of poor electricity supply affects SMEs most. Large firms are able to deal with a deficient electricity supply by investing in their own generation capacity. This, of course, results in higher costs, limiting their ability to compete in international markets. But since in their own small

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222   Handbook of energy politics

Micro

Number to time

Low-Income Countries

Number to time

High-Income Countries

SMEs

Large

Micro

The Missing Middle

SMEs

Large

Source:  https://www.hks.harvard.edu/centers/cid/programs/ entrepreneurial-finance-lab-research-initiative/the-missing-middle.

Figure 9.4  The missing middle gap local markets they are the dominant players, they can afford the high cost of power. The third segment, the micro firms, often uses illegal electric connections and/or avoid paying electricity bills. Once again SMEs are the main victims, having to endure a substandard service for which, nonetheless, they are fully charged. The different avenues of access to credit also lead to the U-shaped system shown in Figure 9.4 and prevalent in SSA (Kauffman 2005).32 The development of micro financing schemes aimed at reducing poverty has helped many micro firms gain access to capital to fund their small operations. Micro financing may have had an important impact in terms of poverty reduction, but its contribution to industrial development is less obvious. Larger firms are able to access credit from domestic or international banking institutions because of their dominant market power. By contrast, small and medium-sized companies’ credit options are limited to the local banks, which means they are often exposed to very high interest rates and required to produce costly collateral. The dual structure of firms in SSA is also characterized by the nature of its owners. Indeed, the majority of large firms in SSA are owned by ethnic minorities. These firms are responsible for a large share of the value creation in manufacturing activities. The advantage of ethnic minorities’ firms is due to their extended networks that help them to diversify activities, countries of operation and sources of financing (Ramachandran and Shah 2007).33 These firms are mostly family-owned and often bring with them years of experience and expertise built by generations of entrepreneurs who evolved from merchants to manufacturers. By contrast, a large proportion of the informally operating micro firms are owned and ­operated by locals

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Natural resource-led development in Sub-Saharan Africa  ­223 who do not have any of these support structures. These have resulted in the past in political tensions and exposed entrepreneurs to nationalistic policies discriminating against ethnic minorities’ firms. The absence of SMEs is preventing SSA countries from obtaining sustained levels of economic growth and achieving industrialization. On average, in high-income countries, the contribution to GDP by SMEs is 60 percent. In SSA, the contribution of SMEs to GDP is less than 20 percent (Kauffman 2005).34 This problem is exacerbated by the “enclave” characteristics of natural resource activities. In fact, SSA can be described as an archipelago of a few MNCs unable or unwilling to connect with local firms. MNCs tend to favor a centralized procurement process where suppliers offer global solutions; this is even more relevant as MNCs tend to set up global supply chains. Assuming local firms are able to meet quality standards, MNCs also prefer a healthy level of competition among suppliers. Having a reduced number of local firms operating in a country limits the ability of MNCs to develop linkages. Therefore, LCP on its own is not sufficient for natural resource-based industrialization to thrive in SSA. Without a larger number of viable SMEs, it is unlikely that a natural resource-based industrialization strategy would be successful because of the limited options for developing linkages.

CLOSING THE MISSING MIDDLE The first and obvious step to solve the missing middle is to address all the issues that lead to its emergence in the first place: lack of power supply, corruption and poor infrastructure to name just a few. Solutions to these problems are beyond the scope of this chapter. However, if properly designed LCPs are implemented, capturing the benefits of three key trends may help change some of the limitations for increasing the number of SMEs (Gelb et al. 2014):35 1. rapid urbanization, 2. growth of the working age population, and 3. the surge of private Chinese investments in manufacturing activities in SSA. ●



Rapid urbanization combined with growth of working age population Africa is experiencing the world’s fastest urbanization process. According to McKinsey, “between 2015 and 2045 an additional 24 million people are projected to live in cities each year in Africa, compared to 11 million in India and 9 million in China” (Bughin et al. 2016).36 Since cities offer better access to infrastructure, education and services to population living in rural areas, a rapid process of

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224   Handbook of energy politics urbanization increases productivity. African urban GDP is almost three times higher than rural GDP. The rapid process of urbanization is supported by high rates of population growth and migration from rural to urban centers. In recent years, SSA has experienced a significant change in its population composition, with a large cohort of young adults beginning to enter the workforce (Canning et al. 2015).37 This transition could lead to a situation where a large working age population boosts demand growth, yielding what is known as the demographic dividend. However, to capture that dividend SSA policymakers must create the conditions to expand the demand for labor by strengthening the knowledge and technical capabilities of the workforce and expanding the number of firms operating in the countries, particularly the SMEs.   For resource rich SSA countries, providing preferential market access to local firms through LCP could offer the necessary boost to help industrialization. However, there is abundant literature showing the risks associated with natural resource dependency and the preference for import goods at the expense of the local manufacturing, leading to deindustrialization. However, countries with abundant supply of labor could avoid some of those pitfalls (Yokoyama 1989).38 SSA will experience an almost endless supply of labor over the next decades. According to McKinsey, by 2034 Africa’s working population will overtake that of China or India.39 SSA would then have a large low-cost workforce, mostly concentrated in urban centers, enabling the development of labor-intensive manufacturing opportunities. Rapid urbanization combined with an expanding working age population are two characteristics that did not exist in previous industrialization efforts in SSA.   To be effective and benefit from these two trends, LCP would have to carefully map the supply chain from the extraction activities, focusing on where the countries can best develop linkages based on their long-term industrialization goals and their competitive advantages. Second, the policy must address some of the limitations that have been highlighted in this chapter leading to the missing middle gap. As such, the goal is not just to develop short-term solutions to supply MNCs, but to create the conditions in which the country can master the technologies that would help leapfrog into different industrial activities. ● The surge of private Chinese investments in manufacturing activities in SSA Chinese investments in SSA have increased significantly in the 1990s, led by state-owned corporations seeking access to com-

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Natural resource-led development in Sub-Saharan Africa  ­225 modities, followed by a surge of private business. Estimates of the number of Chinese enterprises in Africa vary widely, from a conservative assessment of 8,000 firms by the Chinese EXIM Bank to 28,000 or more as suggested by Chinese diplomats (Gu 2009).40 The vast majority of these are privately owned SMEs, and most of them are involved in manufacturing activities.   The decision by Chinese private entrepreneurs to invest in Africa is due to 1. the fast-growing market opportunities the region has to offer, 2. excessive levels of competition in China, and 3. the entrepreneurs’ confidence of success in markets that operate in challenging business environments. Their business model is based on low-cost production and a high level of flexibility and adaptability to the changing and often uncertain market and political conditions of SSA. Although some of these entrepreneurs benefitted from access to capital from Chinese state banks, most of them did not rely on Chinese government sponsored programs or assistance. Instead these entrepreneurs followed a strategy in which their activities as traders, bringing manufactured output from China to Africa, eventually evolved into establishing manufacturing capabilities in the region. ● Based on these trends two questions arise: First, can the surge of Chinese entrepreneurs investing in SSA help SSA close the missing middle gap? Second, can LCP in the extractive industry lead to the development of locally own firms and thus help close the missing middle gap? ● Can the surge of Chinese foreign entrepreneurs help SSA close the missing middle gap?   The answer to this question will depend on the ability of SSA’s policies to encourage a much greater level of integration of these manufacturing activities with the rest of the local economy. On the one hand, SSA should benefit from the knowledge, technological capabilities and management know-how of these new entrepreneurs, which through process of learning by doing can be transferred to local entrepreneurs and employees. On the other hand, many of these Chinese firms continue to rely on China’s supply chain and prefer to hire Chinese workers and managers. As such, their impact on local content has been limited (Horta 2015).41   Because these Chinese entrepreneurs bring with them a higher level of technical competency and management skills, they offer opportunities for SSA entrepreneurs to increase their knowledge base. However, for that to occur linkages between Chinese and local firms must be encouraged. This is an area where policymakers

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226   Handbook of energy politics can expand policies encouraging those linkages. Efforts toward bringing both communities together should be promoted through for example cultural awareness activities, business exchanges, scholarships and promotion of Chinese language education in SSA countries. It should be noted that at least some initial efforts toward knowledge transfer are already occurring mostly from large Chinese firms. For example, Huawei in 2014 implemented the “Seeds for the Future” in Kenya, a program aimed at increasing the skills of top engineering students drawn from various local universities. It provides them with the opportunity to learn and apply the latest technologies. The chosen students travel to China for training in Chinese culture, language and innovative information and communication technologies and interaction with top information technology specialists at the Huawei University (Li 2016).42 However, more Chinese SMEs should be encouraged to localize their supply chain and provide capacity training to their local workforce. This should not be an activity limited only to the large Chinese companies such as Huawei. Chinese investments in the African SME sector can be a welcomed development if they are coordinated in a way that encourages skills transfers, open up access to wider markets and in sectors that promote growth, and conducted in a way that does not undermine the activities of the indigenous population. (Mutale 2015)43



As important as ensuring that the new SMEs owned by Chinese and other ethnic minorities increase the linkages of their own supply chain and the employment of locals, is the development of locally owned SSA enterprises. Still, promoting the development of locally owned SMEs should not be done at the detriment of those ethnic minority investors. ● Could LCP in the extractive industry lead to development of locally owned firms and thus help close the missing middle gap? In the absence of a LCP, well-established local firms will have to compete with international ones for a share of the MNC procurement business. However, since in most SSA countries there are only a handful of firms available for hiring by the MNCs to meet their local content requirements, there is the risk that LCP would result in a reallocation of activities from productive ones to ­rent-seeking by the few well-established local firms that would  benefit from LCP. That reallocation would depend on how much the government allows it to occur (Mehlum et al. 2005).44 For LCP to be effective they must aim at increasing the

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Natural resource-led development in Sub-Saharan Africa  ­227 number  of  SMEs, not only protecting existing well-established local ones.   Since the goal of the LCP is not to recreate supply chains in every SSA country rich in minerals or hydrocarbons, the LCP must be based on a clear understanding of local firms’ capabilities vis-à-vis the expected opportunities that could emerge from the procurement needs of MNCs. By mapping what are the manufacturing and service needs of a project, and comparing that with the capabilities available by the local firms, the LCP can target specific sectors of the supply chain, focusing on reducing barriers to entry for new entrepreneurs.   LCP could reduce barriers to entry for locally owned SMEs by mandating MNCs to submit a simplified procurement process, for example by using language accessible to the majority of the local population. A common complaint by local SMEs in SSA is their difficulty understanding the specific procurement requirements because of the format used by the MNCs. Moreover if MNCs are required to present their procurement plans early enough, not only existing but also potential new entrepreneurs would be able to assess the emerging market opportunities. Simplification of the procurement process can also be achieved if the LCP requires SMEs to adhere to nationally set standards accepted by all MNCs operating in the country. A common complaint by SMEs is the diversity of standards required by MNCs – reflecting their preference for using standards they are familiar with or are accepted in their country of origin.   Providing innovative access to credit mechanisms would reduce the limitations that often affect locally own firms when seeking credit from local banks. Moreover, barriers to SMEs can be removed by encouraging MNCs to unbundle some of their procurement orders, making smaller orders accessible to local firms. Working with local banks, MNCs can also develop mechanisms in which their procurement orders can be accepted as collateral from local firms by local banks.   To encourage the creation of new businesses, data shows that having a university degree is a significant determining factor in the performance and rate of growth of locally owned firms (Ramachandran and Shah 2007).45 As such, parallel to a LCP is the need to enhance the technical capabilities of the local workforce, in addition to expanding the business acumen of university graduates. Overall, LCPs must encourage the strengthening of business training at universities and technical schools.   Finally, policymakers should take into account the impact that

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228   Handbook of energy politics other policies may have on local firms’ competitiveness. For example, as reported by the Columbia Center on Sustainable Investment study, it is common in SSA to grant import duty exceptions to MNCs, thus crowding out domestic suppliers who often are required to pay hefty duties for the import of their material or equipment (CCSI 2016).46 The design of the LCP should consider how other regulations or policies may negatively impact local firms’ ability to compete and properly evaluate the different trade-offs between competing objectives, such as offering attractive fiscal contracts to IOCs vs. promoting the development of local manufacturing.

CONCLUSION Since independence the SSA region has adopted different industrialization policies with modest results. Achieving industrialization is becoming more difficult with the advent of global supply chains (Baldwin 2011),47 but without industrialization SSA is likely to remain at the margin of the global economy, unable to provide enough jobs for its rapidly growing working age population. However, in light of the large natural resource wealth in SSA, the region is expected to attract billions of dollars from MNCs. Since the value of procurement of goods and services is the largest expense of MNCs operating a mineral or oil and gas project, there is a large opportunity to boost demand for local goods and services by capturing a share of that procurement need. This can be achieved by promoting LCPs that foster linkages between MNCs exploiting the region’s natural resources and local firms. Until now LCP outcomes in SSA have been modest, characterized by their low levels of breadth and depth. This is due to the difficult conditions in which local firms operate in SSA resulting in a particular firm structure: numerous informal and low productivity micro firms and a few large ones. What is missing in SSA are formal SME enterprises. By itself, LCP is a necessary but not a sufficient condition for fostering industrialization. To increase the chances of industrialization through the exploitation of natural resources, policymakers should address the dual firm structure existing in the region. Thus, LCP should aim at reducing the barriers resulting in insufficient numbers of SMEs and in their underperformance. Most of these barriers are external to the firms – for example, lack of electricity, poor infrastructure, corruption or high cost of capital – often dismissed as the “Cost of Doing Business.” In order to increase the number of SMEs, SSA could take advantage of three emerging trends: rapid urbanization, labor force growth and

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Natural resource-led development in Sub-Saharan Africa  ­229 the entry of private Chinese entrepreneurs. The first two trends facilitate the development of industrial clusters that can focus on labor-intensive manufacturing activities. These labor-intensive activities can benefit from the increasing demand for goods and services by MNCs. SSA policymakers would need to first map MNC supply chains and evaluate what within the supply chain can be manufactured locally, taking into account the competitive advantages of having an endless supply of labor. The entry of Chinese entrepreneurs offers the opportunity for SSA to have access to a large number of entrepreneurs bringing their know-how, technology and business skills that can spill over to the rest of the economy. However, their impact is currently limited because of their preference to maintain their supply chain from China. We conclude therefore by saying that LCPs can help SSA’s natural resource-based industrialization if the policies are aimed at increasing localization of supply chains of Chinese SMEs, and by reducing the barriers to entry for local entrepreneurs, not to the detriment of those owned by foreigners, but as a complement.

NOTES   1. Szirmai, A., W. Naudé, and L. Alcorta (eds.) (2013) Pathways to Industrialization in the Twenty-First Century: New Challenges and Emerging Paradigms, WIDER Studies in Development Economics. Oxford and New York: Oxford University Press.   2. The document refers to Sub-Saharan Africa (SSA) only, it excludes North African countries and the Republic of South Africa.   3. Whitfield, L., O. Therkildsen, L. Buur and A.M. Kjaer (eds.) (2015) The Politics of African Industrial Policy, A Comparative Perspective, Cambridge, Cambridge University Press.   4. Hansen, M.W., T. Pedersen and B. Petersen (2009) “MNC strategies and linkage effects in developing countries,” Journal of World Business, Multinational Enterprises and Economic Development, 44 (2) (April), 121–30.   5. Page, J. (2011) “Should Africa Industrialize?” United Nations University, Working Paper 2011/47.   6. Mendes, A.P.F., M.A. Bertella and R.F.A.P. Teixeira (2014) “Industrialization in ­Sub-Saharan Africa and import substitution policy,” Revista de Economia Política 34 (1) (March), 120–38.   7. Mendes, A.P.F., M.A. Bertella and R.F.A.P. Teixeira (2014) “Industrialization in SubSaharan Africa and import substitution policy,” Revista de Economia Política 34  (1) (March), 120–38.   8. Whitfield L., O. Therkildsen, L. Buur, A.M. Kjaer (eds.) (2015) The Politics of African Industrial Policy, A Comparative Perspective. Cambridge, Cambridge University Press, 2015.   9. Takahashi, Y., O. Atushi and K. Shunji (2007) “Alternative Export-Oriented Industrialization in Africa. Extension from Spatial Economic Advantage in the case of Kenya,” Hiroshima University Graduate School of International Development and Cooperation. Discussion Paper 2006–7. 10. Szirmai, A., W. Naudé, and L. Alcorta (eds.) (2013) Pathways to Industrialization in the Twenty-First Century: New Challenges and Emerging Paradigms, WIDER Studies in Development Economics. Oxford and New York: Oxford University Press.

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230   Handbook of energy politics 11. From author based on data from International Monetary Fund (2017) database http://www. imf.org/external/pubs/ft/weo/2017/02/weodata/weoselagr.aspx. Accessed May 25, 2017. 12. UNECA (United Nations Economic Commission for Africa) (2013) “Making the most of commodities,” available at http://www.uneca.org/publications/economic-reportafrica-2013. Accessed May 25, 2017. 13. African Natural Resources Center (ANRC) (2016) African Development Bank, ­available at https://www.afdb.org/en/topics-and-sectors/initiatives-partnerships/african-naturalresources-center-anrc/. Accessed May 25, 2017. 14. Leke, A., S. Lund, C. Roxburgh and A. van Wamelen (2010) “What’s driving Africa’s growth, McKinsey & Company,” available at http://www.mckinsey.com/global-themes/ middle-east-and-africa/whats-driving-africas-growth. Accessed May 25, 2017. 15. RMB Global Markets (2015) “Where to invest in Africa. 2015–2016,” available at http:// www.rmb.co.za/globalmarkets/wtiia_2015_2016/index.htm. Accessed October 1, 2016. 16. Ernst & Young (2015) “Africa attractiveness survey 2015,” available at http://www. ey.com/Publication/vwLUAssets/EY-africa-attractiveness-survey-2015-making-choices/​ %24FILE/EY-africa-attractiveness-survey-2015-making-choices.pdf, p. 26. Accessed Oct-​ ober 1, 2016. 17. Hirschman, A.O. (1981) Essays in Trespassing: Economics to Politics and Beyond, Cambridge: Cambridge University Press, available at http://www.cambridge.org/vu/ academic/subjects/economics/microeconomics/essays-trespassing-economics-politicsand-beyond. Accessed May 25, 2017. 18. Kaplinsky, R. (2011) “Commodities for industrial development – Making linkages work,” United Nations Industrial Development Organization (UNIDO), The Open University. Available at http://www.unido.org/fileadmin/user_media/Publications/ Re​search_and_statistics/Branch_publications/Research_and_Policy/Files/Working_Pa​ pers/2011/WP012011%20Commodities%20for%20Industrial%20Development%20-%​ 20​Maiking%20Linkages%20Work.pdf. Accessed May 25, 2017. 19. Hefner, F.L. and P.P. Guimares (1994) “Backward and forward linkages in ­manufacturing location decisions reconsidered,” The Review of Regional Studies 24 (3) (December 1), 229–44. 20. Hansen, M.W., T. Pedersen and B. Petersen (2009) “MNC strategies and linkage effects in developing countries,” Journal of World Business, Multinational Enterprises and Economic Development 44 (2) (April), 121–30. 21. Nordas, H.K., E. Vatne and P. Heun (2003) “The upstream industry and local industrial development, a comparative study,” Institute of Research in Economics and Business Administration, Bergen. 2003. SNF report No2003 08/03, available at https://brage.bibsys. no/xmlui/bitstream/handle/11250/164495/R08_03.pdf?sequence=1&isAllowed=y. Acces​sed May 25, 2017. 22. Tordo, S., M. Warner, O. Manzano and Y. Anouti (2013) Local Content Policies in the Oil and Gas Sector, World Bank Publications. 23. Hausmann, R., J. Hwang and D. Rodrik (2005) “What you export matters,” Working Paper. National Bureau of Economic Research, December. 24. Morris, M., R. Kaplinsky, D. Kaplan (2011) “Commodities and linkages: Industrialization in Sub-Sahara Africa,” MMCP Discussion paper 13. University of Cape Town and Open University, available at http://oro.open.ac.uk/30048/1/MMCP_Paper_13.pdf. Accessed May 25, 2017. 25. Gelb, A., C.J. Meyer and V. Ramachandran (2014) “Development as diffusion: Manufacturing productivity and Sub-Saharan Africa’s missing middle,” SSRN Scholarly Paper. Rochester, NY: Social Science Research Network, February 26, available at https://papers.ssrn.com/abstract=2457235. Accessed May 25, 2017. 26. Gelb, A., C.J. Meyer and V. Ramachandran (2014) “Development as diffusion: Manufacturing productivity and Sub-Saharan Africa’s missing middle,” SSRN Scholarly Paper. Rochester, NY: Social Science Research Network, February 26, available at https://papers.ssrn.com/abstract=2457235. Accessed May 25, 2017. 27. Fox, L. and T.P. Sohensen (2012) “Household enterprises in Sub-Sahara Africa and

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28.

29.

30.

31.

32. 33.

34. 35.

36.

37. 38. 39.

40.

why they matter to growth, jobs and livelihood,” Policy Research Working Paper 6184. The World Bank, African Region, available at http://www.iza.org/conference_files/ worldb2012/fox_l4959.pdf. Accessed May 25, 2017. Sveinung, F., L. Grunfeld and C. Green (2010) “SMEs and growth in Sub-Sahara Africa. Identifying SMEs role and obstacles to SMES growth.” Menon Business Economics (14), available at http://www.norfund.no/getfile.php/132385/Documents/Homepage/ Reports%20and%20presentations/Studies%20for%20Norfund/SME%20and%20growth​ %​20MENON%20%5BFINAL%5D.pdf. Accessed May 25, 2017. Gelb, A., C.J. Meyer and V. Ramachandran (2014) “Development as diffusion: Manufacturing productivity and Sub-Saharan Africa’s missing middle,” SSRN Scholarly Paper. Rochester, NY: Social Science Research Network, February 26, available at https://papers.ssrn.com/abstract=2457235. Accessed May 25, 2017. Ousman, G. and M. Hallward-Driemeier (2012) “Why do some firms abandon formality for informality? Evidence from African countries,” Working Paper, African Development Bank, available at http://www.afdb.org/fileadmin/uploads/afdb/Documents/Publications/ Working%20Paper%20159%20-%20Why%20do%20some%20Firms%20abandon%20 Formality%20for%20Informality%20-%20Evidence%20from%20African%20Countries. pdf. Accessed May 25, 2017. Gelb, A., V. Ramachandran, M.K. Shah and G. Turner (2007) “What matters to African firms? The relevance of perceptions data”. Policy Research Working Paper 4446. World Bank, available at https://papers.ssrn.com/sol3/papers.cfm?abstract_id=10759​02##. Accessed May 25, 2017. Kauffmann, C. (2005) “Financing SMEs in Africa,” Policy Insights No7. OECD Development Centre, available at https://www.oecd.org/dev/34908457.pdf. Accessed May 25, 2017. Ramachandran, V. and M.K. Shah (2007) “Why are there so few black-owned firms in Africa? Preliminary results from Enterprise Survey Data,” Working Paper. Center for Global Development, available at https://ideas.repec.org/p/cgd/wpaper/104.html. Accessed May 25, 2017. Kauffmann, C. (2005) “Financing SMEs in Africa,” Policy Insights No7. OECD Development Centre, available at https://www.oecd.org/dev/34908457.pdf. Accessed May 25, 2017. Gelb, A., C.J. Meyer and V. Ramachandran (2014) “Development as diffusion: Manufacturing productivity and Sub-Saharan Africa’s missing middle,” SSRN Scholarly Paper. Rochester, NY: Social Science Research Network, February 26, ­available at https://papers.ssrn.com/abstract=2457235. Accessed May 25, 2017. Bughin, J., M. Chironga, G. Desvaux, T. Ermias, P. Jacobson, O. Kassiri, A. Leke, S. Lund, A. Van Wamelen and Y. Zouaoui (2016) “Lions on the move II: Realizing the potential of Africa’s economies, McKinsey & Company,” available at http://www.mck​ insey.com/global-themes/middle-east-and-africa/lions-on-the-move-realizing-the-­potent​ ial-of-africas-economies, Accessed May 25, 2017. Canning, D., R. Sargeeta and Y.S. Abdo (2015) Africa Demographic Transition. Dividend or Disaster? Open Knowledge Repository, World Bank Group, available at http://hdl.handle.net/10986/22036. Accessed May 25, 2017. Yokoyama, H. (1989) “Export-led industrialization and Dutch disease,” The Developing Economies, available at http://onlinelibrary.wiley.com/doi/10.1111/j.1746-1049.1989. tb00171.x/epdf. Accessed May 25, 2017. Bughin, J., M. Chironga, G. Desvaux, T. Ermias, P. Jacobson, O. Kassiri, A. Leke, S. Lund, A. Van Wamelen and Y. Zouaoui (2016) “Lions on the move II: Realizing the potential of Africa’s economies, McKinsey & Company,” available at http://www. mckinsey.com/global-themes/middle-east-and-africa/lions-on-the-move-realizing-thepotential-of-africas-economies, Accessed May 25, 2017. Gu, J. (2009) “China’s private enterprises in Africa and the implications for African development,” The European Journal of Development Research 21 (4) (September 1), 570–87.

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232   Handbook of energy politics 41. Horta, L. (2015) “Anti-China sentiment in Africa: Why are they unwelcomed?” S. Rajaratnam School of International Studies (RSIS), Nanyang Technology University, available at https://www.rsis.edu.sg/rsis-publication/rsis/co15049-anti-china-sentimentin-africa-why-are-they-unwelcomed/#.WG9xK1N96yo. Accessed May 25, 2017. 42. Li, A. (2016) “Technology transfer in China–Africa relation: Myth or reality?” Transnational Corporation Review 8 (3) (October). 43. Mutale, C. (2015) “Chinese investments in Africa’s SME Sector: a case study of Zambia,” School of Economics and Management, Lund University, available at http://lup. lub.lu.se/luur/download?func=downloadFile&recordOId=7868680&fileOId=7868711. Accessed May 25, 2017. 44. Mehlum, H., K. Moene and R. Torvik (2005) “Cursed by resources or ­institutions,” Department of Economics, Norwegian University of Science and Technology, ­available at http://www.ntnu.edu/documents/140152/38283210/10worldeconomy7.pdf/97578458c73b-40d4-bc26-60a7fb32a456. Accessed May 25, 2017. 45. Ramachandran, V. and M.K. Shah (2007) “Why are there so few black-owned firms in Africa? Preliminary results from Enterprise Survey Data,” Working Paper. Center for Global Development, available at https://ideas.repec.org/p/cgd/wpaper/104.html. Accessed May 25, 2017. 46. Columbia Center on Sustainable Investment (CCSI) (2016) “Linkages to the Resource Sector: The role of Companies, Government, and International Development Cooperation,” Deutche Gesellschaft fur Internationale Zusammenarbeit GmbH, available at http://ccsi.columbia.edu/files/2016/07/Linkages-to-the-resource-sector-GIZ-CC​ SI-2016.pdf.pdf. Accessed May 25, 2017. 47. Baldwin, R. (2011) “Trade and industrialisation after globalisation’s 2nd unbundling: How building and joining a supply chain are different and why it matters,” Working Paper. National Bureau of Economic Research, December.

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PART III MAIN INFLUENCES IN GEOPOLITICS

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10.  Will there ever be a post-oil era? Mamdouh G. Salameh

THE AMAZING AGE OF OIL When Edwin Drake drilled one of the world’s first commercial oil wells in Titusville, Pennsylvania in 1859, he definitely could not have anticipated the tremendous impact this discovery would have on the global economy, civilization and warfare in the years that followed. Since then, oil has been the lifeblood of the industrial world’s progress and standard of living. Innumerable everyday products – from pharmaceuticals to computers – depend on oil and its refining into complex chemicals and plastics. Modern industrial farming, which feeds much of the world, would grind to a halt if it were deprived of diesel-powered tractors, oil- and gas-based fertilizers to grow and harvest crops and the fossil fuels to process, package and ship food worldwide to feed a world population that has skyrocketed from 1.5 billion at the start of the oil age to 7 billion now. Though the modern history of oil begins in the latter half of the nineteenth century, it is the twentieth century that has been completely transformed by the advent of oil. The twentieth century was truly the century of oil whilst the twenty-first century would be the century of peak oil and the resulting oil wars. No other commodity has been so intimately intertwined with national strategies and global politics and power as oil. The close connection between oil and conflict derives from three essential features of oil: (1) its vital importance to the economy and military power of nations; (2) its irregular geographic distribution, and (3) peak oil.1 Conventional oil production peaked in 2006. As a result, any energy gap during the coming years will have to be filled with unconventional and renewable energy sources. However, it is very doubtful as to whether these resources could bridge the energy gap in time as to be able to create a sustainable future energy supply. There is no doubt that oil is a leading cause of war. Oil fuels international conflict through four distinct mechanisms: 1. resource wars, in which states try to acquire oil reserves by force; 2. the externalization of civil wars in oil-producing nations (Libya as an example); 3. conflicts triggered by the prospect of oil-market domination such as the United States’ war with Iraq over Kuwait in 1990; and 4. clashes over control of 235

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236   Handbook of energy politics oil transit routes such as shipping lanes and pipelines (closure of the Strait of Hormuz or the Strait of Malacca for example).2 Between 1941 and 2014, at least ten wars have been fought over oil, prominent among them the twenty-first century’s first oil war, the invasion of Iraq in 2003. Oil was central to the course and outcome of world War II in both the Far East and Europe. One of the allied powers’ strategic advantages in World War II was that they controlled 86 per cent of the world’s oil reserves. The Japanese attack on Pearl Harbor was about oil security. Among Hitler’s most cherished strategic objectives in the invasion of the former Soviet Union was the capture of the oilfields in the Caucasus. In the Cold War years, the battle for the control of oil resources between international oil companies and developing countries was a major incentive and inspiration behind the great drama of decolonization and emergent nationalism. At present, there are at least five major conflicts that could potentially flare up in the next three decades. The most dangerous among them is a conflict between Saudi Arabia and Iran over Iran’s nuclear programme and primacy in the Gulf region. Another is one between China and the United States that has the potential to escalate to war over dwindling oil resources or over Taiwan or over the disputed islands in the South China Sea claimed by both China and Japan with the United States coming to the defence of Japan. As in the twentieth century, oil will continue in the twenty-first century to fuel the global struggles for political and economic primacy as long as it holds a central place in the global economy.

OIL’S FIRM GRIP ON THE GLOBAL ECONOMY Those who are already starting to talk prematurely about the decline of the supremacy of oil should think again. They should look no further than the adverse impact that the collapse of oil prices since July 2014 has had on the global economy. The global economy has not been able to reconcile itself with the collapse of oil prices because the main ingredients that make up the global economy, namely, global investments, the oil industry and the economies of the oil-producing countries, are all being undermined. While it is true that low oil prices could reduce the cost of manufacturing, thus helping the global economy to grow, it is a short-term benefit. It is vastly offset by a curtailment of global investment which forces companies around the world to cut spending, sell assets and make thousands, if not millions, of people redundant. There has been a loss of 0.75–1.00 per cent annually in global economic growth since 2014.

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Will there ever be a post-oil era?  ­237 The seven major oil companies in the world – Royal Dutch Shell, BP, ExxonMobil, Chevron, Total, ENI and Statoil – need a price of $125–$135/barrel to balance their books. They also need certainty about the future trend of oil prices before committing themselves to huge investment in exploration and production.3 As a result of declining oil prices, the global oil industry has already sold many of its production assets and cancelled more than $200 bn in oil and gas investments so far, which will translate in two years’ time into a smaller share in the global oil production.4 Oil production by ExxonMobil, Shell, Chevron and ENI has declined from 11.5 million barrels a day (mbd) in 2003 to 9.5 mbd in 2015. This will be reflected in steeper oil prices in the near future.5 At prices much below $75/barrel, some of the North Sea’s remaining economically recoverable reserves, estimated at 15 and 16.5 billion barrels (bb) of oil and natural gas, will end up as so-called stranded assets – hydrocarbons that are simply too expensive to develop. Moreover, global investment in upstream exploration from 2014 to 2020 will be $1.8 trillion less than previously assumed, according to leading US consultants IHS.6 The Arab Gulf oil producers have lost an estimated $289 bn in oil revenues between 2014 and 2016 (see Table 10.1). As for the United States, it is doubtful whether the steep decline in oil prices would provide a boost to the US economic recovery. And while the price decline would certainly provide the equivalent of a sizable tax cut for US consumers, it will deliver a major blow to the increasingly important US oil industry which is estimated to employ around 2 per cent of the US workforce. It is also raising the risk of major defaults on the $200 billion in loans that have been extended to the domestic shale oil industry. The

Table 10.1  Net oil export revenues of the Arab Gulf oil producer Countries

2013

2014

2015

2016

Iraq Kuwait Qatar Saudi Arabia UAE Oman Total

86 92 42 274 53 27 574

74 72 34 208 42 22 452

46 38 20 111 28 11 254

62 34 20 123 34 12 285

Source:  Ministry of Trade, Industry and Energy (2014), p. 45. Outlook (STEO) / OPEC Annual Statistical Bulletin 2016 / Author’s Projections.

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238   Handbook of energy politics cost of servicing that debt has also increased exponentially after a number of operators saw their ratings reduced to junk.7 For Russia, the combination of sanctions over the Ukraine crisis and falling oil prices has sent the Russian economy into recession and caused the Russian currency to lose 40 per cent of its value against the dollar. Russian GDP was reported to have shrunk by a projected 1.7 per cent in 2015.8

BREAKDOWN OF GLOBAL OIL CONSUMPTION BY SECTOR It is widely known that crude oil has many applications – in industry, energy and chemical products, in agriculture, for shipping and for business travels to name but a few. Some sectors, however, demonstrate unquenchable thirst for oil. Notable among them is transport. The growth of crude oil demand for transport needs has been spectacular in the past 39 years. From 1973 to 2012, the sector increased its oil consumption from 2251 million tons of oil equivalent (mtoe) to 3652 mtoe, a 62 per cent rise.9 Naturally, this is related to the increased use of transport vehicles such as passenger cars and planes. Conversely, oil consumption in industry dropped 31 per cent from 448 mtoe to 310 mtoe during the same period (see Figures 10.2 and 10.3). In 2015, petroleum products provided about 92 per cent of the total energy the US transport sector used.10 Worldwide, oil accounts for 90 per cent of total crude oil consumption. The global energy mix will not look much different for oil in 2040 according to ExxonMobil’s recently released “Outlook for energy: A view to 2040” (see Figure 10.4). World gross domestic product (GDP) is projected to double in the next 15 years from $76 trillion in 2015 to almost $150 trillion, accelerating demand for energy.11 Non-OECD nations, particularly China and India, will experience the most economic growth, driven by urbanization. Oil is expected to remain the world’s primary energy source, driven by demand for transport which is projected to grow by 20 per cent between 2015 and 204012 (see Figure 10.5).

SAUDI ARABIA PLANS FOR THE FUTURE Saudi Arabia’s “Vision 2030” which includes the sale of part of Saudi Aramco, the world largest oil company, should not be taken to mean that the country is preparing for a post-oil era. It is merely a belated attempt to

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Will there ever be a post-oil era?  ­239

Figure 10.1  Who gets what? diversify the economy in the light of the very adverse impact the current low-price regime is having on its economy (see Figure 10.6). It is clear Saudi Arabia needs to reform, diversify and re-energize its economy, but this will involve more than just increasing investments in non-oil industries. With the release of a new independent report on world oil reserves by a former BP insider, a report that suggests that conventional reserves are half what is being claimed, the issue of limits on oil production has resurfaced. (The report implies that Saudi reserves have been inflated as well.)13 Moreover, the Saudi government’s plans to modernize the economy and partly privatize Saudi Aramco, depending to some extent on higher oil prices. The kingdom needs higher oil revenues as a “bridge” to a less oil-dependent economy. The value of the assets is directly tied to the price of oil. The higher the oil price, the higher the price of the IPO.

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240   Handbook of energy politics

23.1% Total: 2251 mtoe 45.4% 11.6%

Transport Industry Non-energy use Other*

19.9%

*Agriculture, buildings, commercial & public services, and others.

Figure 10.2  Global crude oil consumption in 1973, by sector

11.8% Total: 3652 mtoe 16.0%

Transport

8.5% 63.7%

Industry Non-energy use Other*

*Agriculture, buildings, commercial & public services, and others.

Figure 10.3  Global crude oil consumption in 2012, by sector

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Will there ever be a post-oil era?  ­241 100 Other renewables Wind/Solar Nuclear

80

Coal 60 Gas

40

20

0

Oil

2015

2040

Source:  Courtesy of ExxonMobil (2017) “Outlook for energy”.

Figure 10.4  Global energy mix evolves

RUSSIA’S TRICKY DIVERSIFICATION PLANS It is difficult to overstate the importance of the oil and gas industry to the Russian economy. Russia has some of the world’s most sophisticated and advanced technical, industrial and scientific bases. Globally, Russia is competitive in defence products, space launches, nuclear power, mineral resources and information technology. But none of these industries compares to oil and gas exports. To the average Russian, the country’s economy seems to be structured around exchanging barrels of oil for imports. The trouble, of course, is that as oil prices have plunged, those barrels buy ever fewer imports.14 Unfortunately, the Russians, under 70 years of communist regime, have failed to convert their technical prowess into exports of manufactured goods with the exception of weaponry. In 2014 and before the global collapse of crude oil prices, 50 per cent of Russia’s budget and about 68 per cent of its export revenues came from oil and gas exports. Now, with the current price of crude oil and the fact that the natural gas price is derived from that of crude oil, Russia’s economy is, at least in the short term, being hurt and must be under enormous pressure. It must be noted, however, that the high prices of oil and revenues

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242   Handbook of energy politics 300 Other renewables

250

Biomass Nuclear

200 150

Coal

100 50 0

Gas Oil ’15 ’25 ’40 Transportation

’15 ’25 ’40 Residential/ Commercial

’15 ’25 ’40 Industrial

’15 ’25 ’40 Electricity generation

Source:  Courtesy of ExxonMobil (2017) “Outlook for energy”.

Figure 10.5  Energy demand varies by sector

100 80 60

Oil

40 20 Non-Oil 2000

02

04

06

08

10

12

14

0

Source:  Ministry of Finance.

Figure 10.6  Saudi Arabia’s government revenues

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Will there ever be a post-oil era?  ­243 g­ enerated by export of oil and gas in the post-Soviet era were in fact poisonous for the Russian economy because they simply intensified its dependence on oil and gas and plagued it with the resource curse. In that sense, and if Russia intends to be saved from such a predicament, a low oil price could be an opportunity (a blessing in disguise) for that country. Perhaps that is why Vladimir Putin has recently issued some executive orders to rid Russia’s economy of dependence on oil and gas export revenues. A reluctance to carry out reforms could lead to ­stagnation and malaise in the years to come.

ARE WE ON THE VERGE OF A POST-OIL ERA? A few experts have been projecting the advent of the post-oil era within the next 50 years. The underlying assumption is that alternatives to oil would have been fully and cheaply developed by then thus ushering in the post-oil era. There is no doubt that global energy’s future is in renewables. Solar power along with other alternative energy sources will ultimately provide all the electricity we need, and will power water desalination plants and will drive our transport. And while renewable energy sources have made great strides in the last 25 years, it will take their enabling technologies probably 50 years more before renewable energy sources start to have a decisive impact on electricity generation and transport. In 2015, renewable energy accounted for only 2.8 per cent of the global primary energy consumption.15 And although electric cars have already made their appearance on our roads, it will take many decades before they make an impact on the global demand for oil for transportation let alone replacing oil in the transport sector. Therefore, talking about the advent of the post-oil era within the next 50 years is premature to say the least.

COULD ELECTRIC CARS REPLACE OIL? Despite the hype, electric cars enjoy niche rather than mass-market appeal. Tesla, the biggest electric car manufacturer, has achieved a market value of $33 bn when producing just 50,000 electric cars a year compared with a valuation of $47 bn for General Motors, which in 2015 made more than six million cars.16 Still, take-up of electric cars among consumers remains tiny. Currently, electric and hybrid cars combined number around two million cars out of

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244   Handbook of energy politics 1.2 billion conventional cars (internal combustion cars) on the roads worldwide in 2014, or a negligible 0.2 per cent. The total number of conventional cars is projected to reach 2.0 billion by 2035. Out of the total of 1.2 billion cars, 275 million are in the United States and 172 million in China.17 We have to bear in mind that today for the majority of people, electric vehicles aren’t the right solution for them yet. The enabling technology has to improve a lot before they achieve a global appeal. Three hurdles stand in the way of mass adoption of electric cars: price, range and ease of charging. The greatest contributor to the price is the battery, which can account for a significant portion of the cost of an electric car. The dominant force in battery-powered cars is the costly lithium-ion technology, the same used in laptops and mobile phones.18 Other options are being pursued, from magnesium-based batteries to those that use silicon rather than carbon anodes. Solid state batteries, which promise much greater power and more flexible sizes, are also being investigated. Other alternatives to combustion engines include hydrogen fuel cells, which use the planet’s most abundant element to drive their motors.19 Toyota, which led hybrid adoption with its Prius cars, has already launched a fully hydrogen-powered model. Once purchased, the cars are supposed to be virtually free to run, with the cost of an electric recharge being minimal. The second and most significant public concern about electric cars is the range. Recent models are limited to 100 miles. Tesla’s Model, which is claimed to travel in excess of 250 miles on a charge, remains positively expensive for many, costing between $70,000 and $120,000. Carmakers are pushing to hit a compromise on technology and price – a $35,000 car that can travel more than 200 miles. However, Tesla’s Model 3 is still at least two years from the road.20 The third and final hurdle is the ease and speed of charging at home and en route. It currently takes up to two hours to charge a car for a full range of 250 miles.21 Some experts are now saying that widespread electric vehicle use could spell the end of oil. The tipping point, they reckon, is 50 million electric cars on the roads. This they believe could be reached by 2024.22 However, 50 million electric cars on the roads could hardly make a dent on the global demand for oil let alone replace it. In 2016 the world used 35 billion barrels of oil (bb) of which 90 per cent, 32 bb, were used to power 1.2 billion conventional cars around the world.23 Bringing 50 million electric cars on the roads will reduce the global oil demand by only 1.3 bb, or 4 per cent. This will neither be the end of oil as

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Will there ever be a post-oil era?  ­245 some experts are suggesting nor a tipping point. A tipping point will only be reached once 600 million electric cars are on the roads. Current worldwide production of electric cars doesn’t exceed some 500,000 cars annually. So, it will take many decades to manufacture 50 million electric cars. And whilst electric cars are very welcome addition to global transport and the environment, they will not pose a threat to oil throughout the twenty-first century and maybe far beyond. Moreover, for electric cars to have a serious impact on the global demand for oil, at least 600 million of them (50 per cent of the current global number of conventional cars) should be on the roads worldwide within the next 50 years. This is impossible to achieve within that time frame. Even with the best intentions and billions of investments, only 1.257 million electric and plug-in hybrid cars were sold in 2015 of which 740,000 were all-electric and 517,000 were plug-in hybrids. We then can only guess how many decades will have to pass before the entire global fleet of conventional cars is replaced by electric cars. This means that there can never be a post-oil era during the twenty-first century and most probably beyond. However, for the Gulf Cooperation Council (GCC) countries – Saudi Arabia, UAE, Kuwait, Qatar, Oman and Bahrain – there would be no post-oil era ever. Contrary to widely accepted wisdom, oil will remain an integral part of the Middle East economies throughout the twenty-first century and far beyond. Even if cheap alternatives to oil in transport, water desalination and electricity generation were to become readily available in the future, oil will not be left underground because the Arab Gulf oil producers will use it to power thousands of water desalination plants to generate enough water not only for drinking but also for irrigation to make the desert bloom again. They will also use it to dominate the global petrochemical industries and any industries in which oil is a feedstock.24

CONCLUSIONS There is a lot of hype about the advent of the post-oil era within the next 50 years. It will take far more than five decades before electric cars could start to make an impression on the global oil demand for transport let alone replace it. And while experts around the world sit in their ivory towers and project the advent of the post-oil era within the next 50 years, the realities of the situation cast doubt on their projections. So, to the question as to whether there will be a post-oil era, my answer

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246   Handbook of energy politics is no, even during the next 100 years. Oil will continue to reign supreme through the twenty-first century and maybe far beyond.

NOTES   1. M.G. Salameh (2014) “Oil wars,” research paper published by the USAEE/IAEE Working Paper Series No: 14163, 1 May.   2. Ibid.   3. M.G. Salameh (2015a) “What is behind the steep decline in the crude oil prices: Glut or geopolitics?” research paper published by the Arab Centre for Research & Policy Studies, Doha, Qatar, June.   4. F. Birol (2016) “Oil & gas page,” Qatar Today, February, p. 20.   5. M.G. Salameh (2016a) “Saudi Arabia’s misguided oil strategy & its impact on oil prices,” paper given at the Regional Energy Conference organized by the Arab Administrative Development Organization of the Arab League 17–18 May 2016, Cairo.   6. M.G. Salameh (2016b) “Is Saudi Arabia losing its war of attrition against US shale oil?” Article posted by the ESCP Research Centre for Energy Management (RCEM) 19 September.   7. M.G. Salameh (2016c) “Oil & the US economy,” article posted by the ESCP Research Centre for Energy Management (RCEM) 7 July.   8. M.G. Salameh (2016d) “Saudi Arabia’s misguided oil strategy & its impact on oil prices,” USAEE/IAEE Working Paper Series No: 16–227, 22 January.   9. GlobalPetrolPrices.com (2015) “Breakdown of oil consumption by sector,” 7 October 2015, available at http://www.globalpetrolprices.com/articles/39/ accessed on 15 November 2016. 10. US Energy Information Administration (EIA) data (Today in Energy) (n.d.), available at www.eia.gov/todayinenergy accessed on 13 November 2016. 11. World Bank Estimates, https://data.worldbank.org accessed 20 November, 2016. 12. ExxonMobil (2016) “2040 energy outlook,” 20 December, available at http://www. exxonmobil.co.uk/en-gb/energy/outlook-for-energy/a-view-to-2040/a-view-to-2040 accessed on 17 January 2017. 13. K. Cobb (2016) “Does the US have a plan for the post-oil era?” Oilprice.com, 25 May 2016, available at https://oilprice.com/Energy/Crude-Oil/Does-The-US-Have-A-PlanFor-The-Post-Oil-Era.html accessed on 30 May 2016. 14. V. Kazakov (2016) “Russia’s Transformation in a post-oil era,” Gulf News Analysis, 15 June. 15. BP (2016) “BP statistical review of world energy,” June, p. 41. 16. P. Campbell (2016) “Electric cars see range, battery and ease of charging as ­barriers to mass adoption,” Financial Times, 26 July, available at https://www.ft.com/ content/8f79ae6e-2400-11e6-9d4d-c11776a5124d, accessed on 15 November 2016. 17. Green car reports (2014), 7 July, available at www.greencarreports.com accessed on 17 January 2017. 18. P. Campbell (2016) “Electric cars see range, battery & ease of charging as barriers to mass adoption,” Financial Times, 26 July, available at https://www.ft.com/ content/8f79ae6e-2400-11e6-9d4d-c11776a5124d.accessed on 15 November 2016. 19. M.G. Salameh (2008) “How viable is the hydrogen economy: The case of Iceland,” paper given at the 28th USAEE/IAEE North American Conference, 3–5 December, New Orleans, USA. 20. P. Campbell (2016) “Electric cars see range, battery & ease of charging as barriers to mass adoption.” 21. Ibid. 22. M. Lempriere (2016) “As our carparks turn electric, at what point should big oil begin

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Will there ever be a post-oil era?  ­247 to worry?” 8 December, available at http://www.power-technology.com/features/featu​ reas-our-carparks-turn-electric-at-what-point-should-big-oil-begin-to-worry-5691930/, accessed on 11 January 2017. 23. International Energy Agency (IEA) (2017) ‘Global EV outlook 2017: Two million & counting,” 25 May, available at www.iea.org/media/topics/transport/Global_EV_ Outlook_2017_Leaflet accessed June 5, 2017. 24. M.G. Salameh (2016) “No post-oil era for the GCC countries,” Crawford School & Policy Forum of the Australian National University, April.

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11.  The Oil Age

Colin J. Campbell

INTRODUCTION Oil and gas have provided very important sources of energy that fuelled the economic expansion of the world over the past century, but they are finite natural resources formed in the geological past, which means that they are subject to depletion. As discussed here, the evidence indicates that this remarkable oil-driven chapter of history is about half over. Logic suggests that the Second Half of the Oil Age, which dawns, may be marked by economic contraction contrasting with the expansion of the First Half. The transition threatens to be time of great tension, but gradually as people come to recognise that the circumstances are imposed by Nature they may come to adapt in positive and constructive ways. It is by all means an important issue with far-reaching economic, social, financial and political consequences. But it is a complex topic, and the data needed for proper analysis are far from reliable.

THE NATURE OF EXPLORATION The science of petroleum has made great advances, so that the formation of oil and gas is now well understood. Geochemistry shows that oil is derived from algae that proliferated on the surface waters of restricted lakes and seas especially at times of global warming. The warm surface waters restricted circulation, giving anoxic conditions at depth, so the algal material that sank to the depths was converted into kerogen. When buried to a depth of about 2000m beneath younger sediment washed into the seas or lakes, it became heated enough to be converted into oil. Much of the world’s oil comes from rocks laid down in two periods of global warming, 90 and 150 million years ago. A theory that oil is formed deep in the Earth’s crust under abiotic conditions may be confidently dismissed as there is not a single known oilfield that cannot be readily explained on the basis of conventional understanding. Gas comes both from more carbonaceous material and from oil that had been overheated by deep burial. Once formed, the oil began to migrate upwards through the rocks to zones of lesser pressure, provided that there were fractures, fissures 248

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The Oil Age  ­249 or permeable and porous rocks through which it could move. Much was dissipated in the source rocks themselves, and is now being tapped through so-called fracking: namely by artificially fracturing rocks lacking adequate natural porosity and permeability. In addition, some was lost or degraded where it reached the surface, with the tar sands of Canada being a well-known example. But in many cases the migrating oil and gas were trapped in dome-like structures, known as anticlines, or in other structural circumstances, provided that such had an adequate reservoir and seal. Sandstone is the prime reservoir, with the oil being held in the pore-space between the grains of sand, and fractured limestone is another. Clay and salt form effective seals preventing the oil and gas escape from the trap. Timing is another factor because the trap had to be in existence when the oil migrated. In earlier years, finding the right combination of circumstances relied on geological fieldwork using technology no more advanced than the hammer, hand lens and notebook. But later, geophysical techniques allowed the geology at depth to be mapped in detail. It involved the release of an explosive charge and measuring the time taken for the echoes to reach the surface from deeply buried strata. Oil companies searched for promising areas and then secured rights from governments and landowners to explore them, such rights normally carrying drilling obligations. Once a promising prospect was identified, the details were evaluated in economic terms. If it looked viable, an exploration well, known as a New Field Wildcat, would be drilled to test it. In some cases, the well confirmed the analysis by making a discovery, but in many others, some unforeseen factor gave disappointing or negative results. Even so, the information gained provided a new understanding of the geology that sometimes led to a subsequent discovery. When a viable discovery was made, it became necessary to drill so-called appraisal wells to determine the size of the field more accurately in order to justify the construction of the necessary infrastructure, including pipelines. Obviously, there is a range of uncertainty, and it became normal to classify estimated future production as Proven, Probable and Possible Reserves with the meanings the words imply. Estimates of the size of the field are commonly based on the Proven in full, two-thirds of the Probable and onethird of the Possible. Probabilistic methods are also employed, with the Mean value being taken as the best estimate. Some fields have more than one reservoir and trap, with the smaller additions normally being added late in its life. This in turn affects the definition of the exploration wells with the need to properly distinguish New Field Wildcats from New Pool Wildcats. Much of the oil is held immovable in the reservoir by capillary forces and other factors. In earlier years, it was normal to recover no more

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250   Handbook of energy politics than about 30 per cent, but technological advances have increased the recovery factor, in some cases, to as much as double that level. Economic factors obviously play an important role. Higher oil prices can make the tail end of a field more viable. Tax is another important element with the cost of exploration being effectively subsidised by being commonly treated as a deduction from taxable income. In the early days, most exploration was onshore, but as those opportunities were depleted, attention turned to the offshore, calling for more advanced and costly technology. Oceans cover much of the planet’s surface, but only a few areas beneath them have the right geology to deliver significant finds, with the Gulf of Mexico and the margins of the South Atlantic being prime tracts. There are several different categories of oil and gas, each having its own costs, characteristics and depletion profile, but there is no standard classification, which is the cause of much confusion in the statistics. The following classification is used here: 1. Regular Conventional Oil and Gas: a liquid, known as condensate, which naturally condenses from gas, may be treated together with Regular Conventional oil. 2. Heavy Oils: with a density greater than 17.5o API, including bitumen (Degree API is an industry measure of density), but there is no standard cut-off for the definition of Heavy. Canada has 25o API, Venezuela has 22o API but 17.5o, which is relatively low, is here seen as a useful one so that all oil that can be produced in more or less normal ways may be included as Conventional. 3. Oil Shale: oil that can be produced by heating immature source rocks. 4. Tight Oil and Gas (also called Shale Oil and Gas): as derived from rocks lacking adequate natural porosity and permeability that can yield production when artificially fractured. 5. Deepwater Oil and Gas: in water depths greater than 500m. 6. Polar Oil and Gas. 7. Natural Gas Liquids from gas plants. 8. Other Non-Conventional Gases: coalbed methane, hydrates and so on.

DEPLETION PROFILES Regular Conventional Oil, which is relatively cheap and easy to extract, is clearly of prime importance. The production profile of an individual field normally shows a rapid initial increase, followed by a plateau set by the extraction facilities, and then a gradual decline as the pressure in the res-

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The Oil Age  ­251 80

Cum. Discovery Gb

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Figure 11.1  North sea creaming curve ervoir drops. As the oil is extracted, the underlying water in the reservoir rises, leaving less and less oil-bearing rock in contact with the wells. Most oil accumulations also contain a gas cap, which is normally extracted after most of the oil has been taken. A country’s profile reflects the timing and size of the individual fields, of which the larger were normally brought in first, being too big to miss. Production typically passes a peak close to the midpoint of depletion, but naturally local circumstances, including political factors, affect the profile. More than 50 countries are now producing less than at some date in the past, some being long into decline. Figure 11.1 shows the discovery profile of the North Sea with cumulative discovery plotted against cumulative exploration wells. Clearly, the discovery trend is flattening although the high prices of recent years have led to some unexpected, mainly small, discoveries. Extrapolating the trend suggests that the total amounts to about 75 Gb (billion barrels). Production, which is plotted in Figure 11.2, peaked in 2000, and is assumed to continue to decline at the current Depletion Rate of about 5 per cent a year (Annual as a per cent of the Future). Naturally, there may be departures from the forecast for all sorts of reasons, but it offers a reasonable overview of the future. Similar profiles have been made of all the world’s significant producing countries, which in turn are summed into regional and world totals. The North Sea’s primary producers are Denmark, Norway and the United Kingdom, all of which, especially Norway, publish relatively

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252   Handbook of energy politics 7000

Oil Production kb/d

6000 5000 4000 3000 2000 1000 0 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020 2030 2040 2050

Figure 11.2  North sea oil production r­ eliable data on the size of the discoveries. But that unfortunately is far from the case in some other countries. A particular source of confusion is the reporting by the OPEC countries, which is significant since they supply almost 40 per cent of the world’s current needs. In 1980, Kuwait reported reserves of 65 Gb (billion barrels), consistent with the past trend. By 1984, they had been reduced by production to 64 Gb, but that was a time of low oil prices adversely affecting national revenue. OPEC production quota was based on reported reserves, meaning that the more the member countries reported, the more they could produce to fill their coffers. In the following year, Kuwait increased its report to 90 Gb although nothing particular had changed in the oilfields. Past production had amounted to 22 Gb, which suggests that it may have changed to reporting a rounded total of the amount found, termed Original Reserves, not Remaining Reserves. This in fact is normal industry practice when determining the relative ownership of a field that crosses a frontier or lease boundary, being a fairer procedure because ownership is not influenced by the rates of extraction. At first, the other OPEC countries did not know how to react. But when Kuwait added 2 Gb in 1987, possibly from a genuine discovery or higher recovery factor, it was the straw that broke the camel’s back. Abu Dhabi exactly matched Kuwait (up from 31 Gb); Iran went one better at 93 Gb (up from 49 Gb), while Iraq, not to be outdone, came in with a rounded 100 Gb (up from 47 Gb). Saudi Arabia could not match Kuwait because it was already reporting more, but in 1990 increased from 170 to 258 Gb, probably following Kuwait’s example of reporting the total found, not

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The Oil Age  ­253 the amount remaining. Another cause of confusion is the so-called the Neutral Zone, which is shared by Saudi Arabia and Kuwait. Venezuela, for its part, increased from 25 Gb to 56 Gb, but did so by including its non-conventional heavy oil that had not previously qualified for quota purposes. It is remarkable that such a flawed data-set is routinely reproduced without comment. It is also necessary to address the production of the other categories of oil and gas, with particular attention now being given to that from socalled fracking, which is enjoying a boom in the United States. It is early days to assess its world impact, but it has to be recognised that the wells are very expensive and short-lived. Furthermore, the source rocks being drained are not uniform, with prime attention being given to so-called sweet spots offered by interbedded inferior reservoir rocks of limited distribution. It is evident from the foregoing that accurate depletion modelling is very difficult, but that said, the overall position may be determined within reasonable limits. It is good to make the assessment by country so that the uncertainties and anomalies can be better identified. An assessment is given in the Appendix. It also makes sense to consider the forecast in terms of production to the end of the century, as there is no need to worry about some irrelevant tail end. Table 11.1 gives such an assessment, based on 2012 data, and Figure 11.3 provides a reasonable depletion profile of all categories of oil and gas. More may be found than estimated, but it would be a mistake to rely on that happening. A debate rages as to the precise date of peak but misses the point when what matters is the vision of the long decline that comes into sight on the other side of it. Table 11.1  The Oil Age PRODUCTION TO 2100 All numbers to be generously rounded. PAST FUTURE From known fields Yet-to-Find TOTAL

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OIL

GAS

Reg. Gb

All Gb

Reg. Tcf

All Tcf

1141 909 794 115 2050

1297 1303

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254   Handbook of energy politics 60 55 50 45

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40 35 30 25 20 15 10 5 0 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020 2030 2040 2050 Regular Oil Polar

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Figure 11.3  Oil & gas production profiles 2012 base case

PLACING THE OIL AGE IN A HISTORICAL PERSPECTIVE The foregoing has summarised a technical assessment of the nature of petroleum and its depletion. It is stressed, as already stated, that it is a natural resource formed in the geological past and therefore subject to depletion. That said, higher prices and advances in technology can tap ever less viable resources, extending the life of production. Despite the uncertainties of detail, it is clear that there is an Oil Age, and the following comments endeavour to place it in an historical context. We are now close the end of the First Half, which was marked by expansion, largely fuelled by cheap and easy oil-based energy. The Second Half, which dawns, will see radical changes that need to be addressed. The solar system came into existence almost five billion years ago and included Planet Earth, which was special in having a molten core, a viscous mantle and a hard crust, later surrounded by a relatively thin skin of air and water. Continents moved around on the back of deep-seated convection currents in the Earth’s crust, and mountains arose where they collided. Seas and lakes became home to early life more than 550 million years ago. Some species, including the limpet (or patella to give

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The Oil Age  ­255 it its ­scientific name), have remained little changed. But others evolved and proliferated when they found a niche that suited them, only to die out if it closed from natural causes. It was not plain sailing as cataclysmic events from volcanoes, climate changes and meteor impacts led to mass extinctions. Early Man made an appearance only about 200 000 years ago and lived by hunting and gathering food. Settled agriculture followed about 12 000 years ago, laying the foundations for modern society. Some communities exhausted the fertility of the land upon which they relied, partly by cutting down the trees that increased soil erosion. In such cases, they either died out or were forced to occupy or conquer other lands. There were conflicts that remained a common feature of subsequent history. Food also had to be stored between harvests, and the storehouse held accounts of how much was received and returned to the farmers. It soon found itself in a key position, being able to give preference to the privileged members of the community and charge interest for the provision of food after a bad harvest. Its accounting laid the foundations for banking. Some communities were more successful than others, which led to the growth of empires, with the Egyptian, Roman or Aztec Empires being notable early examples. The communities needed political control leading to the appointment of monarchs and emperors, some of whom claimed divine authority for their positions. But they too became subject to conflict as people rose against what they perceived as excessive power and privilege. Stone Age Man had fashioned flints into knives and arrowheads before people turned to bronze, iron and steel for better tools and weapons. Firewood, charcoal and some coal were used for cooking, heating and smelting. The minerals were at first dug from surface outcrops, but the pits were progressively deepened into regular mines, which were subject to flooding when they hit the water table. That led to a remarkable technological development: the hand pump and bucket gave way to the steam pump which in turn evolved into the steam engine. It changed the world in radical ways especially in the field of transport with the development of railways and steam ships that facilitated trade. There was another major technological development around 1870 when a German engineer, by the name of Nikolaus Otto, perfected a way to inject fuel directly into the cylinder of a steam engine, developing what was known as the Internal Combustion Engine, which was much more efficient. At first, it used benzene distilled from coal before turning to petroleum refined from crude oil. The Oil Age had opened a few years with production from seepages and shallow oil wells, providing paraffin (termed kerosene in the USA) for illumination, but the new engine led to

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256   Handbook of energy politics increased demand for oil. It provided the energy for the rapid expansion of industry, transport, trade and even agriculture. The first automobiles took to the road around 1880 and the first tractor ploughed its furrow in 1907. This is not as long ago as it might seem, having been witnessed by the parents of an old man living today. In earlier years, for energy, man had relied mainly on his own muscles and those of his animals, supplemented by some wind and water energy to drive mills and power sailing ships, but now things changed radically. The expansion of trade in turn changed the structure of society. People no longer lived in simple rural societies, fed by whatever their particular region could support, but increasingly moved to towns, where they dedicated themselves to manufacturing goods and working in markets. This in turn prompted the rapid expansion of banking and finance as businesses needed more loans to start or expand their operations. Governments raised their revenue from tax, but if they exceeded the proceeds, they too called for help from the bankers. Land ownership had been the principal form of wealth in earlier years but the opening of the industrial age delivered a new privileged class of wealthy businessmen, investors and bankers who came to exert their power in many ways, having a major influence on government policy. An underprivileged workforce lived in abject urban conditions but reacted to exploitation with the anarchist, socialist and communist movements of the last century aiming at a fairer distribution of wealth. There were many conflicts that arose between different nations, most probably being triggered by trading pressures. The major changes of the industrial age saw a radical increase in population. It had no more than doubled over the first 17 centuries of the last millennium but then expanded rapidly to pass one billion in the early years of the last century before reaching 7 billion today. (See Stanton (2003)1 for a penetrating analysis of population pressure by country.) Europe’s growing population came to exceed its carrying capacity, prompting emigration to the New World in the eighteenth and nineteenth centuries, leading to the near extermination of the indigenous people in North America, but Europe now in turn faces massive immigration from Africa and the East. Energy is a critical issue for society but is not commonly recognised as such. Apart from fuel itself, every room in every house contains embedded energy that had been used in making everything from the bedspread to the windowpane. The travellers on a modern liner are barely aware of the massive amount of embedded energy in its huge steel hull. Female emancipation was another change. Previously, women had seen their role as wives and mothers running the home of the breadwinner, but now they have developed their own successful careers in business and the

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The Oil Age  ­257 professions. Marriage itself has lost some of its meaning: not all couples marry, and many that do subsequently divorce. Women also became dedicated consumers as they headed down the streets to buy the latest fashion. Circumstances range widely from one country to another. Two elements stand out as pinnacles of energy consumption around peak oil. One is aviation which makes colossal demands, not only from the fuel used by airliners and that embedded in their construction, but also indirectly in the massive infrastructure of airports and by encouraging tourism. Few people indeed have any essential need to travel by air. The other is telecommunication: television screens and loudspeakers are on around the world delivering often less than erudite news and shows. The Internet also provides a great deal of useful information and is being increasingly used for trade. Many people spend much of their time at computer screens and using mobile phones, using electricity produced by fossil fuels. Such impacts probably have less than positive impacts on children, who now grow up depending on them, having lost the ability to enjoy the simple pleasures of the past. Despite the new wealth created from petroleum, the First Half of the Oil Age was not a particularly benign age seeing two World Wars of unparalleled intensity. New transport facilities kept the troops supplied with food, munitions and reinforcements, and many of the weapons, ranging from aircraft in the sky to tanks on the ground, relied on oil-based energy. Indeed, oil supply, or lack thereof, was a critical element in some battles. The cost of these two wars, the Cold War and subsequent military engagements were astronomic, being partly funded by debt that had to be repaid. While these conflicts made appeals to loyalty with a positive response, it is less sure that they served any genuinely useful purpose for civilisation. The dropping of atomic bombs on Japan at the end of the Second World War was a significant development. Scientists had been seeking means of tapping nuclear energy for some years but the military application gave them the resources to perfect the work. Some countries, notably France, have turned to nuclear energy as a prime source of electricity, and Britain now plans a major new nuclear power plant, evidently having recognised that its oil and gas production is in steep decline – its coal production having peaked in 1914. Some claim that nuclear power offers a solution, notwithstanding the risk of serious accidents, such as have occurred at Chernobyl in Russia and more recently at Fukushima in Japan. But it transpires that the mining of prime grade uranium, which is another finite natural resource, has also passed its peak.2

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258   Handbook of energy politics

OIL INDUSTRY Before leaving this chapter of history, it is well to review the evolution of the oil industry itself. Early fields, close to natural seepages, were placed on production in Pennsylvania, Romania and on the shores of the Caspian. The first organisations to take a major control of the world’s oil supply were Shell Oil and the Standard Oil Company, commencing operations in the late nineteenth century. Shell started developing Caspian oil, while Standard had a dominant position in Pennsylvania.3 The early days of the oil industry saw ruthless commercial competition with many contentious mergers and acquisitions. But the power of Standard Oil began to be seen as excessive, leading the US Government to break it up under Antitrust Legislation in 1911. Some of its daughters, especially Exxon, Mobil and Chevron, grew to be major international oil companies in their own right. Europe saw a parallel development as Shell and British Petroleum (BP) expanded their operations around the world, concentrating on the Middle East, Mexico and Venezuela. Despite competition, there remained strong motives for the oil companies to exercise a common control to regulate price and thereby profit. The discovery of a major new province could lead to a glut, depressing prices with adverse financial consequences. In the late 1920s, oil production was growing especially in the United States, Venezuela, Romania and Russia, and the risks of oversupply prompted Henri Deterding, the Chairman of Shell, to rent the Achnacarry Castle in Scotland for an informal meeting with the leaders of the other major companies. It led to an informal accord, known as the As-Is Agreement, aiming to set production levels to support price. There were also political moves, notably when the Soviet Union nationalised its oil industry in 1928, followed by Mexico ten years later. Another special situation was that of Iran, whose oil rights were held exclusively by the Anglo-Persian Oil Company. Winston Churchill had the British Government take a 51 per cent stake in the company in 1914 to secure a supply of oil for the British Navy that was converting from coal to oil as its fuel. The company became British Petroleum, now BP, and extended its operations around the world, but the government sold its holding in 1979 under the capitalist policies of the then Prime Minister, Margaret Thatcher. The Great Depression of 1930, which might now be better renamed the First Great Depression, was another factor, leading to a fall in demand, which called for a corresponding reduction in production to support price. This prompted the US Government, facing major new discoveries in Texas, to intervene in the following year with a new policy to restrict

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The Oil Age  ­259 production to a given number of days a month. Most oil in those days was moved by rail, so it was convenient to entrust enforcement of the policy to the Texas Railroad Commission. Onshore oil rights in the United States belong to the landowner, meaning that its oilfields commonly have a diverse ownership, calling for intervention beyond that of the major oil companies. This also had reserve reporting implications leading the Stock Exchange to impose strict rules for what could be reported as reserves for financial purposes. The major companies were subject to the same rules and came to find it made sense to report the minimum needed for financial purposes with the resulting growth giving a favourable, if somewhat misleading, image to the stock market. As Shell discovered to its cost in 2004, when it overstated its genuine reserves, those days are however now substantially over because the giant fields (defined as holding more than 500 Gb) mature and therefore offer progressively less scope for under-reporting. It is also significant that the seven major companies, nicknamed the Seven Sisters, which once controlled world oil supply, are now reduced to four by merger, evidently having found it easier to secure reserves by acquisition than exploration. Companies that failed to find new reserves promising financial expansion were bought by others seeking access to their residual reserves. It speaks of an important transition from expansion to contraction with much wider implications given the central place of oil-based energy in the modern world.

MIDDLE EAST As already discussed, the evidence suggests that the First Half of the Oil Age comes to an end. The transition threatens to be a time of rising tension, as the basic circumstances behind people’s lives face radical changes. Studying the history of the Middle East is both difficult and sensitive, but nevertheless needs to be addressed as almost 40 per cent of the world’s oil supply comes from the region, giving it a critical role. Early communities around the world no doubt observed the environment in which they lived and began to imagine a divine power behind the changing natural circumstances. They also had to build a positive community spirit, and their leaders found it expedient to call on some divine power to do so. Priests were appointed to help manage the communities. One of the more successful early communities lived in the Jordan Valley and built a religion to support its endeavours. Their descendents have played a prominent role over later history, but their contributions have not been widely recognised. In 47 BC, a faction invited the Romans

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260   Handbook of energy politics to include their territory into its empire. Later, a baby in a manger in Bethlehem was identified as the Son of God, being described as having been born to a virgin mother. This was not welcomed by the government, which went so far as to order the killing of all male children under the age of two and born in the vicinity in the hope of eradicating him, but failed to do so. Since a baby poses no threat to anyone, it speaks of some movement behind the new Son of God. When he grew up, he did indeed claim divine inspiration for new ideas. They included widening access to God, which were not welcomed by the religious leaders who persuaded the Roman Governor to have him crucified. But his followers went on to build the Christian Church that has had a huge influence around the world since. The Romans, however, came to find it a difficult territory to administer, and in AD 135 decided to sack Jerusalem, killing its inhabitants or driving them into exile. The exiles, having no lands in their new homes, were forced to concentrate on trade and finance. They maintained their separate identity and religion, which according to the biblical Book of Deuteronomy forbade usury, with the important exception of when it was practiced against strangers. The Christian Church also condemned the practice but this provided an opportunity for the descendents of the exiles to practice it on strangers. That in turn led to resentment and persecution, especially in Russia and later Germany, which prompted the formation of a new movement of so-called Zionists seeking to recover a homeland in the Jordan Valley. The opposition to usury probably reflected the conclusion that someone was making money without working for it, which gave rise to resentment. The rest of the Middle East consists largely of deserts and barren lands but various communities sprang up in the relatively favoured spots, being often in conflict with each other. In about AD 570, another religious leader by the name of Muhammad was born and went on to claim to be a messenger from God forming the religion of Islam. It later split into several different sects. It transpires that Judaism itself also broke up to include some hidden sects, such as the Dönmeh, which played a prominent role behind the scenes in Turkey. Even the House of Saud, ruling Saudi Arabia, belongs to the Wahhabi sect, which was formed under the influence of a merchant from Basra by the name of Shulman. These factors continue to play an important role in the Middle East, the world’s principal oil supplier, and have many wider effects. Despite the diversity of people, the region, with the exception of Persia (now Iran), was eventually unified under the Ottoman Empire of Turkey. Oil and gas from natural seepages had been known in the region since the earliest days, and the opening of the Oil Age brought new interest in exploiting these resources. In the early years of the last century, Germany

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The Oil Age  ­261 was planning to build a railway from Berlin to Baghdad as it sought to expand trade into the area. It secured a concession to do so, and its engineers identified seepages of oil close to the track in the vicinity of Mosul in Iraq. This caught the attention of a Persian general who successfully persuaded a British entrepreneur to look for oil in the adjoining part of his country. The effort was rewarded when a well at Masjid-i-Sulaiman in the foothills of the Zagros Mountains blew out in May 1908, opening up what was to prove the world’s most prolific oil province. Germany and Russia endeavoured to build their trading empires to rival those of Britain and France, and found themselves in a degree of conflict over eastern Europe and the Balkans. The assassination of an Austrian archduke in 1914 by a Serbian nationalist triggered the First World War as various alliances unravelled. Turkey decided to support Germany. At first, the war was something of a stalemate until a turning point came in 1917 as a result of several interrelated actions. Britain bowed to Zionist pressure for the creation of a homeland in Palestine, probably being influenced by financiers offering to secure dollar loans to help fund the war; the Bolshevik Revolution, backed by Zionist elements including New York bankers, brought down the Czar of Russia and the United States entered the war on the side of Britain and France. The Middle East was invaded by British and French forces, which successfully brought down the Ottoman Empire that was in due course broken up into the individual countries. Some achieved full nationality only comparatively recently: Kuwait doing so in 1961. The frontiers were drawn somewhat arbitrarily, and did not necessarily reflect the underlying tribal divisions. The Kurds, who are descended from the ancient Medes, occupy a tract of territory from Syria through parts of Iraq and Turkey into Iran. They failed to be recognised but are now close to securing a form of independence. After the war, France, Germany and the United States vied with each other for effective control of Middle East oil, which they had come to realise was a vital resource fuelling the modern world, having played a critical role in the First World War itself. Oil exploration was stepped up, and major discoveries were made in the region, especially in Iraq, Kuwait and Saudi Arabia, bringing great wealth and new political power. But, as always, major new discoveries led to a glut that depressed the price of oil. It was particularly serious in the Middle East because oil formed its principal source of revenue. Accordingly, these countries were receptive to a proposal by the Venezuelan Minister for the creation of the Organization of Petroleum Exporting Countries (‘OPEC’) in 1960 with production quotas being largely based on reported reserves as discussed earlier. Of particular significance were the two so-called Oil Shocks that

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262   Handbook of energy politics prompted surging oil prices with adverse economic consequences around the world. The first was in 1974 when Kuwait, Saudi Arabia and Libya restricted exports to the United States and other countries in response to their support for Israel. The second came five years later being prompted by fears associated with the fall of the Shah of Iran. The rights of the major international companies, which had found the oil in the Middle East, were progressively nationalised, but many tensions remained. Iran and Iraq found themselves at war in 1980 over a disputed frontier through oil-bearing territory, and ten years later Iraq invaded Kuwait in a dispute over the ownership of the South Rumaila oilfield that straddles the frontier, to be duly repelled by US forces in the First Gulf War. The last event of historical significance for the region was triggered by 9/11, in which buildings in New York and Washington collapsed, some having been struck by hijacked airliners. The hijackers were reported to be Arabs, led by Osama bin Laden, who came from a wealthy Saudi family. Although there are various explanations of the incident, it seems clear that there was a Middle East connection. It put the United States onto a war-footing, which led to an attack on Afghanistan, lying on a proposed pipeline route from the Caspian. That was followed by the Second Gulf War of 2003 when, together with Britain, it invaded Iraq on what proved to be false claims that it had weapons of mass destruction. When speaking to journalists some years later, President Bush may have inadvertently revealed the true reasons with the words our energy supply was at risk. Iraq’s leader, Saddam Hussein, was duly executed, but the subsequent government has faced great difficulties running a devastated country, which has experienced many acts of terrorism, partly triggered by the deep-seated conflict between Sunni and Shia branches of Islam. Iran is another important oil-producing country, but the fall of the Shah of Iran in 1979 led to the creation of an Islamic government of the Shia persuasion that became progressively isolated in the Middle East. Economic sanctions were later imposed by the United States and other countries on the grounds that it might develop nuclear weapons to attack Israel, even though that country apparently maintains six nuclear submarines. A recent change of government appears to have opened the door to a better relationship and the lifting of sanctions, but the moves are not welcomed by Israel. A civil war currently rages in Syria, which borders Israel, with the rebels evidently being backed by other countries in the region. Syria’s leader belongs to the Alawite sect that has close ties with Iran. It is not a significant oil producer, but may be seen as a potential transit country for new oil and gas pipelines from the producing countries. It also borders Israel,

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The Oil Age  ­263 10 War Loss

9

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Production Gb/a

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7

Kuwait

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Iran

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1970

1990

2010

2030

Figure 11.4  Middle East Gulf which seeks to expand its territory. The United States recently threatened to launch a military attack on the country, but partly under Russian pressure was persuaded not to do so. Figure 11.4 provides a forecast of production of Regular Conventional Oil for the main Middle East countries. The surge in Kuwait in 1992 is war-loss, which is to be treated as production in the sense that it depleted the reserves by like amount. These countries currently supply about 34 per cent of the world’s needs for Regular Conventional, but that will have risen to about 40 per cent by 2020, when its overall peak of production is expected. The population of these countries has increased eleven-fold since 1900, based on the flood of oil wealth, but logic suggests that they will see a radical decline by the end of this century, no doubt prompting more severe tensions. It still costs the Middle East countries around $20–30 a barrel to produce oil, so when they sell it for over $100 that represents profiteering on a mammoth scale, which probably has far reaching international financial implications.

MONEY The foregoing discussion has touched on the economic growth of society made possible by increased supplies of cheap and easy oil-based energy. The growth has also seen a radical increase in finance, which in recent years has run into serious difficulties. It is worth therefore trying to understand more about the nature of money, which is far from easy. One may imagine that someone in early days found a nugget of gold in a riverbed, and being impressed by its shiny appearance, showed it to a neighbour, who liked it even more, offering to swap it for a few sheep.

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264   Handbook of energy politics Gradually, it became seen as a useful means of facilitating barter, its value being set by its natural scarcity. Silver also came to be used in a similar way. But coins made from these minerals were heavy to carry around, and their owners may have feared theft. A storekeeper duly offered to hold them against a receipt, which became a form of currency matching the underlying value of the gold and silver. Before long, an imaginative storekeeper came to realise that he could issue more receipts than he had gold on deposit, confident that not everyone would cash in simultaneously. This laid the foundations for so-called fractional banking. It could be said that, at root, money should match the underlying supply of the energy essential for agriculture, trade and manufacturing. In the early stages of the Industrial Age investors put their money into specific projects such as building a factory or a canal, of which they had detailed knowledge and to which they had a sense of loyalty. But later they placed their investments on a stock market run by traders who obviously could have little detailed knowledge of the underlying projects and still less loyalty towards them. The traders soon began to speculate, even buying futures when they expected a particular stock or market to grow, or selling short when they expected it to decline. Commodities, including oil, were traded in a similar way. The use of the pound sterling for world trade at the height of the British Empire delivered massive unseen rewards to the banks of London, controlled by a few well-known names. They moved to take a position in the growing US financial market, and in 1913 persuaded President Woodrow Wilson to give them control of the Federal Reserve Bank, which remains in private hands despite its name. The dollar was previously backed by gold, but President Nixon abandoned that constraint in 1971. Many countries also held their gold reserves on deposit in Fort Knox. Some, including Germany, are now trying to withdraw it, but face some difficulties in doing so. The British Empire was extinguished by the Second World War, after which the United States rose to be the dominant world power. Unlike earlier empires that had direct responsibility for the territories they administered, the US empire, if it can be called that, is strictly a commercial and financial one. Countries came to hold their financial reserves in dollars which delivered a handsome reward, and financiers from New York could speculate against weak currencies before arriving with offers of dollar loans, securing interest payments and in a sense enslaving the country concerned. There is a network of intertwined so-called central banks managing the financial situation of countries, and trading between each other. The United States maintains a military presence at great cost in as many as 130 countries. Perhaps the motive

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The Oil Age  ­265 is to try to preserve stability in the interest of the underlying financial system that it controls. The First World War came at a colossal cost, leaving a defeated Germany virtually bankrupt. That in turn prompted radical inflation that indirectly allowed foreign investors to buy property and other assets in Germany at negligible cost, causing resentment. The United States, which was spared the direct ravages of war, enjoyed a boom accompanied by much speculation. It also lent large amounts of money to help Europe recover from the war. But the market overreached itself in 1929 prompting the First Great Depression. It put about a quarter of the US workforce onto the breadline, which led to an almost socialist response in the form of the New Deal to assist the downtrodden. The world economy remained weak until the Second World War, and governments issued more money than they had on deposit under so-called Keynesian economics in order to fuel more investment and progress, which met with some success. An important book by Jeff Rubin,4 the former chief economist of a Canadian bank, explains how eternal growth is embodied in the mindset of the economist. The policy in the recessions was to adjust lending rates and inflation to stimulate a return to growth. It is evident that now new policies are needed to minimise the impact of long-term contraction imposed by falling energy supplies. A remarkable presentation by Chris Martenson (2014) explains the situation well.5 The post-war years saw a rapid general world recovery, led by the United States but later joined by India and China which were able to use cheap labour to compete on world markets. Manufacturing in the United States declined, placing more emphasis on its financial stake. This epoch of prosperity was at root made possible by a flood of easy and cheap oil-based energy. But it too ran its course as the demand for oil began to outpace the supply during the early years of this century. Traders spotted the trend of rising oil prices and bought positions on the Futures Market causing a surge in oil prices to almost $150 in 2008 – prices having averaged no more than about $47 over the past 50 years (quoted in 2013 dollars). The scale of speculation is indicated by the fact that the amount traded on the Futures Market exceeded actual production sometimes by a factor exceeding as much as ten.6 It is noteworthy that the price of oil quoted in terms of gold has not changed significantly over the past half century.

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266   Handbook of energy politics

THE SECOND HALF OF THE OIL AGE DAWNS The foregoing has endeavoured to touch on some of the key issues of past history which saw a radical change with the opening of the Industrial Age, fuelled by energy from coal followed by oil and gas. This new energy supply has allowed the human population to grow six-fold in only 150 years, which is a very exceptional burst in historical terms. It is of course a huge subject, and it is difficult to track not only the facts but also to identify the hidden pressures behind the unfolding events. But Regular Conventional Oil, which has dominated past production, being relatively easy and cheap to produce, reached a peak in 2005 at 67 kb/d (thousand barrels a day), since when it has fallen to 61 kb/d, and is expected to continue to do so at about 2.5 per cent a year. Its price surge to almost $150 a barrel in 2008 imposed recession cutting demand such that prices fell to $63 in 2009 before again passing $100 a year later. Its production limits had long been recognised by the major oil companies which moved to try to replace it by much more difficult and expensive oil from tar sands, polar and deepwater regions, and more recently by artificially fracturing oil- and gas-bearing rocks lacking adequate natural porosity and permeability. They would certainly not have turned to these expensive and difficult sources had there been adequate Regular Conventional oil left. There has also been a surge in recent years in the formation of small promotional and speculative oil companies taking up exploration right in the hope of making a profitable discovery. It is more difficult to analyse the gas supply situation. In earlier years, it was barely economic, and much was flared. It also has a somewhat different depletion profile with production constrained by pipeline capacity giving a long plateau followed by a steep decline. The assessment made here suggests that production will reach a maximum of 132 Tcf/a (trillion cubic feet a year) in 2015 and then decline at about 2.5 per cent a year. For a more detailed assessment on a country by country basis, see a recently published Campbell’s Atlas of Oil and Gas Depletion (2013).7 Looking ahead, it is obvious that the world faces radical changes. Today, annual production of some 57 billion barrels of oil and gas (the latter quoted in terms of energy equivalent) supports a population of 7  billion people, but by 2050 the supply will be sufficient to support little more than half that number in their present way of life. Agriculture has been described as process that turns oil into food, having become very oil dependent for fuelling the tractors and transport as well as providing artificial nutrients. The transition threatens to be a time of great tension as indeed has already been witnessed by riots and revolutions around the world. People facing soaring food prices and growing

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The Oil Age  ­267 unemployment tend to blame their governments, as already witnessed especially in North Africa and parts of the Middle East in the so-called Arab Spring. These countries tended to have dictatorial regimes, and people hoped that democracy would improve their lot, which is unlikely to be realised because the underlying cause is depletion imposed by nature. It is not solely an issue of petroleum supply as such, as the modern world is also destroying its environment, depleting water supplies, cutting down forests and causing soil erosion, as fully discussed by Gore (2000)8 and Heinberg (2003).9 Industrial emissions may also be affecting the climate, as some scientists believe, although it has changed many times in the geological past in response to solar cycles, massive volcanic eruptions and other factors. The European Union was constructed following the Second World War to build an economic empire to rival the United States and remove some of the causes of conflict that had led to two very costly and devastating wars. It was a successful enterprise that adopted a common currency, as well as removing internal barriers to migration. But the recent economic crisis has had a serious impact, especially in Greece, Italy, Spain, Portugal and Ireland. Governments naturally hope that conventional financial methods will restore prosperity, but gradually people are losing confidence. It is significant that Scotland now contemplates seceding from the United Kingdom, formed in 1802, and there are similar pressures in Spain and Belgium. It makes eminent sense, even though it comes too late for Scotland to enjoy all the proceeds of its substantial share of North Sea oil and gas. This speaks of a new regionalism that could offer positive solutions in the changed circumstances. It is being actively supported by the Transition Town Movement, which has even introduced local currencies (see Hopkins, 2008).10 The United States too may see more devolved authority given to the individual states, which makes great sense. The people of Montana may come to live on whatever their ample and beautiful countryside can provide. Gradually there may be a new awakening as more and more people become aware of what unfolds.11 Indeed, there is now a proliferation of books and scientific papers touching on the subject, many of which are listed in Campbell’s Atlas of Oil and Gas Depletion.12 An excellent article by Lindsey Grant (2013) summarises the situation in an historical context, suggesting an inevitable collapse in population.13 Another valuable insight into the world’s position is provided by Leonard (2013).14 There is much that governments could do with new policies to meet the unfolding situation, including the following, as already proposed at a recent conference organised by INSEAD in Paris:15

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268   Handbook of energy politics 1. Adopt the Oil Depletion Protocol: already the Portuguese Parliament has passed a resolution urging its government to adopt a policy for cutting consumption to match world depletion rate (annual as a percentage of future production). Depletion is currently running at no more than about 2.5 per cent a year for Regular Conventional oil and less than 1 per cent for all categories. Cutting demand by such small amounts should be readily attainable. A book by Heinberg (2006) describes the proposal.16 2. Progressively disallow energy costs as a charge against corporate taxable income, which is a form of hidden subsidy. Management, facing these costs head-on, would likely react by paying more attention to energy efficiency, for which there is much scope. 3. Install smart meters, so that households may be more aware of their electricity consumption as they use it, and impose new tariffs whereby the cost per unit rises with increasing consumption. 4. Encourage car-sharing whereby people come to give lifts, sharing the cost of the fuel. 5. Introduce a Tradable Ration whereby everyone receives a ration at a fixed price providing for minimal essential needs to people in different circumstances, but are free to trade what they do not use. 6. Encourage the development of energy from tides, waves and wind, as well as that from solar and geothermal sources. Anaerobic digestion, by which urban and agricultural organic waste is used to generate methane, can also contribute. Home-owned wind- and solar-power facilities can make households largely self-sufficient, even selling a surplus back to the grid. 7. Encourage a new regionalism with local currencies, managed responsibly, whereby people may become less oil-dependant and again rely on what their particular region can support. This might prompt a new more positive democracy with the leaders having better links with the people they represent, being freed from hidden financial and other pressures. 8. Above all, take measures to reduce the world population. Petroleum Man will be almost extinct by the end of the century, but Homo sapiens, if he is as wise as his name implies, can survive in reduced numbers, provided he adapts intelligently.

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The Oil Age  ­269

SUMMARY It may be useful to briefly summarise how the author became aware of the subject. In 1957, having finished a DPhil in geology at Oxford University, he joined a major oil company to work in Trinidad as a field geologist, being later transferred to Colombia, where he had some colourful experiences mapping remote areas in the eastern Andes and Magdalena Valley. Mules provided transport for his field party in beautiful, if partly bandit-infested, country. The task was to identify the different geological formations with the help of their fossil content. They were exposed in isolated outcrops, so logic and imagination were needed to interpret the intervening geology.17 In 1966, prior to a transfer to Australia for fieldwork in Papua New Guinea, he was asked to compile a report on the prospects of Colombia. Each of the geological basins was analysed, with the number of exploration wells (wildcats) and discoveries being duly noted. It soon became evident that some of the basins had good remaining prospects whereas others lacked much potential. The prime prospects of the Llanos Basin in a remote area east of the Andes were identified. It later became a major source of oil but was not economic at the time with oil prices then around $14 a barrel (quoted in 2013 dollars). In 1969, he found himself in the head office of another major company in Chicago as part of a team making a world evaluation. He had responsibility for Latin America, and it soon became clear that every country had a pattern comparable in varying degrees with that already observed in Colombia. The finite limits were evident, and this insight, with its farreaching implications, made a deep professional and personal impact. In 1984, after many intervening experiences managing oil exploration in Ecuador, Europe and Turkey, he found himself as an executive vicepresident in Norway. His underlying interest in depletion remained, and he had his company sponsor research into the subject by the Norwegian Petroleum Directorate. Consultants were retained, and data on production and reserves, as published by the Oil & Gas Journal, were used to construct models of each country’s depletion profile. The Directorate agreed that the results of the study could be published as a book.18 This caught the attention of Petroconsultants in Geneva, who maintained the industry’s confidential database. They proposed compiling a new report based on their more accurate data, working with a French expert, Jean Laherrère.19 It was duly produced, covering the world’s significant producing countries. It was suppressed under pressure from an oil company, but the results were summarised in an article, entitled ‘The End of Cheap Oil’,20 published by Scientific American in 1998. Prior to that, the author had formed the Nordic-American Oil Company

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270   Handbook of energy politics to buy up oil rights in the United States in expectation of a radical increase in oil price. It started production in West Texas using fracking technology in the Artesia Field, but it was ahead of its time and had to be sold. He also found himself retained as a consultant to help the Bulgarian Government attract foreign oil companies on the fall of the communists. Another project was to work for Shell to determine the relative ownership of the Statfjord Field, which crosses the median line between British and Norwegian waters in the North Sea. His interest in the subject of depletion continued over the subsequent years of retirement. It led to the formation of the Association for the Study of Peak Oil and Gas (ASPO), which now has affiliates in more than 30 countries and holds major international conferences. He has published seven more books on the topic, and has made presentations at more than 100 conferences. It is a contentious subject with two main camps: on the one side are the geologists and engineers familiar with the actual discovery and production process; while on the other side are the economists with a faith that market forces must deliver, being very conscious of the time-value of money. Both camps have strengths and weaknesses in their positions. There are also many vested interests with motives to obscure the true position.

NOTES   1. W. Stanton (2003) The Rapid Growth of Human Populations 1750–2000: Histories, Consequences, Issues, Nation by Nation, Brentwood: Multi-Science Publishing Co. Ltd.   2. M. Dittmar (2009) ‘The future of nuclear energy: Facts and fiction’, available at http:// europe.theoildrum.com/node/5631, 5 August–10 November. Also, a 2011 update.   3. D. Yergin (1991) The Prize, New York: Free Press.   4. J. Rubin (2012) The Big Flatline – Oil and the No-Growth Economy, New York: St. Martin’s Press.   5. C. Martenson (2014) ‘Accelerated crash course’, available at https://www.youtube.com/ watch?v=pYyugz5wcrI, accessed 19 November 2017.   6. L. Tolub and M.A. Erb (2010) ‘Oil price band for the next decade: Utopia versus ­reality’, Swiss Derivatives Review, 43, Summer, 8–12.   7. C.J. Campbell (2013) Campbell’s Atlas of Oil and Gas Depletion, Berlin: Springer.   8. A. Gore (2000) Earth in Balance, Upper Saddle River, NJ: Prentice Hall.   9. R. Heinberg (2003) The Party’s Over, Vancouver: New Society Publishers. 10. R. Hopkins (2008) The Transition Handbook, Cambridge: Green Books. 11. C.J. Campbell (ed.) (2011) Peak Oil Personalities, Skibbereen, Ireland: Inspire Book. 12. C.J. Campbell (2013) Campbell’s Atlas of Oil and Gas Depletion, Berlin: Springer. 13. L. Grant (2013) ‘Capitalism: Growth and collapse’, Negative Population Growth Inc. October. 14. R. Leonard (2013) ‘The new oil world: The game has changed, but how? Africa is becoming a major new player in the new world hydrocarbon order’, American Foreign Policy Interests, 35, 352–9. 15. C.J. Campbell (2013) ‘Recognising the second half of the oil age’, Environmental Innovation and Societal Transitions, vol. 9., pp. 13–17.

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The Oil Age  ­271 16. R. Heinberg (2006) The Oil Depletion Protocol: A Plan to Avert Oil Wars, Terrorism and Economic Collapse, Vancouver: New Society Publishers. 17. C.J. Campbell and H. Bürgl (1964) ‘Section through the Eastern Cordillera of Colombia, South America’, Geological Society of America Bulletin, 76, 567–90. 18. C.J. Campbell (1991) The Golden Century of Oil 1950–2050: The Depletion of a Resource, Dordrecht, Netherlands: Kluwer Academic Publishers. 19. C.J. Campbell and J.H. Laherrère (1995) World Oil Supply 1930–2050, Geneva: Petroconsultants. 20. C.J. Campbell and J.H. Laherrère (1998) ‘The end of cheap oil’, Scientific American, March, 80–8.

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272   Handbook of energy politics

APPENDIX Table 11A.1  Resource based production forecast, 2012

REGION

RESOURCE BASED PRODUCTION FORECAST Regular Conventional ON by Country to 2100 Sorted by production in 2010 Mb/d

2000 2010

2020

2030

D.R Disc/ % NFW

Totals Gb Past Future

C F F C H

Russia Saudi Arabia Iran China US-48

6.48 7.77 3.70 3.25 4.21

8.73 8.37 4.08 4.08 3.37

6.31 9.32 3.38 2.70 1.90

4.09 7.43 2.85 1.58 1.08

4.2 1.9 1.5 5.2 5.5

24 156 1537 124 68 307 42 26 0.5 181

74 176 82 28 19

E F F F D

Mexico UAE Iraq Kuwait Norway

3.01 2.37 2.57 1.76 3.22

2.62 2.42 2.40 2.04 1.87

1.74 2.74 4.41 2.33 1.29

0.83 2.33 3.65 1.98 0.77

7.1 1.9 1.4 1.5 4.2

35 219 567 1540 40

41 32 36 41 25

15 53 79 59 13

A A C D A

Algeria Libya Kazakhstan Nigeria UK

1.25 1.41 0.72 2.17 2.28

1.54 1.65 1.53 1.25 1.23

1.10 1.38 2.19 1.37 0.60

0.73 1.09 1.95 1.11 0.37

4.0 1.5 1.4 1.8 4.6

22 28 26 38 9

22 28 12 29 25

13 32 38 26 6.6

G C B H G

Qatar Azerbaijan Indonesia Oman Venezuela

0.74 0.28 1.43 0.97 2.47

1.13 1.04 0.95 0.87 0.90

1.21 0.82 0.60 0.60 0.88

1.15 0.61 0.41 0.35 0.76

1.8 2.6 4.1 5.3 1.5

315 42 7 21 31

10 11 25 10 51

25 13 7.5 6.0 24

H E B E A

Canada Colombia India Argentina Angola

0.91 0.69 0.65 0.76 0.75

0.88 0.79 0.75 0.63 0.52

0.49 0.60 0.50 0.38 0.21

0.27 0.34 0.33 0.24 0.16

5.8 5.5 4.0 4.6 2.6

1 7 7 3 14

21 8 8 11 6.5

4.7 5.9 6.1 4.2 3.5

B F A A E

Malaysia N.Zone Egypt Sudan Ecuador

0.69 0.63 0.77 0.19 0.39

0.56 0.53 0.58 0.51 0.49

0.38 0.35 0.40 0.45 0.38

0.25 0.24 0.26 0.26 0.26

4.1 3.9 4.1 1.0 3.6

14 273 8 21 28

7.5 8.7 11 1.7 5.1

4.5 4.3 4.8 4.3 4.9

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The Oil Age  ­273

Percent

Peak Dates

Disc Dep Expl Disc

Prod

94 97 92 92 99

68 41 46 61 91

1988 1967 1967 2003 1981

1960 1948 1964 1960 1936

1987 1981 1974 2010 1970

97 94 90 97 95

73 37 32 41 65

2003 1952 1978 1963 2009

1977 1972 1928 1938 1979

2004 2016 2028 1991 2001

96 95 89 95 98

62 47 24 53 79

1961 1963 1988 1967 1990

1956 1961 2000 1968 1974

2006 1970 2026 2005 1999

96 95 98 96 95

29 45 77 62 68

1988 1953 1983 1984 1981

1940 1871 1944 1962 1914

2020 2010 1977 2000 1970

97 92 98 93 96

82 58 58 72 65

1980 1988 1991 1985 1968

1958 1988 1974 1962 1978

1973 2012 2011 1998 2000

98 97 96 86 95

63 67 70 28 51

1970 1962 2008 2002 1972

1971 1960 1965 2003 1969

2004 2003 1996 2019 2006

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REGION

2012

F C A E H D B G

Regular Conventional Oil by Region D.R % ME.Gulf Eurasia Africa L.America N.America Europe Asia-Pacific ME Minor Minor

2000 2010 2020 2030

1.7 18.8 19.8 3.4 11.2 15.8 2.2 7.3 6.9 3.8 8.1 5.8 5.6 5.1 4.3 4.6 6.1 3.5 4.1 4.3 3.5 2.5 2.8 2.7 4.5 0.5 0.8

22.5 18.5 12.4 8.6 5.5 4.4 4.3 2.6 2.4 1.3 2.1 1.3 2.4 1.5 2.1 1.7 0.6 0.3

45 43 29% 31%

32 22 43% 47%

Non ME.Gulf ME.Gulf Share Total

Mb/d

2.5 64

63

53

39

Non Conventional Oil 1.3 3.5 1.8 2.2

Heavy etc. Deepwater Polar Gas Liquid Total WORLD

3.6 1.6 1.3 6.4

5.7 11.2 6.7 9.4 1.4 2.0 8.4 8.0

11.7 6.0 2.3 6.6

13

22

31

27

2.3 77

85

84

66

Production to 2100 Regular Conventional

All Oil

Gb

%

Gb

%

PAST FUTURE Known To be found

1141 909 794 114

56 44 39 5

1297 50% 1303 50%

Discovered

1936

95

2263

TOTAL

2050

2600

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274   Handbook of energy politics Table 11A.1  (continued)

REGION

RESOURCE BASED PRODUCTION FORECAST Regular Conventional ON by Country to 2100 Sorted by production in 2010 Mb/d

2000 2010

2020

2030

D.R Disc/ % NFW

Totals Gb Past Future

B G B A G

Australia Syria Vietnam Congo(B) Yemen

0.72 0.52 0.36 0.10 0.44

0.48 0.37 0.32 0.11 0.26

0.28 0.13 0.32 0.06 0.12

0.20 0.10 0.20 0.03 0.09

3.2 2.3 3.3 6.3 2.9

2 20 23 17 10

7.5 5.1 2.3 2.5 2.8

4.0 2.4 3.7 1.5 1.9

B D A E C

Denmark Thailand Gabon Brazil Turkmenistan

0.36 0.11 0.32 0.50 0.14

0.25 0.24 0.25 0.16 0.18

0.12 0.13 0.18 0.13 0.16

0.06 0.06 0.12 0.11 0.10

6.5 6.6 3.8 1.9 4.0

17 6 8 3 10

2.4 1.1 3.8 6.2 3.6

1.1 1.2 2.2 2.8 1.9

B A E D C

Brunei Chad Trinidad Italy Romania

0.19 0.00 0.12 0.09 0.12

0.14 0.12 0.10 0.10 0.09

0.08 0.14 0.06 0.07 0.07

0.05 0.10 0.05 0.04 0.06

4.2 2.1 3.1 4.6 2.2

32 28 12 1 8

3.6 0.4 3.6 1.2 5.6

0.9 1.8 0.9 0.8 1.4

C A E A B

Ukraine Tunisia Peru Cameroon Pakistan

0.07 0.08 0.10 0.08 0.05

0.05 0.08 0.07 0.07 0.06

0.04 0.05 0.05 0.04 0.04

0.04 0.04 0.04 0.02 0.02

1.4 3.1 2.7 5.8 4.9

7 4 7 8 1

2.9 1.5 2.6 1.3 0.7

1.1 0.7 0.9 0.4 0.4

G C E G B

Turkey Uzbekistan Bolivia Bahrain Papua

0.05 0.09 0.03 0.04 0.07

0.05 0.06 0.04 0.04 0.03

0.03 0.10 0.03 0.02 0.02

0.02 0.09 0.03 0.01 0.02

5.9 1.7 2.1 5.8 3.6

1 3 3 56 4

1.0 1.1 0.6 1.1 0.5

0.3 1.4 0.7 0.2 0.3

D D D D C

Germany Netherlands France Austria Hungary

0.05 0.03 0.03 0.02 0.03

0.03 0.02 0.02 0.02 0.01

0.03 0.02 0.01 0.01 0.01

0.02 0.01 0.01 0.01 0.01

2.1 2.4 3.8 5.6 1.7

2.0 0.9 0.8 0.9 0.7

0.5 0.3 0.2 0.1 0.3

C C E A

Croatia Albania Chile Uganda

0.02 0.01 0.01 0.00

0.01 0.01 0.00 0.00

0.01 0.01 0.01 0.15

0.01 0.01 0.00 0.15

1.7 2.6 3.2 0.0

3 10 1 48

0.6 0.5 0.4 0.0

0.3 0.2 0.1 2.0

64

62

53

39

2.5

4

WORLD

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1 1 0.5 1 1

1115

885

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The Oil Age  ­275

Percent

Peak Dates

Disc Dep Expl

Disc

Prod

95 95 97 96 92

65 68 38 62 60

1985 1992 1994 1992 1992

1967 1966 1975 1984 1984

2000 1996 2016 2011 2001

94 90 94 97 93

70 53 63 69 66

1985 1983 1989 1982 1986

1971 1981 1985 1975 1956

2004 2010 1997 1990 1973

99 84 99 94 95

79 21 79 62 80

1975 2002 1972 1962 1969

1929 1977 1959 1989 1890

1979 2015 1981 1997 1976

99 96 95 95 93

71 67 75 78 63

1990 1981 1975 1977 2003

1962 1964 1869 1977 1984

1970 1983 1982 1985 2006

Notes Requíar Conventional Oil Includes condensate

97 83 92 99 98

79 44 0 85 62

1975 1991 1962 1983 1990

1961 1985 1999 1932 1987

1991 1998 2005 1970 1993

ME-Gulf =UAE, Iran, Iraq, Kuwait, NZ, S.Arabia. Eurasia = FSU, E.Europe & China. N.America = USA & Canada. Minor refers to countries having insignificant production or possibilities

96 99 97 98 93

79 74 84 89 73

1958 1985 1959 1975 1964

1949 1943 1954 1949 1965

1967 1986 1988 1955 1979

91 94 99 80

69 69 87  0

1985 2013 1972 2010

1957 1928 1960 2009

1988 1983 1982 2030

95

56

1981

1964

2005

The Production Forecast assumes decline at the Current or Midpoint Depletion Rate, whichever comes first. Depletion Rate = annual production as % of Future. Deepwater >500m WD. The statistics refer to production to a cutoff at the end of the century not ultimate recovery. DR = Depletion Rate (Annual/Future). D¡sc/ NFW = Av. Discovery In Mb per wildcat. The world total includes a small rounding factor.

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12.  New energy and the geopolitics of the future Michael Lynch

The global energy scene is rapidly evolving, with impetus coming from two directions: technical advances and policy imperatives. On the one hand, the ability to produce oil and gas from shales has greatly increased supplies of those fuels, while cheaper photovoltaics, wind power and batteries are changing the landscape for power and transportation. On the other, concerns about climate change are leading governments to pursue cleaner sources of energy through subsidies, mandates and research. There are a variety of effects on the geopolitical situation, some obvious, others subtle. The typical view can be summed up by a recent piece by former Energy Secretary Ernest Moniz: While oil security remains important, these principles reflect the greatly changed global energy landscape and several are particularly important to this discussion. First, infrastructure modernization will improve energy system resilience. Second, reducing our greenhouse gas emissions and accelerating the transition to a low-carbon economy are key contributors to enduring energy security. Third, energy efficiency should be enhanced across the board. And fourth, a commitment to clean energy technology innovation underpins energy security. (Moniz, 2017)

This chapter will offer a more nuanced reading of the changes occurring and their impact on energy security and geopolitics more broadly.

ENERGY AND GEOPOLITICS Resources appear to have influenced geopolitics as far back as history records. More than five millennia ago, the Naqadans of Egypt were dependent on the Levant (modern Lebanon) for wood for their boats yet appear to never have suffered a shipping collapse because of this vulnerability (granted, evidence is sparse from that period). But generally, in pre-modern times, energy consumption meant biomass (waste and woody products) and renewables (wind and water), with virtually no 276

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New energy and the geopolitics of the future  ­277 “­ commercial” energy used, and little trade in energy, although ancient societies did exchange other resources and goods on a broad scale. The common perception is that coal fueled Britain’s Industrial Revolution and was a major factor in the rise of its empire, although progress came less from the resource itself than the technical advances (steam engines) that allowed it to be converted into more usable power. Coal exports did not affect British power, as they were not very large but also because coal is not only relatively abundant, but also in many uses, wood or charcoal could be substituted. British geopolitical power was projected by coal-fired gunboats, not coal colliers. But the Industrial Revolution also saw an enormous rise in the need for energy, and many parts of the world lacked large resources of commercial energy, creating a massive trade in first coal, then oil, gas and uranium. This changed the political landscape in a number of ways.

THE MODERN ERA Petroleum had the biggest impact on geopolitics, but not immediately. The initial use was for lighting and lubricants, both of which had ready, if less desirable, substitutes (primarily animal fats and vegetable oils). While the U.S. in particular prospered from its oil wealth in the nineteenth century, coal was still the main source of energy and the international conflict over petroleum was primarily at the corporate level, especially as other companies fought Standard Oil’s dominance late in the century.1 The early twentieth century changed this, as the discoveries at places such as Spindletop in Texas (1901) and in Persia (1908) convinced consumers that oil was abundant, encouraging them to rely on it to fuel trains and ships. The development of the internal combustion engine at the same time not only provided a market for gasoline, previously a waste product, but also changed the nature of warfare as motorized troops and logistics returned maneuver to the battlefield after World War I’s horrendous trench warfare. Recognition of petroleum’s strategic consequences probably first began with Winston Churchill, who worried that switching the Royal Navy to oil would mean dependence on the unreliable United States or Russia. (The first actual military action against an oilfield was in 1863 when Confederate cavalry attacked Burning Springs, Pennsylvania. The impact on the war’s outcome was negligible.) Given his concerns, Churchill supported the U.K. government’s investment in what is now BP and its newly discovered oilfields in what is now Iran. The government also sought to gain control of oil in Iraq through the Sykes-Picot Agreement, dividing parts of the post-World War I Ottoman Empire with France.

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278   Handbook of energy politics But strategic ownership of resources did not guarantee tactical access. In World War II, both Germany and Japan were desperate to acquire foreign oil, among other resources, and this was a factor fueling the conflict. Ultimately, especially for England and Japan, the ability to deliver the oil was the challenge, not possession of the fields, as shipping proved vulnerable to attack and controlling overseas fields did not erase a nation’s vulnerability. This lesson was not well learned. Instead, the role of U.S. and British oil companies in implementing an oil embargo against Japan in 1941 caused a number of governments to think that the nationality of the oil producing companies was the guarantor of supply and that politics, not economics, was key to access of needed resources. The post-war era saw a new phase of petroleum geopolitics, as Roosevelt’s granting of Lend Lease aid to Saudi Arabia marked the recognition of the importance of that region’s resources and other importing nations set up their own national oil companies to seek out foreign petroleum supplies.

A HISTORY OF ENERGY INSECURITY By the early post-World War II years, it was obvious that the Middle East continued enormous amounts of cheap petroleum resources, and would come to dominate the industry. There were early threats by some governments to delay development in protest to the founding of Israel, but the reality was that producing nations in this era were far more concerned about acquiring revenue from production and exports. Mexico was a ­stand­out; their 1937 nationalization of foreign holdings delayed largescale exploitation of the nation’s resource for roughly four decades. Although it is difficult to sort out the political leverage of Middle East nations resulting from their oil resources as opposed to their role in the Cold War, there is little doubt that many Western countries provided more economic and political aid to oil-rich nations than they would have otherwise. The United States developed what was called a “special relationship” with Saudi Arabia and, especially during the Nixon Administration, sought to cultivate the Shah of Iran as the region’s policeman. National oil companies in France, Italy and Japan used their diplomatic leverage in seeking oil concessions, the first two in former colonies, all seeking Middle Eastern fields with mixed success as the Seven Sisters had locked up most of the territory. The two oil crises in the 1970s changed attitudes about the political importance of petroleum resources. The Second Arab Oil Embargo in 1973 sent most importing nations scurrying to curry political favor with oil exporters in the Middle East, making diplomatic concessions and offering various aid and investment programs. What had passed unnoticed was

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New energy and the geopolitics of the future  ­279 that the two targets of the embargo—the U.S. and the Netherlands—did not suffer disproportionately from oil shortages as the large oil companies shifted supplies to offset shortages, or at least share them equally.2 The 1979 Iranian Revolution demonstrated the vulnerability to disruptions of an extra-governmental nature: the regime’s opponents cared little about the international oil market, and foreign governments had literally no leverage with them. But it highlighted the degree to which oil’s importance made it a target for hostile groups, from within and without a nation. Saddam Hussein underlined this point when he destroyed the Kuwaiti oilfields in 1991. Complacency set in afterwards as many countries built strategic reserves of petroleum and OPEC ended up with an enormous amount of unused capacity that could easily offset any sudden shortfall of supply. But by 2000, this had shrunk and a number of smaller disruptions added up to a sufficient loss of supply that the oil price soared for roughly a decade, reminding consumers of their vulnerability. But one major lesson went unlearned: the vulnerability in most cases was the result of susceptibility to economic damage from higher prices, not the famous “factories going dark” that an absence of supplies would cause. Yet most governments with strategic reserves to this day insist that they will release them only if physical shortages occur, which is unlikely in the modern, relatively free oil market. The importance of oil in geopolitics has certainly declined, at least for the moment. Still, there are cases where a country might be seriously dependent on one energy supplier, as many Eastern European countries are on Russia for natural gas, and there is clearly a desire to reduce that vulnerability. And since most fossil fuels are priced at the market, switching from them to renewables or nuclear can ease economic damage from supply disruptions and higher prices, import or domestic.

NEW TECHNOLOGIES There are major changes underway in the energy industry that could alter the geopolitical landscape: the rise of renewable energy (wind and solar), electric vehicles, the hydraulic fracturing of shales and the development of advanced nuclear power plants. Nearly all will result in greater energy autonomy for most countries, but with exceptions. The outlook for the overall energy sector remains a subject of much dispute, with some insisting that reliance on renewable energy for 100 percent of the world’s supplies is both necessary and desirable,3 others arguing large-scale development of nuclear power is crucial to reducing greenhouse

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280   Handbook of energy politics gas emissions, and still others predicting that oil demand will soon peak. Conventional forecasts from groups like the International Energy Agency do not see massive change without major policy efforts; some analysts are much more aggressive in predicting disruption from new technologies.4 The increased use of wind and solar power almost always results in only minor reductions in reliance on foreign fuel. The days when power plants ran on Middle Eastern oil are (mostly) long behind us, but many nations still import natural gas for power generation, especially in Europe and East Asia. Conversely, nearly all renewable power is produced domestically; talk of megaprojects like a solar array in North Africa to send power to Europe would be an exception, but there are few such projects that would likely be developed. Power exports within Europe would constitute another exception as Germany, especially, runs a surplus at certain times. Still, by reducing gas use in power generation, and thus gas imports, with increased renewable energy production, some countries will be less vulnerable to outside pressure and/or disruptions. Reliance on other nations’ grids to maintain domestic grid stability does increase an element of vulnerability, but in places like Europe, this is more of a technical than political issue. The geopolitical impact of greatly increased renewable power would be minimal, however, since coal imports are not perceived as a source of political vulnerability, primarily because of the widespread availability of coal. Only one-third of global natural gas consumption crosses borders and much of that is considered secure (Norway to France, Canada to the U.S.). Europe is the biggest natural gas importer globally, but gets only 16 percent from Russia and 4.5 percent from Algeria. Among nations, Germany relies on Russia for 60 percent of its consumption, and Japan gets more than half of its LNG from three suppliers: Qatar, Australia and Malaysia. Outside of Eastern Europe, dependency on one or a few sources for a major portion of gas supply is rare. Table 12.1 shows how much various European nations rely on Russia for their gas supply, as well as how much of their gas consumption is used for power generation. The combination of lack of import dependence on one or a few sources, combined with significant opportunities for fuel-sharing and conservation in a crisis makes most importers relatively unconcerned about their vulnerability to pressure from gas exporters.5 Even weak Ukraine, receiving virtually all of its gas from Russia, nevertheless resisted political pressure from its neighbor on a number of recent occasions. Definitely, though, the rise of shale gas and the potential for large-scale LNG exports from the U.S. will mean that global gas trade will become a buyer’s market and the political leverage that exporters might have had will be much reduced.

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New energy and the geopolitics of the future  ­281 Table 12.1  Russian gas in Europe Share of Consumption

Gas Used for Power

52.2% 67.9% 57.4% 129.0% 24.4% 60.6% 69.1% 64.8% 39.1% 7.4% 52.5% 87.0% 60.9%

7.2% 21.4% 2.4% 6.4% 2.6% 10.5% 11.4% 9.9% 28.9% 43.6% 3.3% 5.7% 46.9%

Austria Belgium Czech Republic Finland France Germany Greece Hungary Italy Netherlands Poland Slovakia Turkey Source:  BP (2016); IEA (n.d.).

Whether or not large-scale renewables deployment would reduce or increase dependence on imports in some places remains an open question. At present, the extreme variability of wind and solar requires backup from conventional power plants, primarily gas turbines which are capable of rapid start-up. But this could mean more gas imports, which can increase vulnerability.6 If China were to install massive amounts of renewables, it is likely that imports of natural gas would soar to offset the variability of wind and solar, although it is possible that better storage technology and/ or system management would reduce the problem significantly. In the 1970s, a number of countries saw nuclear power as providing a route to energy independence, or at least significantly reduced vulnerability. France and Japan were the most ardent in this regard, with 225 and 150 terrawatt hours produced in 1985 after aggressive building programs, making up 67 percent and 23 percent respectively of their electricity supplies. Both reduced their oil consumption, but only by 28 percent and 15 percent respectively, hardly insignificant but leaving them still dependent on imports. And their transportation sectors remained almost completely reliant on imported oil supplies. The attractiveness of nuclear power stems from the fact that while fuel must still be imported by most consuming nations, the amounts are small and relatively inexpensive. The 75 metric ton of uranium needed to fuel a 1000 MW nuclear reactor displaces 1.5 million metric tons of coal or 4 million barrels (0.5 million metric tons) of oil.7 The historical concentration

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282   Handbook of energy politics of uranium production in a few countries, and especially Australia and Canada, where labor and political disputes raised concerns about stability of supply, did cause some concern, but the cost of stockpiling a year’s worth of nuclear fuel is trivial compared to coal or oil, which would cost 15 to 20 times as much respectively, even ignoring storage costs. Although public opposition has meant much slower development of nuclear power in recent years, the possibility that advanced versions— such as small modular reactors (SMRs)—will spread could mean a drop in imported gas and coal in some parts of the world. Again, as with renewable power, the biggest impact would be on European imports of natural gas from Russia and North Africa, but potentially China and India would not become major natural gas importers if they accelerate deployment of SMRs. The IEA’s latest projection sees the two countries as the fastest growing markets for gas, at a 4.6 and 5.2 percent per year rate to 2040, most of which would be met by imports.8 Thus, the biggest impact from renewables and/or nuclear power advances will be to coal consumption for power, which is not a major element on the geopolitical landscape. Only Australia and Indonesia rely on exports for a significant portion of their GDP, and reductions in coal production will not affect their economic power greatly. Most major consumers are also major producers, so that only a few countries, like Japan, rely significantly on imports for their supply. And coal exporters have rarely been able to gain political advantage from their resource, given the easy availability of alternative supplies. And although many believe that battery electric vehicles or advanced biofuels have the potential to reduce oil consumption and thus, import dependency, the truth is that neither has progressed to the point of widescale adoption. Even the most optimistic projections, such as Bloomberg New Energy Finance’s, only see a market share of less than 20 percent by 2030.9 More realistically, only a small portion of vehicles in use two decades from now will be electric, and advanced biofuels—promised as imminent for two decades already—appear similarly dubious. Hydraulic fracturing to produce shale oil and gas is another matter, with mixed geopolitical effects. Although the practice has been slow to spread, and there continue to be uncertainties about the economics of shale in different regions, it seems highly likely that production will spread. Table 12.2 shows the most recent estimate of technically recoverable resources in major resource holders, at least as is known now. There are many areas that have not been studied and are not included in the ­estimates, so that the estimates are seriously conservative. Still, it indicates the places that might be exploited in the next decade or so. But it is significant that two countries dominate: Russia and the U.S.

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New energy and the geopolitics of the future  ­283 Table 12.2  Share of technically recoverable shale oil resources U.S.+Russia W. Europe S. Asia S. America

38.81% 3.74% 3.74% 17.30%

Source:  EIA/ARI (2003).

Many have argued that shale production outside the U.S. will not be significant because U.S. conditions are uniquely favorable, including private ownership of mineral rights, a dense service industry keeping costs low, and fiscal regimes that are favorable to investors. Most of these can be overcome. In nations like China and the Ukraine, which would benefit substantially from shale oil and/or gas production, the governments will ease the way for drillers. Argentina, in fact, has offered producers above-market prices to encourage investment in the sector. In nations like Canada and Colombia, the existence of a services industry should mean development will proceed without much delay, depending primarily on the geology and economics. But one important factor could reduce the geopolitical impact of shale: much of the resource is in areas that already have substantial conventional oil resources and production. Russia, in particular, stands out with a giant basin, the Bazhenov, that is thought to hold 75 billion barrels of technically recoverable resource (TRR). By comparison, Western European TRR is estimated at 9 billion barrels. Similarly, in North Africa, Moroccan and Tunisian TRR are dwarfed by Algeria’s and Libya’s. American shale makes a difference because although it has significant conventional oil production, consumption is far higher, so that shale oil production reduces dependence on imports. Aside from the “rich get richer” implications of this concentration in existing producing nations, the ability of import-dependent countries to utilize their shale resources for political power appears small. Initial optimism about Eastern European shale gas resources has not been fulfilled, and countries like Poland and the Ukraine have been unable to develop commercial production so far. Most Western European countries restrict or outright ban fracking, with only Britain likely to produce gas or oil in the near future. Longer term, though, as citizens become more comfortable with the technology, countries like France and Germany could become producers, although they are unlikely to become oil independent.

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284   Handbook of energy politics

CHANGES IN VULNERABILITY The biggest single impact on geopolitics from new energy technologies will be the potential for the U.S. to cease importing significant amounts of oil and possibly even becoming a net exporter. Given the U.S. role in the Middle East, essentially guaranteeing the security of a number of allied, oil exporting countries, the possibility that this will become unnecessary is no doubt causing concern in that region. Since American financial support for the Saudi regime began during World War II, there has been a perception that the crucial importance of Middle Eastern oil to the U.S. and global economy meant that America would stand as a guarantor of security for the Saudis and others. The liberation of Kuwait in 1991 enhanced that view. At the same time, the abandonment of the Shah of Iran in 1979 was proof that the U.S. is unlikely to support an allied regime against its domestic enemies. Some would even say that the Shah was urged to depart by America desperate to restore oil exports, and thus, the regime was made more vulnerable by the world’s dependence on its oil: the regime’s opponents wielded that weakness as a weapon. Middle East politics will continue to concern the U.S., even if it becomes a net exporter of oil. The Arab–Israeli conflict, or what remains of it, can be expected to be a preoccupation of almost any administration, particularly if the level of violence increases again. The Iranian threat to dominate the region can be expected to be of concern for a long time, including any possibility that its nuclear weapon program appears to be revived. But adventurism by some parts of the Iranian political establishment, including support for groups like Hezbollah in Lebanon and Syria’s Assad, will keep U.S. attention focused on that nation.

WHAT’S REALLY CHANGING? At the same time, it is hard to argue that the U.S. has allowed Middle Eastern oil to dominate its foreign policy, given the strong support for Israel for the past several decades. It has been claimed that the American companies producing oil in Saudi Arabia warned Nixon in 1973 against support for Israel that was too overt, as it might trigger an oil embargo, but he ignored them and made a flashy display of sending weapons to Israel. Similarly, when George W. Bush was elected president, many assumed that as an oilman with long family ties to Saudi Arabia, he would adopt a more pro-Arab stance, but he did just the opposite, hailing Israeli Prime Minister Ariel Sharon as a “man of peace,” to the surprise and consternation of many.10

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New energy and the geopolitics of the future  ­285 But there are a number of areas where shale gas especially can change the political landscape. Nations like Poland and the Ukraine are dependent on Russian natural gas for a majority of their gas supplies, and there is a perception that Russia has used “the gas weapon” against the Ukraine after the pro-Russian president was forced out of office in 2013 and Gazprom cut supplies, although the company claimed this was due to non-payment, not political reasons. Already, countries in Eastern Europe have sought to diversify supplies, especially by adding pipeline connections but also by seeking imports of LNG. However, it is not crucial for a nation to be completely independent to reduce its vulnerability significantly, and it is hard to see where the governments in either Eastern or Western Europe have bowed to Russian economic pressure. If anything, they have acted against Russian interests, especially since the Russian intervention in Ukraine. Imports do represent a vulnerability but it should not be exaggerated.

BLOWBACK Perhaps the most serious geopolitical threat arising from new energy technologies comes from the effect of lower petroleum revenues on some countries that are not very stable politically, such as Venezuela, Nigeria, Iran and Russia, although arguably some of the rich Middle East countries should be included. The rise of Hugo Chávez in 1998 was due, in part, to the economic problems Venezuela was experiencing as the result of lower oil prices. It is easy to see how unrest could increase in a number of countries, leading to an oil supply disruption that could last anywhere from days to months or even years. The longer and larger the disruption, the more severe the economic and political impact on oil-importing nations.

THE NEW ENERGY GEOPOLITICAL LANDSCAPE Again, the two axes of energy geopolitics are the economic and political power gained by exporters and the vulnerability of importers to political pressure. New energy technologies will affect both. Russia’s leverage resulting from its natural gas deliveries will be significantly reduced as shale gas not only displaces its gas but also increases the diversity of global supplies. Merely having the ability to import LNG from the U.S. will be a deterrence to any attempt by Russia to threaten importers with a loss of supply, even if imports from Russia don’t decrease.

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286   Handbook of energy politics Already, there is a perception that U.S. shale oil production has meant reduced fears of political vulnerability to oil imports from the Middle East, and the current shift from a sellers’ to buyers’ market provides importers with increased leverage over their suppliers. Indeed, some exporters refer to demand-side vulnerability, although given the fungibility of crude oil, refusing to buy from a given supplier will have minimal impact on their sales.

CONCLUSIONS New sources of power, whether renewables or nuclear, will play a modest role in changing global geopolitics, primarily reducing coal use and, slightly, natural gas imports. More important will be the role of shale oil and gas in both reducing some nations’ energy imports and apparent vulnerability, but also making markets more transparent and flexible. Perversely, declining petroleum revenues will increase political instability in exporting nations, which could have significant, albeit temporary, negative effects on the global economy and thus geopolitics.

NOTES   1. See G.P. Nowell (1994) Mercantile States and the World Oil Cartel, 1900–1939, New York: Cornell University Press.   2. M.A. Adelman (1995) The Genie Out of the Bottle: World Oil Since 1970, Cambridge, MA: MIT Press.   3. Mark Jacobson is one advocate, with a website devoted to the subject: https://www. beforetheflood.com/explore/the-solutions/100-percent-renewable-energy-is-the-onlymoral-choice/   4. See for example, Carbon Tracker Initiative and the Grantham Institute (2017) “Expect the unexpected: The disruptive power of low carbon technology,” February.   5. IEA (International Energy Agency) (2016a) “Global gas security review 2016,” especially Chapter 5, available at https://www.iea.org/publications/freepublications/ publication/GlobalGasSecurityReview2016.pdf, accessed November 20, 2017.   6. Preliminary data for Germany suggests a notable increase in natural gas use for power generation, but it is too early to draw a strong conclusion, see K. Appunn et al. (2017) “Germany’s energy consumption and power mix in charts,” Clean Energy Wire, available at https://www.cleanenergywire.org/factsheets/germanys-energy-consumption-andpower-mix-charts, accessed November 20, 2017.   7. See World Nuclear Association (2017) “The nuclear fuel cycle overview,” available at http://www.world-nuclear.org/information-library/nuclear-fuel-cycle/introduction/ nuclear-fuel-cyc​le-overview.aspx, accessed November 20, 2017.   8. IEA (International Energy Agency) (2016b) “World energy outlook 2016,” p. 169, available at https://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016. html, accessed July 28, 2017.   9. Bloomberg New Energy Finance (2017) “New energy outlook 2017: Global outlook.”

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New energy and the geopolitics of the future  ­287 10. A. Shlaim (2014) “‘Man of peace’? Ariel Sharon was the champion of violent ­solutions,” The Guardian, January 13, available at https://www.theguardian.com/com​ mentisfree/2014/jan/13/ariel-sharon-no-man-of-peace-israel, accessed July 28, 2017.

REFERENCES Adelman, M.A. (1995) The Genie Out of the Bottle: World Oil Since 1970, Cambridge, MA: MIT Press. Appunn, K., F. Bieler and J. Wettengel (2017) “Germany’s energy consumption and power mix in charts,” Clean Energy Wire, available at https://www.cleanenergywire.org/ factsheets/germanys-energy-consumption-and-power-mix-charts, accessed November 20, 2017. Bloomberg New Energy Finance (2017) “New energy outlook 2017,” available at https:// about.bnef.com/new-energy-outlook/, accessed July 28, 2017. BP (2016) “BP statistical review of world energy 2016,” available at https://www.bp.com/ content/dam/bp/pdf/energy-economics/statistical-review-2016/bp-statistical-review-ofworld-energy-2016-full-report.pdf, accessed July 28, 2017. Carbon Tracker Initiative and the Grantham Institute (2017) “Expect the unexpected: The disruptive power of low carbon technology,” February, available at http://www.­carbontracker. org/report/expect-the-unexpected-disruptive-power-low-carbon-­technology-solar-electricvehicles-grantham-imperial/, accessed July 28, 2017. EIA/ARI (2013) “World shale gas and shale oil resource assessment,” available at https:// www.adv-res.com/pdf/A_EIA_ARI_2013%20World%20Shale%20Gas%20and%20 Shale%20Oil%20Resource%20Assessment.pdf, accessed July 28, 2017. EIA (2016) “International energy outlook 2016–Electricity–Energy Information Administration,” available at https://www.eia.gov/outlooks/ieo/electricity.php, accessed July 28, 2017. IEA (n.d.) “Statistical database,” available at http://www.iea.org/statistics/statisticssearch/, accessed December 16, 2017. IEA (International Energy Agency) (2016a) “Global gas security review 2016,” available at https:// www.iea.org/publications/freepublications/publication/GlobalGasSecurityReview2016.pdf, accessed November 20, 2017. IEA (International Energy Agency) (2016b) “World energy outlook 2016,” available at https://www.iea.org/newsroom/news/2016/november/world-energy-outlook-2016.html, accessed July 28, 2017. IEA (International Energy Agency) (2017) “World energy statistics and balances,” available at https://www.iea.org/statistics/relateddatabases/worldenergystatisticsandbalances/, accessed July 28, 2017. Jacobson, M. (2017) “Before the flood – Renewable energy,” Before the Flood, available at https://www.beforetheflood.com/explore/the-solutions/100-percent-renewable-energy-isthe-only-moral-choice/, accessed July 28, 2017. Moniz, E.J. (2017) “Under Trump, energy security is running on empty,” The Hill, May 26, 2017, available at http://thehill.com/blogs/pundits-blog/energy-environment/335146under-trump-energy-security-is-running-on-empty, accessed December 16, 2017. Nowell, G.P. (1994) Mercantile States and the World Oil Cartel, 1900–1939, New York: Cornell University Press. Shlaim, A. (2014) “‘Man of peace’? Ariel Sharon was the champion of violent solutions,” The Guardian, January 13, available at https://www.theguardian.com/commentisfree/2014/ jan/13/ariel-sharon-no-man-of-peace-israel, accessed July 28, 2017. World Nuclear Association (2017) “The nuclear fuel cycle overview,” available at http:// www.world-nuclear.org/information-library/nuclear-fuel-cycle/introduction/nuclear-fuelcycle-overview.aspx, accessed July 28, 2017.

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13.  The economic case for staged development and providing appropriate incentives for good behaviour in the context of ‘resource curse’ Paul Stevens and Jennifer I. Considine

THE CONTEXT Common sense and elements of economic theory such as dual gap analysis suggest that large-scale revenues from oil, gas and mineral projects accruing to government should lead to economic growth and poverty reduction. However, over the years, the phenomenon of a negative impact of revenues from extractive industry projects has been labelled ‘resource curse’. Recently, the issue has remerged in a significant way. This began with the World Bank’s Extractive Industry Review (World Bank, 2004), growing reputational concerns from major international petroleum and mineral companies and fears by financiers of such projects regarding project risk. This revival of interest has been reinforced as a number of new countries embark on expanding extractive industry production and thus face the threat of an attack of ‘resource curse’. The rise in oil, gas and mineral prices in the last ten years – the upturn of the so-called ‘super cycle’ – also meant a number of countries who previously thought that they had controlled the potential for an attack of ‘resource curse’ had to think again.

THE ARGUMENT FOR STAGED DEVELOPMENT Much has been written about the causes and cures of ‘resource curse’ (Stevens, 2003, 2005; Van der Ploeg, 2010; Ross, 2012). One way to reduce the risk of suffering a negative impact is to slow the development of the project by implementing it in discrete stages over a longer time than is currently the norm for such projects. Slower development offers a number of advantages for both governments and for companies. For governments, slower project development slows the revenue inflow.1 This brings a number of benefits. It helps prevent the economy ­overheating 288

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The economic case for staged development  ­289 causing inflation and a possible exchange rate appreciation leading to an attack of Dutch disease. It may constrain the extractive industry project from crowding out other sectors of the economy from access to factor inputs. By constraining popular expectations, slower revenue inflows can help mute pressures on government to spend on projects which may be unnecessary, unwise or simply too large for the economy to digest. Smaller revenue inflows spread over a longer time can also make the ‘pot’ seem less worth fighting for (a variation on money illusion) which can help reduce the domestic conflict often exacerbated by such projects (Collier and Hoeffler, 2004). Slowing the revenue inflow also gives more time for the government to develop the policymaking capacity which is a necessary condition to create a ‘developmental state’ which is a key element to reduce the potential for an attack of ‘resource curse’ (Mkandawire, 2001; Stevens, 2005). Finally, from the government’s perspective, slowing development gives a chance for the development of a local service industry capability. This would help to maximize the backward linkages from the project to the local economy thereby assisting with the process of diversification (Hallwood, 1990). From the company perspective, there are also advantages to developing the project in stages thereby slowing development. It reduces the risk of the country suffering ‘resource curse’. Increasingly, it is likely that if a host country suffers such a ‘curse’, the operating company will attract criticism from NGOs and ethical investors, which will damage corporate reputation. An analogy lies in the concept of ownership externalities. Thus the business unit implementing the project sees only its private costs and benefits while reputation damage is effectively a cost to the corporate headquarters. To best allocate corporate resources, these externalities need to be internalized in terms of the capital budgeting decision by the headquarters. Furthermore, if an attack of ‘resource curse’ affects the project by encouraging internal conflict, it risks the viability of the project, which in turn could increase the cost of capital. Staging the project could also reduce the risk of the company’s vulnerability to the ‘obsolescing bargain’. This is where the government squeezes ever more rent out of the project by unilaterally manipulating the fiscal terms (Vernon, 1971). Since investment in the next stage of the project is conditional upon achieving required returns on the previous stage, staging the project would give the company more leverage than if all costs are sunk quickly. A staged approach also allows the company to retain leverage over government behaviour with respect to oil revenue management. Before the project operates, often the World Bank and the IMF have significant leverage over governments. They go to great efforts to put in place policy instruments to assist sound revenue management. However,

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290   Handbook of energy politics once the revenue begins to flow, that leverage diminishes accordingly.2 The only alternative source of pressure to ensure good governance lies with the companies to threaten no further investment although the implication of interference in sovereign behaviour is clearly controversial.3 It also raises issues as to the contractual nature of the project, such as, would a refusal to move to the next stage of the project threaten the contractual relations between government and company? Finally, if a slower approach does encourage the development of a local service industry, this would reduce the cost of the project’s factor inputs. However, while these arguments for a staged development are compelling for the company, in terms of conventional commercial analysis common in most large corporations, slowing the development of a petroleum or mineral project is serious heresy. This is for two reasons. Often the project requires associated investment in infrastructure – for example an oilfield requiring an export pipeline. This must be built at a minimum size which, given economies of scale, is often quite large (McLellan, 1992). The very high fixed costs involved require maximum capacity utilization. Otherwise, average fixed costs rise exponentially. Thus, while the infrastructure operates below capacity as it is slowly filled up, this might cause damage to the project’s profitability. Second, and probably more significantly, any delay in production reduces the net present value of the project as the discount rate bites into the value of revenues expected even further into the future. For these reasons, if companies are even to consider the option of staged development thereby slowing the project, a business case to do so must be developed to supplement the arguments already outlined.

THE BUSINESS CASE FOR STAGED DEVELOPMENT There may be clear economic and financial incentives to the company to develop the project in stages thereby slowing the development. Strategic planning procedures that increase the length of time available to develop projects, and/or develop projects in stages are likely to improve the ‘finances’ (net present value) of specific energy projects, and in most cases, reduce a portion of the risks presented by political and legislative uncertainty, and volatility in energy prices. The basic intuition behind this result is that uncertainty creates value. According to standard economic textbooks this is a proposition that tends to be true for all producers facing a variable production price. As a general rule, a firm’s average profits will be higher when the firm faces a variable price rather than a constant, or stable price. Given diminishing marginal returns to scale, a company will tend to make more money by producing

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The economic case for staged development  ­291 more when the price is high, and less when the price is low, than it will by producing a constant quantity at the average of the two prices (Varian, 1978). A slightly more sophisticated interpretation of the proposition that ‘uncertainty creates value’ occurs in cases where a project operator has the real option to develop investment opportunities in stages. By biding their time between the various stages, and waiting until more information is available, a firm will be able to make investment decisions that are ‘more informed’, and better suited to the economic and political situation that are likely to prevail throughout the project’s lifetime. Indeed, energy literature has long emphasized the value of using the theory of irreversible investment under uncertainty (Dixit and Pindyck, 1994) to quantify the ‘option-like’ characteristics of large-scale energy projects (Tourinho, 1979; Brennan and Schwartz, 1985; Dias and Rocha, 1999; Dias, 2001). To summarize the basic concepts, traditional Discounted Cash Flow (DCF) and Net Present Value (NPV) models tend to view large-scale projects as now-or-never investment opportunities. The entire capital investment is committed up front, often in the first year, and the project is evaluated by simply adding up the discounted net present value of future revenue streams (or cash flows). Its precision in cases where payoffs are non-linear and asymmetrical – such as real options and financial derivatives – is strictly limited. The breakthrough to the valuation of options and derivatives by non-linear models and methodologies was made in the early 1970s (Black and Scholes, 1973; Merton, 1973; Cox et al., 1979). A project is said to have real options value when; 1. it incorporates financial, and political uncertainty, and 2. the management team has the ability to delay decisions, and actions to a future date and can respond to changes in the business environment. With this more flexible, real options approach, investment opportunities can be seen, and valued, as a series of contingent investment decisions (Sick, 1990; Trigeorgis, 1995, 1996). In short, the decision to complete an investment programme can be made in stages, gradually, as more information becomes available to the project operator. The simplest examples of contingent investment decisions are pilot projects, where large capital investments are delayed, pending the successful outcome of smaller test projects. A more complex example would involve a firm’s making a series of small investments in a project with plans to expand production facilities in the event that key political and economic uncertainties are resolved in a manner that is favourable to the project operator. Trigeorgis (1996), Kulatilaka and Marcus (1992) and Kulatilaka (1995) utilize real options valuation methods to illustrate the fact that traditional DCF methods tend to undervalue the projects. Their thesis, that these

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292   Handbook of energy politics methods fail to provide a value for the real options that are embedded in large-scale investment projects, is well documented. Dapena (2002, 2003) uses a simple simulation model to illustrate the fact that there may be some cases where DCF tends to overvalue project economics. Technology and globalization create significant opportunities for growth and expansion, but at the same time require considerable injections of capital. These payments can be viewed as a series of call options on future growth, which, as discussed earlier, cannot be valued adequately by traditional DCF methods.

THE MODEL This study utilizes a standard Cox-Rubinstein Model (1985) to illustrate the advantages to staged – or slower – development in the upstream petroleum industry. Assuming that the price of oil follows a binomial process, let T equal the option’s time to maturity or expiration. The time to maturity is divided into N small intervals of equal duration t, so that T = Nt. The oil price can move in one of two directions, up from S to uS with probability q, or downwards from S to dS, with probability (1 – q). The values of q, u and d are functions of the mean, variance and rate of return on the price of oil (asset price) S. Specifically, in a risk-neutral world, these values will satisfy the following relationships:

u 5 es "Dt

(13.1)



d 5 e2s"Dt

(13.2)



a 5 erDt

(13.3)



q5a

a2d b u2d

(13.4)

The binomial process for the world oil price is illustrated in Figure 13.1. The actual value of the oil price S is observed at time t. At some point in the future – say t + t – the oil price can take on two different values – Su with probability q, or Sd with probability (1 – q). One time period later, the oil price has three different values: Su2 with probability q2; S with ­probability q(1 – q); or Sd2 with probability d2. As mentioned earlier, when a real options approach is utilized, investment opportunities in the upstream petroleum industry can be seen, and valued, as a series of contingent investment decisions. With a small investment in ‘project negotiations’4 the project operator has a real option

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The economic case for staged development  ­293 Oil Price Su2 Su S

S Sd

t

Sd2

t+∆t

t+2∆t

T

Figure 13.1  World oil price over time to delay actual investment decisions for a significant time period. Given current levels of volatility in the crude oil price – and forward curve – and political and legislative uncertainty in the host country, there is a significant probability that the project will come ‘into the money’ at some time in the future. In short, the project operator has an implied call option on a future capital investment. The value of this ‘implied’ call option can be calculated by standard options pricing procedures. Given the fact that the world oil price is assumed to follow a binomial process, the terminal value of a call option on the world oil price at time t+t, which matures at time t, is:

i. Cu 5 max [ 0, Su 2K ] , with probability q, and



ii. Cd 5 max [ 0, Sd 2 K ] , with probability (1 – q)

where K is the excise or strike price of the option. The actual value of the call option (CT) at time T is the maximum of the option’s intrinsic value or zero:

CT 5 max [ 0, ST 2K ] 

(13.5)

In a risk-neutral world, the value of an option is equal to the expected value of that option discounted at a risk-free rate of interest for the period under investigation (Briys et al., 1998).

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294   Handbook of energy politics

Ci, j 5 e2rDt [ q Si11, j11 1 (12 q) Si11, j ]



4i [ [ 0, N 21 ] , j [ [ 0, i ] 

(13.6)

In the case of an American call option, the project operator can call the option in at anytime between the settlement date and the exercise date, so that the firm does not suffer from losses that may arise from the restriction to call the option at the expiry date. As a result, the price of an American option must be equal too, or greater than, the intrinsic value of the option at any given time. This amounts to another restriction on the options price. The value of an American call option on the world oil price at time t+it, which matures at time it, is given by:

Ci, j 5 max [ Su j d i2j 2 K, e2rDt [ qSi11, j11 1 (1 2 q) Si11, j ] ] 



4i [ [ 0, N 21 ] , j [ [ 0,i ] 

(13.7)

The price of an American call option on the world oil price can be written as an implicit function of the following variables:

Ci,j 5 f (S,K,T,u,d,q,r,N) 

(13.8)

As there is no cash dividend involved in the transaction, the expression on the left of the maximum –Su j d i2j 2 K 2 will never come into play, and the price of the American call option will always be equal to e2rDt [ qSi11, j11 1 (12 q) Si11, j ] .

A SIMPLE NUMERICAL EXAMPLE Consider a firm that is considering the development of a small 200,000 b/d oilfield. The project requires an initial investment of $20 million per day, and will generate an initial flow rate of 200,000 b/d flow with a natural annual decline rate of 10 per cent throughout the 15-year forecast period. Prices for future production can be locked in on the forward curve when the final investment decision is made. The potential for enhanced oil recovery techniques has been ignored for ease of analysis. Given the forward curve for light sweet crude on the NYMEX (09/26/13 high-low average), crude oil production costs of $35.88 per barrel (Mackenzie, 2012), and a 15 per cent discount rate, the project has a net present value (NPV) of −$1,816, 335.98. The NPV of the cash flows alone, not considering the initial capital investment, is $28.6 million.

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The economic case for staged development  ­295 A company with a typical 15 per cent project threshold rate, blindly following the standard procedures for discounted cash flow analysis would choose not to develop the oilfield.5 As mentioned earlier, with a small investment in ‘project negotiations’ the project operator has a real option to delay the investment decision for a significant time period. Given current levels of volatility in the crude oil price – and forward curve – there is a significant probability that the project will come ‘into the money’ at some time in the future. In short, the project operator has an implied call option on a future capital investment with a NPV of cash flows of $28.6 million. The value of this ‘implied’ call option can be calculated by standard options pricing procedures, and depends on the volatility of crude oil prices, and length of time that the project can be delayed.6 Given the values for the independent variables in Ci,j 5 f (S,K,T,u,d,q,r,N) , equation 13.7 can be used to calculate the value of an American call option for the hypothetical crude oil investment project. The variables may be defined as follows. Let: Cij S

; ;

K

;

T

;

u, d, q r

; ;

N

;

The value of the Real Option to develop the oilfield. The Net Present Value of Cash Inflows – that is, the NPV of the future revenue stream of the oilfield. The strike (or exercise) price for the real option. Essentially the future capital investment in the oilfield. Expiry date, the length of time until the investment must be made. Parameters describing the volatility underlying the asset. The risk-free interest rate. The rate of return on US Treasury Bills. The number of small intervals t– that is, a variable describing the length of time between the settlement or value date (now) and the expiry date.

Figure 13.2 illustrates the relationship between the value of the ‘real option’ to develop the oilfield, the volatility of crude oil prices, and the length of time that the project can be delayed.7 Clearly, the value of the real option to develop the oilfield will increase with the volatility of crude oil prices, and the length of time that the project can be delayed. Given current levels of volatility in crude oil prices,8 and a one-year delay window, the value of the real option to develop the oilfield is worth $2.2 million. That is to say, the project operator would be willing to pay up to $2.2 million in ‘project negotiation’ costs, in order to secure the right to

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296   Handbook of energy politics Table 13.1  Discounted cash flow analysis 2014

2015

2016

Gross Revenue $96.97 $87.93 $84.21 Oil Price 200,000 180,967 148,164 Production Barrels/ $19,393,263.16 $15,912,729.36 $12,476,860.47   Day Total Revenue Project Costs $35.88 $35.88 $35.88 Marginal $7,176,000.00 $6,493,113.31 $5,316,111.55   Production Costs $35,000,000.00 Total Costs Initial Investment Gross Profit −$22,782,736.84 $9,419,616.05 $7,160,748.92 Profit −$1,816,335.98 Net Present Value Total Cash Flows $12,217,263.16 $9,419,616.05 $7,160,748.92 NPV Cash Flows $28,618,446.63

2017

2018

$82.38 $81.80 109,762 73,576 $9,042,220.52 $6,018,507.66

$35.88 $35.88 $3,938,272.30 $2,639,902.87

$5,103,948.22

$3,378,604.79

$5,103,948.22

$3,378,604.79

The Value of a Real Option

$14,000,000.00 $12,000,000.00 $10,000,000.00 $8,000,000.00 $6,000,000.00 $4,000,000.00 $2,000,000.00 $0.00

1

2

Volatility = 0.2

3 Year to Excercise Volatility = 0.4

4

5 Volatility = 0.8

Figure 13.2  The real options value of a hypothetical oil investment develop the oilfield at some point in the next 12 months. The value of the real option increases significantly, to $4.8 million when the project can be delayed for up to two years. It is important to notice the fact that the results depend to some extent on the stochastic process that is chosen to model crude oil prices.

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The economic case for staged development  ­297

2019

2022

2023

2024

2025

$80.87 $80.87 $80.87 44,626 24,491 12,162 $3,608,907.21 $1,980,610.27 $983,541.95

2020

2021

$80.87 5,465 $441,933.89

$80.87 2,222 $179,676.91

$80.87 817 $66,099.44

$80.87 272 $22,002.59

$35.88 $35.88 $1,601,182.03 $878,747.33

$35.88 $436,373.01

$35.88 $196,075.03

$35.88 $79,718.16

$35.88 $29,326.67

$35.88 $9,762.00

$2,007,725.18 $1,101,862.94 $547,168.94

$245,858.85

$99,958.75

$36,772.77

$12,240.59

$2,007,725.18 $1,101,862.94 $547,168.94

$245,858.85

$99,958.75

$36,772.77

$12,240.59

Specifically, Abazi (2003) points out the fact that the mean reversion process is not suitable for the basic measurement equation as crude oil prices follow a unit root process. Instead, Abazi models prices as following the basic geometric Brownian motion, without mean reversion, while the stochastic volatility is assumed to follow a mean reversion process. As a general rule, geometric Brownian motion models tend to outperform the mean-reversion (Abazi, 2003). An extension of these results to the geometric Brownian motion dynamics, and the Black-Scholes option pricing model is straightforward, and will not be presented here.

PRINCIPALS, AGENTS AND GOOD GOVERNANCE: PROVIDING THE OPTIMAL INCENTIVE SCHEME While real options theory suggests that the firm has an incentive to develop a large-scale investment project in stages, there is no guarantee that simply slowing down the investment timetable will provide the right incentives for the government of the host country to eliminate actions leading to the ‘resource curse.’ This section utilizes a principal–agent framework to investigate the possibility of finding an optimal allocation of investment funds, thereby providing the appropriate incentive schemes for the agent countries. Principal–agent models are widely recognized for their ability to provide equitable and efficient incentive schemes in situations where the decisionmakers (agents) have different goals and objectives than the economic actors that are affected by the decisions (principals). The models have

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298   Handbook of energy politics been applied to a vast array of problems, and incentive schemes ranging from simple labour, and wage compensation schemes, to corporate and national and even supranational governance. In the case of national governments, and democratic institutions: ‘A fair governance implies that those mechanisms are organized in a way allowing that the rights and interests of the stakeholders (the “principals”) are respected by the executives (the “agents”), in a spirit of democracy.’9 This concept has been extended to explain and model variations in the delegation and compliance of principals and agents in the European Union (Tallberg, 2003; Pollack, 1997, 2003; Franchino, 2001; Thatcher and Stone Sweet, 2002). In the case of the global upstream petroleum industry, there is considerable competition for capital funds for large-scale investment funds.10 The level of international competition – and the large size of rewards to successful exploration and development efforts – lend themselves particularly well to tournament compensation schemes. Specifically, to those compensation schemes where monetary incentives (investment funds) are based on the rank order of a country’s performance, rather than its absolute performance level. In a rank-order tournament, the rewards are not based on the output level of a particular project or development, because the prizes are fixed in advance. Instead, the incentives are determined by the agent’s attempts to win the tournament, or contest for investment funds. The best, most efficient and successful countries will receive the bulk of the capital investment. For example, it is no coincidence that much of the upstream investment by the international oil companies is in the OECD countries despite the lure of promising geology elsewhere. In the case of the crude oil industry, the monitoring costs are so high that moral hazard (resource curse) has become a serious problem. The gains in efficiency that usually accompany an incentive structure based on production may easily be overridden by the losses accruing to moral hazard, corruption and resource curse. In light of these considerations, this section extends the principal–agent model of rank-order tournaments (Lazear and Rosen, 1981) to the problem of the resource curse.

THE BASIC RANK-ORDER TOURNAMENT MODEL A large multinational oil company, the principal, is seeking to sponsor a large-scale investment project in two developing countries – the agents. All players are assumed to be risk neutral, and the agents are assumed to be identical in every aspect of their political and legislative structure, and

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The economic case for staged development  ­299 preferences. To simplify the analysis the problem is confined to a single period. The agents, i = 1 and 2, are engaged in the exploration, and production of crude oil, and are expected to provide a positive effort ai towards this objective in a given time period. That is, the principal expects ai [ [ 0,` ] . As the principal cannot observe all of the actions taken by the agent, and a number random factors can have a significant influence the exploration and development process, the agents production functions (crude oil supply curves) take the following form:

xi 5 ai 1 ei , 4ei [ (2`,1`) 

(13.9)

where: ei ;  the random factors affecting the crude oil production process ei , iid (0,s) . The agent controls the mean of the distribution ai by investing in the physical infrastructure of the project, and the political and legislative ­environment – institutions – within which the project must be completed. The cost of investing in the positive effort ai is f(ai). The random factors affecting the oil production process can be viewed as a ‘luck’ factor, and can represent the underlying geological and political uncertainty, and a host of other random shocks to the production process. The process is assumed to be independently and identically distributed for all agents, so that the principal can diversify risk by actively engaging a portfolio of agents. The competitive tournament model assumes that the level of crude oil production x1 and x2 can be observed by both of the agents and the principal. In fact, the values x1 and x2 can be taken as the principal’s subjective assessment of the agents’ production levels. While these values can be observed by all the participants, they cannot be verified by an impartial third party – such as a court of law, or international arbitration institution. Assuming that the agent is paid a piece rate (w) – according to ­production – the agent’s expected returns to the production of crude oil are wa – f(a). A risk neutral agent will choose the level of effort a that maximizes his expected return.

max E [ wx 2 f (a) ] 5 wa2f (a) F.O.C.  w 5 f r(a)

(13.10)

The agent will choose the level of effort that equates the marginal returns to investment to the marginal production level.

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300   Handbook of energy politics Let the price of crude oil production be defined by (P). Assuming a competitive market for crude oil production, the principal’s expected profit function may be given by: Finally:

max E [ Px 2wx ] 5 (P 2w) a F.O.C.  P 5w

(13.11)

P 5 f r(a) 

(13.12)

The workers will choose a level of effort where the marginal cost of investment in effort (a) is equal to its marginal value to society (P). The piece rate solution is socially efficient. In a two-player rank-order tournament, the principal awards a fixed prize I1 to the winner, and I2 to the loser. The agents gain utility from investment income (Ii) and disutility from effort (ai) according to the following utility function: U (Ii ,ai ) 5 Ii 2 f (ai ) 



(13.13)

Assuming that each agent has an identical cost of investing in the positive effort a, f(a), and q = the probability that an agent will win the contest, then the agents expected utility is given by:

E (U ) 5 q [ I1 2 f (a) ] 1 (1 1 q) [ I2 2 f (a) ]  5 qI1 1 (12 q) I2 2 f (a)

(13.14)

An agent will win the tournament if their observed level of output (x) is greater than their opponents, or equivalently: q 5 prob (x1 . x2) 5 prob (a1 1 e1 . a2 1 e2) 5 prob (a1 2 a2 . h)         5 H (a1 2 a2)

(13.15)

In this example, h , f (h) , H( ) is the cumulative probability function of h. The agent’s problem (ai, i = 1,2) is to choose the level of effort a that will maximize his expected utility.

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The economic case for staged development  ­301 maxa E (U) 5 q (ai) I1 1 (1 2 q (ai)) I2 2 f (ai) i

F.O.C.

0 5 (I1 2 I2) S.O.C. 0 . (I1 2 I2)

0q 2 fr (ai) 0ai



(13.16)

0 2q 2 f rr (ai)   0a2i

Assuming a Cournot-Nash framework, neither agent has the ability to influence the others actions, or the market. The agents will maximize their expected utility assuming that the optimal level of effort a for the other agent, has already been determined. For agent #1:

0H (a12a2) 0q 5 5 h (a1 2a2)  0a1 0a1

(13.17)

0H (a2 2a1) 0q 5 5 h (a2 2a1)  0a2 0a2

(13.18)

For agent #2:

Substituting these results into the first order condition (13.16), gives the following reaction functions for agents #1 and #2.

0 5 [ I1 2I2 ] h (a1 2 a2 ) 2 f r (a1) and  0 5 [ I1 2 I2 ] h (a2 2 a2 ) 2 f r (a2)

(13.19)

The agents’ reaction functions are symmetric. In other words, if a Nash solution exists then a1 5 a2 , and the probability of winning (q) is equal to H(0) =1/2.

h (0) [ I1 2 I2 ] 5 f r(ai) ; 4i 5 1,2

(13.20)

The rank tournament will be successful, in as much as each agent will be given the incentive to attempt to improve his probability of winning by investing in the physical infrastructure of the project, and the political and legislative environment – institutions – within which the project must be completed. The level of investment will depend on the bonus for winning, or the spread between amount of winning (and losing) investment funds.

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302   Handbook of energy politics The principal can expect to earn gross revenues of:

Gross Revenue 5 P (x1 1 x2 ) 2 [ I1 1I2 ] 

(13.21)

In a Nash equilibrium, and competitive market, the principal will be willing to bid for agents up to the point where expected profits are equal to zero: [ I1 1 I2 ] 5 E (x1 1x2) P [ I1 1 I2 ] 5 (a1 1 a2 ) P  [ I1 1 I2 ] 5 Pa 2



(13.22)

Since the probability of winning is exactly half in equilibrium, the agents expected utility is equal to:

E (U ) 5 q ( ai ) I1 1 (12 q (ai )) I2 2 f (ai) 5 Pa 2 f (a)



(13.23)

In equilibrium, the prize structure will be chosen to maximize equation (13.23): maxI

i 5 1, 2

Pa 2 f (a)

 0a [ P 2 f r (a) ] 5 0 0Ii

F.O.C.

(13.24)

Once again, the agents will choose a level of effort where the marginal cost of investment in effort (a) is equal to its marginal value to society (P). The rank tournament solution yields an allocation of resources that is socially efficient.

WHO’S WATCHING THE REGULATORS? There are clear benefits to both governments and companies from staging and thereby slowing the development of extractive industry projects if there is a threat of ‘resource curse’. However, conventional project appraisal techniques argue slower development undermines the financial viability of the project. This chapter has tried to show that by using option theory, slowing the project can be justified in financial terms. Thus, a business case can be made for slowing development in addition to the arguments that slower development will reduce the risk of an attack of ‘resource curse’.

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The economic case for staged development  ­303 At the same time, the intense level of competition for capital funds for large-scale investment in the oil industry, provides regulators and major oil companies with a unique opportunity to devise a payment incentive scheme that can minimize behaviour and patterns leading to ‘resource curse’. As mentioned earlier, the level of international competition – and the large size of rewards to successful exploration and development efforts – lend themselves particularly well to tournament compensation schemes. Specifically, to those compensation schemes where monetary incentives (investment funds) are based on the rank order of a firm’s performance, rather that an absolute performance level. Specifically, organizations like the World Bank, and major oil companies alike can take a number of measures to reduce the costs of resource curse in developing nations. A company, or multilateral lending operation can invest in stages – thereby simultaneously optimizing the real options value of large exploration and development projects. Large-scale investments can be viewed as ‘prizes’ or ‘rewards’ in a rank order tournament, and staggered according to production results among competitive companies. In this case, disparities between producing basins have to potential to skew the results in favour of those nations with young, or prolific oilfields. The playing field can be levelled by grouping producers into ‘like’ producing basins, with similar characteristics, and restricting investment rewards to specific groups. Finally, the rewards might be granted in an unbiased manner on the basis or ‘merit’ or effort, and success. Dual problems of corruption and resource curse are unlikely to survive an optimal, unbiased long-term incentive scheme. Companies and nation states, who are likely to invest in any prospect – regardless of the state of corruption – might easily be persuaded to base their investment on the final outcome, oil production, among like ‘producing basins’.

NOTES   1. An obvious alternative method of slowing the revenue flow without slowing the project development is by use of an oil fund. However, the effectiveness of this solution is highly controversial (Davis et al., 2001; Devlin and Lewin, 2002; Fasano, 2000; Stevens and Mitchell, 2008) not least because it means the revenue is somewhere ‘available’ if the government changes its mind regarding responsible revenue management.   2. The classic example of this is what happened with the Chad–Cameroon oil project.   3. It also raises the question as to whether other companies, less concerned about host government behaviour might not step in to fill the gap.   4. These might include simply sitting on a well-defined development opportunity, purchasing or renting property, negotiating a lease with a foreign government or initiating negotiations with a major oil company.   5. The standard procedures for discounted cash flow analysis suggest that a project ­operator will invest in the project if and only if the NPV of cash flows minus the

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304   Handbook of energy politics

  6.   7.

  8.   9. 10.

initial capital investment is greater than zero at a given ‘hurdle’ discount rate (15 per cent). The options prices in this analysis were calculated using the standard Cox-Rubinstein Binomial Model for American options (Cox et al., 1979). The term volatility refers to the annualized standard deviation of the rate of change of historical crude oil prices over a period of time. In general, a higher level of volatility is represented by a higher numerical value, so that an estimated volatility of 0.8 is considerably higher than an estimated volatility of 0.2. For the purpose of this analysis the volatility was estimated for daily spot WTI crude oil prices over a number of years. To cite only one example: The volatility of WTI was estimated at approximately 0.40 using historical data from January 1986 to 23 September 2013 (US EIA, 2013). Business Dictionary (2004) ‘Definition of governance’, July, http://www.businessdic​ tionary.com/definition/governance.html, accessed 11 December 2017. While this has been the case for a number of years, a resurgence of ‘resource nationalism’ could undermine this assumption.

REFERENCES Abazi, A. (2003) ‘Stochastic volatility in the crude oil prices: A Markov chain Monte Carlo approach’, Paper presented at the VIII Meeting of Young Economists, Catholic University of Leuven, Belgium, 3–5 April. Black, F. and M. Scholes (1973), ‘The pricing of options and corporate liabilities’, Journal of Political Economy 81, 637–59. Brennan, M. and E. Schwartz (1985) ‘Evaluating natural resources investments’, Journal of Business 58, 135–57. Briys, E., M. Bellalah, H.M. Mai and F. de Varenne (1998) Options, Futures and Exotic Derivatives: Theory Application and Practice, New York: John Wiley & Sons. Collier, P and A. Hoeffler (2004) ‘Greed and grievance in civil war’, Oxford Economic Papers, 56, 563–95. Cox, J., S. Ross and M. Rubinstein (1979) ‘Options pricing: A simplified approach’, Journal of Financial Economics 7 (3), 229–36. Cox, J. and M. Rubinstein (1985) Options Markets, New York: Prentice Hall. Dapena, J. (April 2002), ‘On the property of real options and the assets that give rise to them’, Elektronische Ressource, Serie documentos de trabajo / Universidad del CEMA, Buenos Aires, Vol. 210. Dapena, J. (2003) ‘On the valuation of companies with growth opportunities’, Journal of Applied Economics, VI (1), May, 49–72. Davis, J., R. Ossowski, J. Daniel and S. Barnett (2001) ‘Stabilization and savings funds for non-renewable resources’, Occasional paper 205. Washington, DC: International Monetary Fund. Devlin, J. and M. Lewin (2002) ‘Issues in oil revenue management’, Paper to the World Bank/ESMAP Workshop in Petroleum Revenue Management. Washington, DC, 23–24 October. Dias, M.A.G. and K. Rocha (1999) ‘Petroleum concessions with extendible options: Investment timing and value using mean reversion with jumps to model oil prices’, Working Paper, Petrobras and IPEA, available at http://www.puc-rio.br/marco.ind/ extend.html, accessed 15 August 2016. Dias, M.A.G. (2001) ‘Valuation of exploration and production assets: An overview of real options models’, Journal of Petroleum Science and Engineering, 44 (1–2), 93–144. Dixit, A.K. and R.S. Pindyck (1994) Investment Under Uncertainty, Princeton, NJ: Princeton University Press. Fasano, U. (2000) ‘Review of the experience with oil stabilization and savings funds in

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The economic case for staged development  ­305 selected countries’, IMF Working Paper WP/00/112. Washington, DC: International Monetary Fund. Franchino, F. (2001) ‘Delegation and constraints in the national execution of EC policies’, West European Politics, 24 (4), 169–92. Hallwood, C.P. (1990) Transactions Costs and Trade Between Multinational Corporations: A Study of Offshore Oil Production, Boston: Unwin Hyman. Kulatilaka, N. (1995) ‘The value of flexibility: A model of real options’, in L. Trigeorgis (ed.) Real Options in Capital Investment, Westport, CT: Praeger. Kulatilaka, N. and A. Marcus (1992) ‘Project valuation under uncertainty: When does DCF fail?’ Journal of Applied Corporate Finance, 5 (3), 92–100. Lazear, E. and S. Rosen (1981) ‘Rank-order tournaments as optimum labor contracts’, Journal of Political Economy, 89, 841–64. Mackenzie, K. (2012) ‘Marginal oil production costs are heading towards $100/barrel’, Financial Times, 2 May. McLellan, B. (1992) ‘Transporting oil and gas – The background to the economist’, Oil and Gas Finance and Accounting, 7 (2), Summer. Merton, R.C. (1973) ‘Theory of rational option pricing’, Bell Journal of Economics and Management Science 4 (1), 141–83. Mkandawire, T. (2001) ‘Thinking about developmental states in Africa’, Cambridge Journal of Economics, 25 (3), 289–313. Pollack, M. (1997) ‘Delegation, agency and agenda setting in the European Community’, International Organisation, 51 (1), 99–134. Pollack, M.A. (2003) The Engines of European Integration: Delegation, Agency, and Agenda-Setting in the EU, Oxford: Oxford University Press. Ross, M. (2012) The Oil Curse: How Petroleum Wealth Shapes the Development of Nations, Princeton and Oxford: Princeton University Press. Rosser, A. (2006) ‘The political economy of the resource curse. A literature survey’, Working Paper 268, Institute of Development Studies (IDS), Centre for the Future State. Sick, G. (1990) Capital Budgeting with Real Options, New York: Salomon Brothers Center for the Study of Financial Institutions, Stern School of Business, New York University. Stevens, P. (2003) ‘Resource impact: Curse or blessing? A literature survey’, Journal of Energy Literature, IX (1), 3–42. Stevens, P. (2005) ‘Resource curse and how to avoid it’, Journal of Energy and Development, 31 (1), 1–20. Stevens, P. and J.V. Mitchell (2008) ‘Resource depletion, dependence and development: Can theory help?’ Programme Paper, June, London: Chatham House. Tallberg, J. (2003) ‘The agenda-shaping powers of the EU council presidency’, Journal of European Public Policy, 10 (1), 1–19. Thatcher, M. and A. Stone Sweet (2002) ‘Delegation to non-majoritarian institutions’, West European Politics, 25 (1), 1–22. Tourinho, O. (1979) ‘The option value of reserves of natural resources’, Doctoral Dissertation, University of California at Berkeley. Trigeorgis, L. (ed.) (1995) Real Options in Capital Investment, Westport, CT: Praeger Publishers. Trigeorgis, L. (1996) Real Options: Managerial Flexibility and Strategy in Resource Allocation, Cambridge, MA: MIT Press. US EIA (Energy Information Administration) (2013) ‘Weekly petroleum status report’, 23 September, available at https://www.eia.gov/petroleum/supply/weekly, accessed 15 August 2016. Van der Ploeg, F. (2010) ‘Natural resources: Curse or blessing?’ OxCarre Research Paper 5, University of Oxford. Revised 13 June. Varian, H.R. (1978) Microeconomic Analysis, Second Edition, New York: W.W. Norton and Company Inc.

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306   Handbook of energy politics Vernon, R. (1971) Sovereignty at Bay: The Multinational Spread of US Enterprises, New York: Basic Books. World Bank (2004) ‘Striking a better balance: Extractive industry review reports’, available at http://web.worldbank.org/WBSITE/EXTERNAL/TOPICS/EXTOGMC/0,,contentM DK:20306686~menuPK:336936~pagePK:148956~piPK:216618~theSitePK:336930,00. html, accessed 15 August 2016.

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PART IV THE EVOLUTION OF TECHNOLOGY, CAPITAL AND FINANCIAL MARKETS IN THE ENERGY INDUSTRY

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14.  Deepening green finance1 Hazel Henderson

The global transition away from fossil fuels is already unstoppable (Figure 14.1). Yet while 195 nations had agreed on their UN Sustainable Development Goals (SDGs) and ratified the Paris Accords in 1995, mainstream financial markets had become global laggards. As reported by Peter Coy in Business Week, April 2017, thousands of new indexes, ETF and smart-beta funds compete for investors with ever more exotic “factors” they sell as leading to outperformance.2 Yet they still miss the biggest global trend: to low-carbon renewable-resourced, efficient circular economies. Meanwhile, a GlobeScan Survey of 500 experts assesses global progress toward meeting the UN’s 17 goals in the SDGs, finding that NGOs and social entrepreneurs have led the way.3 ANNUAL SOLAR IRRADIATION TO THE EARTH SOLAR (CONTINENTS) WIND BIOMASS GEOTHERMAL OCEAN & WAVE HYDRO COAL GAS OIL NUCLEAR

GLOBAL ANNUAL ENERGY CONSUMPTION

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FOSSIL FUELS ARE EXPRESSED WITH REGARD TO THEIR TOTAL RESERVES WHILE RENEWABLE ENERGIES TO THEIR YEARLY POTENTIAL

Solar irradiation versus established global energy resources Solar Generation 6, EPIA 2011

Figure 14.1  Annual solar irradiation to the Earth 309

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310   Handbook of energy politics By mid-2016, the Task Force on Climate-related Financial Disclosure (TCFD) co-chaired by Michael Bloomberg and Mark Carney, head of the Bank of England, reported that this lag in financial markets was creating a logjam to the expansion of green investing.4 Anxious asset managers, instead of re-tooling their models and portfolios, were risking another financial crisis as the value of the fossilized assets on their books continued to decline according to research by CDP and 2°Investing.5 Similarly, electric utilities were still dragging their heels in managing the increasing supplies of solar, wind and efficiency upgrades which were lowering demand. Instead of changing their traditional business models of demand management and slowing up their building of more central baseload generation, most fought rearguard actions. They still lobby state legislatures, fight their consumers over net-metering and continue mounting advertising campaigns and ballot initiatives to retain their dwindling markets. A turnaround by laggard Florida Power and Light in 2017 was their announced siting of for eight new solar projects, each adding 75.5 mw by December 2017.6 These battles continue, with energy consumers and businesses leaving grids and generating their own renewable energy. The world’s renewable energy potential is a vast 11,941 exajoules—more than enough for all future human needs, as estimated by REN21.7 On March 11, 2017 solargenerated electricity in California peaked in providing more than half of all supply for the entire state—briefly plunging wholesale energy prices into negative territory (see Figure 14.2). This cost-saving by millions with efficiency in lighting, heating, cooling and building upgrades continued through 2016 and accelerated in 2017. This massive shift to renewables driven by cost reductions, technological innovation, public awareness of climate risks and adoption by corporations of sustainability goals has now placed financial markets in the crosshairs, boxed in by these socio-technical trends. Today, the focus of business leaders, politicians, the private investors we track on Green Transition Scoreboard (GTS), as well as voters and consumers has shifted toward reforming financial markets and their obsolete textbook models.8 Finance was targeted first by socially responsible, ethical investors. Since the 1980s, mutual funds Calvert, Domini, Pax World, Parnassus and ever increasing fund offerings and asset managers have driven increasing trillions of investments as measured by the Social Investment Forum.9 As environmental pollution concerns (including CO2 and climate change) grew, financial markets were targeted on a second side,  by divestment movements such as 350.org. State and city pension funds led by New York City’s pension fund, CALPERS and TIAA-CREF began to respond joined by foundations in a shift to fossil-free portfolios.

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Deepening green finance  ­311 California Independent System Operator net generation, March 11, 2017 gigawatthours 30 25 20 15 10 5 0

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Figure 14.2 California independent system operator net generation, March 11, 2017 By 2015, finance became boxed in on a third side—from the top—by those 195 countries of the UN, and their 17 SDGs and their Intended Nationally Determined Contributions (INDCs) for phasing out fossil fuel subsidies and targeting other so-called “externalities” ignoring pollution, environmental and social costs on balance sheets of companies and government agencies. The new accounting standards are promulgated by IIRC, IRRC, SASB, CIMA, ICAEW, CDSB. The fourth side of the boxed-in financial sector came from below: where upstart innovations emerged from Silicon Valley. The FINTECH100 and increasing numbers of  electronic platforms for peer-to-peer ­lending— crowdfunding, local and cryptocurrencies—began bypassing legacy finance and traditional banking.10 For example, Kenya’s M-Pesa pioneered cellphone-based banking, now accounting for over 50 percent of its GDP—with other countries in Africa following suit.11 Pure informationbased trading—such as barter and swap sites, freecycling and secondhand goods—no longer requires any currency (see Figure 14.4), as all facilitate sharing and community exchange. This Internet-based revival of barter is not to  be confused with the hybrid “gig economy” of TaskRabbit, Mechanical Turk, Uber, Lyft, Airbnb and others highly prized by traditional Wall Street. Such winner-take-all Silicon Valley investors hype these “unicorn” companies, which are little more than part-time labor markets of desperate unemployed people (often displaced by digitization) as the

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312   Handbook of energy politics Boxed-in Financial Markets. Pressures On All Sides For Reform 196 Nations satisfy new model of SDGs, COP21, 22 and International National Development Commitments (INDCs)

Social impact, responsible investors, SRI, ESR, asset

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Activism, 350.org. Divesting Movements Public Demonstrations Driven Scientific Consensus on Carbon “Budget” Below 2˚C

Compact, IIRC, SASB, CIMA

Financial Innovation, FINTECH100, Startups, Electronic Platforms for Peer-2-Peer Lending, Crowdfunding, Local and Cryptocurrencies, Robo-Investing, Information-Based Trading, Barter, Swaps, Secondhand Markets, Cellphone Banking (e.g. M-Pesa) Electronic Remittances and Payment Systems.

Figure 14.3 Boxed-in financial markets: pressures from all sides for reform “sharing economy” critiqued by Douglas Rushkoff in Throwing Rocks at the Google Bus (2015).12 This digitization of ever more sectors of industrial societies has produced: 1. backlashes by civic groups and NGOs calling for guaranteed basic incomes for those replaced by robots and, 2. efforts by elites and central banks to institute similar universal basic income (UBI) schemes to provide purchasing power to those displaced by automation or austerity cuts. As rounds of quantitative easing (QE) became less effective, central

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Deepening green finance  ­313

Figure 14.4  Two main ways of transacting

banks resorted to negative interest rates which crushed savers and pension funds. As I reported in Forbes,13 these central banks then began embracing UBI schemes as economic stimulus so as to maintain aggregated demand. Clearly, the logic of the current economic growth model has broken down, as I described in “Ben Bernanke and Milton Friedman were right” (2016).14 The march of digitization and automation now has prompted even Bill Gates to call for taxing robots!15

THE RISE OF “IMPACT INVESTING” The contentious battles over jobs drove populist politics in the USA and Europe—scapegoating immigrants and focusing on trade deals, as well as automation. Fossil fuel jobs declined to less than 100,000 in the US, while more than 3 million work in clean energy16 and REN21 estimates 8.1 million worldwide. Thus, we explore herein the reforms now occurring in finance itself, now that it is boxed-in by all these global forces and trends. The task of redesigning financial models, new metrics—pioneered in the 1980s—is now producing many more of the actual paradigm shifts in investing that

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314   Handbook of energy politics are sorely needed. A spate of important books appeared over the past 20 years (see www.ethicalmarkets.com/books and reviews) formerly ignored by mainstream asset allocators. These books are finally producing the new models and platforms appearing under the recent rebranding and marketing rubric: “Impact Investing.” We highly recommend Sustainable Investing (2017) by pioneers Cary Krosinsky and Sophie Purdom, that includes many case studies.17 Many retail investors and especially family offices and their young millennial heirs, have been asking their asset managers to shift their portfolios toward clean, renewable companies, green infrastructure, green bonds and young “pure play,” privately held companies. Frequently, those using traditional asset managers, consultants or trustees are told that such new investments are “too risky”—overlooking the  facts that their fossil assets may be even more risky and become “stranded” and turning into liabilities! Trillions in pension funds, retirees’ 401Ks and philanthropic portfolios whose beneficiaries are most concerned with climate change and support the phasing out of fossil fuel, learn to their dismay the extent to which their nest eggs are still in the fossilized sectors. And many major oil companies are still over-investing in new reserves or in  shale oil and gas fracking operations, as reported by Carbon Tracker.18 Meanwhile Business Week reports on floods of money going into climate adaptation in many coastal cities.19 Michael Bloomberg and former Sierra Club executive Carl Pope outlined the bigger picture in Climate of Hope (2017).20 This recent rebranding of 20 years of socially responsible investing (SRI), ESG, “green” and “ethical” funds has broadened the tent, allowing mainstream firms like BlackRock, Goldman Sachs, Bank of America and others to claim the new territory of post-industrial, post-fossil fuels and sustainable investment opportunities. However, some of these investments may not achieve the financial return they promise since intractable global problems of inequality, education, social equality and health will always require traditional philanthropy, as Oxfam’s Mara Bolis points out.21

FORCES DRIVING THE GLOBAL GREEN TRANSITION The shift continues to post-carbon strategies and investments in long-term sustainability, also evident in most corporate planning, as reported by Schneider Electric in its “Global energy market trends” (2017) nearly 25 percent of the global Fortune 100 have defined renewable energy targets many seeking 100 percent long-term to improve their bottom lines.22 Business and political alliances are shifting across the old left-right spectrum. Current debates reveal at least two very different approaches to

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Deepening green finance  ­315 globalization, as I report to the American Sustainable Business Council.23 Firstly, the right-wing movements in the USA and European countries, and secondly, the grassroots globalists in the 195 countries who support the post-carbon, inclusive future envisioned in the UN’s SDGs; the green “glocalization”  movements following a “small is beautiful” agenda.24 These new movements from across the spectrum oppose the current dominant form of elite “Davos Man” globalization still driven by corporations, based on GDP-measured growth, deregulation, tax havens, “free” trade, privatization—all dominated by finance and traditional economic models of profit maximization. These new movements, reacting to the 2008 financial crises and bailout of the big banks, now see global finance as the dominant player driving rising inequality and environmental disruption. Many NGOs, including London-based Positive Money and the New Economics Foundation, the Public Banking Institute in the USA and many others elsewhere, focus on the politics of money creation, central banking and credit allocation, all seen as driven by policy rather than by an invisible hand of the market (see also our TV Special “The Money Fix” http://www.ethicalmarkets. com/watch-the-money-fix/). These populist waves opposing corporate financial globalization also identify the single focus on money (in whatever fiat currencies) as harming all other values of family, community, equality, social justice and environmental quality of life. This also fuels demands for full recognition of all six forms of capital: finance, built, intellectual, social, human and natural, thus benefiting not only stockholders but also all stakeholders in corporate governance.25

GREEN FINANCE EMERGING Investor and shareholder efforts have been reflected over the past 30 years in global initiatives, including the UN Environment Program’s UNEP-FI: the UN Principles of Responsible Investing (unpri.org): the UN Global Compact’s 10 Principles of Corporate Citizenship (globalcompact.org), as well as those from the banking sector, the Equator Principles, as well as many institutional asset managers’ groups on climate change, including the Carbon Trust, the Carbon Disclosure Project (CDP), the Climate Disclosure Standards Board (CDSB), the Social Investment Forum, the Sustainable Investment Forum, Climate Action, Forum for the Future, World Investment Forum, Sustainable Stock Exchanges, the Future 500, the World Business Council on Sustainable Development, Ceres, HELIO International, with its HIFI Index for investors in collaboration with Ethical Markets and the Global Impact Investing Network (GIIN).

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316   Handbook of energy politics The most direct challenge to conventional global finance came from the UNEP “Inquiry on design of a sustainable financial system” (www. unepinquiry.org), spearheaded with the United Nations Environment Program in 2013 by co-directors Simon Zadek, founder of the successful European-based firm AccountAbility, and former HSBC economist Nick Robins,26 who outlines the prospects for a greener future.27 By recruiting an influential advisory group of top central bankers, finance ministers and stock exchange heads from China, India, Indonesia, South Africa, Brazil and other large key economies, the UNEP Inquiry was empowered to confront traditional financial centers and their prevailing “Washington consensus” worldview and models. The inquiry’s initial two-year mandate is now extended, due to its successful engaging of high-level global opinionmakers and its groundbreaking series of reports outlining all aspect of the new “greening” of finance based on the UN’s 17 SDGs. Its many reports first focused on the paradigm shifts required beyond the GDP-growth driven economics based on maximizing money returns to  investors. Ethical Markets contributed reports on “Perspectives on reform of electronic markets and trading”(2014) and “FINTECH: Good and bad news for sustainable finance” (2016).28 In “Ending externalities: Full-spectrum accounting clarifies transition management” (2016), presented by coauthor Timothy Jack Nash at the OECD’s Green Growth Knowledge Platform, Korea in September 2016,29 we examined key aspects of the needed reforms. These are based on the new metrics covering all six forms of capital and the need to expose the fraudulent accounting practices still widespread, of “externalizing” social and environmental costs from corporate and government balance sheets. Financial Management, the journal of the Chartered Institute of Management Accountants covered this in its May–June 2016 issue on “Values” (see www.cimaglobal.com). The UNEP Inquiry, with its global reach, collated and documented all the progress toward greening financial markets, noting progress in Brazil, South Africa and other countries. China became a leader in this new green investing model, and its central bank cooperated in a major policy shift with the People’s Bank of China outlining Chinese plans in their 2015 paper.30 When China acceded to the presidency of the G20, its 2016 meeting in Hangzhou, China promoted this shift to green finance, now an official plank of the G20. The inquiry also teamed up with the Londonbased Climate Bonds Initiative and this helped in the spectacular growth of green bonds in many countries, as reported by founder and CEO Sean Kidney in 2017.31 Bank of England head Mark Carney in the TFCD report 2016 endorsed expansion of green bonds calling for official standardization and recognition of criteria for use of their proceeds, so as to deepen and widen this green segment of the global bond market.32 These included

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Deepening green finance  ­317 1. a term sheet standardizing these bonds, 2. definitional frameworks for validation of green projects, 3. integration into credit ratings, 4. green bond indexes and 5. harmonization of principles and standards for green bond listings. The herd behaviors of all markets can now be steered by such new standards to assure that the proceeds of all green bonds are applied to truly green, scientifically verified investments. My “Greening Trump’s infrastructure plan” (2016) advocates applying such standards to any new US infrastructure spending.33 Meanwhile China is now a major issuer of green bonds with 27 percent of the total of $92 billion in 2016. In March 2017, the Green Bonds Pioneer Awards34 included eight pioneer issuers from China, Norway, Poland, Germany, Mexico, Netherlands, Costa Rica, Colombia, Finland, Luxembourg, Morocco and the Philippines. The UNEP Inquiry’s May 2016 report focused on “Green finance for developing countries,” and its latest report covers the role of FINTECH in reforming mainstream finance.35 As the green bond financing model went mainstream with many issues oversubscribed, the next stage became securitization. This financial tool became discredited in the USA after its overuse in packaging mortgages helped precipitate the meltdown of the housing market in 2007. Wall Street’s excesses in selling these packages of securitized mortgages to pension funds and unsuspecting municipalities should caution the use of securitization to further unlock capital into the green bond market.36 The European Union (EU) Roundtable on Green Securitization, April 24, 2017 may lead to deeper investment pools to finance the global green transition.37 The OECD estimates that annual issuance of green asset-backed securities could reach between US $280–380 billion by 2035.38 Therefore, monitoring and verifying uses of green bond proceeds is vital, and provided by Trucost, PNC, KPMG, EY, BDO, Carbon Trust, the Climate Disclosure Standards Board (CDSB) and many others. This will remain the key to further deepening of the green bond markets globally. Meanwhile Moody’s report on environmental risks downplayed the US Trump administration’s effect on progress toward global decarbonization.39 The OECD Global Forum on Development convened business and investment leaders in Paris, April 5, 2017 exploring the business case for the UN’s SDGs.40 Outgoing UN Secretary General Ban Ki-moon called the global green transformation “unstoppable” at his speech in Kigali, Rwanda.41 The UNEP and Bloomberg Finance report “Global trends in renewable energy investment 2017” found that wind, solar and other renewables added 138.5 gigawatts to global power capacity in 2016 up 8 percent from 2015.42 In December 2016 Fortune and Time co-sponsored a Global Forum at the Vatican with Pope Francis and 150 Fortune 500 leaders to discuss “The business of humanity” December 2–3 in Rome.43

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318   Handbook of energy politics In January 2017 UNEP announced its new digital tool co-developed with China’s Ant Financial by the Green Digital Finance Alliance to expand green finance.44 China leads all this progress on green finance—it is now the largest issuer of green bonds, and the world’s wind generators and electric vehicles, as well as pioneering DC (direct current) grids more suited to carrying renewable electricity.45 Clearly, while the US pioneered so many of the renewable energy technologies and still leads in many areas of research, China has now assumed global leadership as Trump’s plans falter and regress back to serving fossilized interest donors. The new star at Davos is Chinese Premier Xi Jinping, sticking to the UN summit COP21 Paris Accords in 2015 and COP22 in 2016 as “a responsibility we must assume for future generations.”46 Today’s increases in wind, solar and renewables continues, disrupting the century-old model of providing electricity – seen as a death spiral for many utilities and their financial backers.47 My proposal along with that of Joel Makower et al. (2016) in The New Grand Strategy48 is to ease the short-term dilemma of asset managers as they get up to speed on shifting to green sectors. They can simply re-categorize their fossil reserves now at risk from “fuel” to “feedstocks.” This way they can be valued for future use as materials, rather than being burned.49 As Germany assumes the presidency of the G20 from China, its Green Finance Study Group sees opportunity for enhancing economic growth beyond the GDP model, toward green infrastructure and enhanced competitiveness through efficiency. These green global models were on the meeting agenda hosted by the Bank of America on “Greening the financial system,” April 20, 2017 convened by the UNEP and their Inquiry, Bloomberg Philanthropies, the European Banking Federation, the Paulson Institute (funded by former US Treasury Secretary Hank Paulson), the IIF, SIFMA, with our GTS and other invited participants. Ironically, the US dropout from the Paris Accord has energized the 194 other countries still committed to addressing climate risks and accelerating the green transition through the UN’s COP21 and 22 accords and their SDGs. They may even punish US exports with a “carbon tariff.”50

LEADERSHIP IN GREEN PRIVATE INVESTING As scientific and technological innovation continued unabated—particularly in storage and electrifying transport and vehicle recharging, green companies became more recognized. Imperial College, London and Carbon Tracker forecast by 2035 that electric vehicles (EVs) will make up 35 percent of road transport possibly halting fossil fuel growth by

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Deepening green finance  ­319 2020.51 China is aiming to have 5 million EVs on the road by 2020 and Beijing’s 170,000 taxis will switch to all electric over the next five years.52 While Toyota is now selling hydrogen fueled cars, EVs with better capacity batteries and solar-powered EV charging stations are gaining53 as is demand for greener metals.54 Our GTS 2015 covered the new battery and storage technologies, along with prospects for lithium, cadmium nickel, compressed air, supercapacitors, flywheels and using EVs for household storage—as shown in our TV program “Green Building and Design” (2004) at www.ethicalmarkets.tv. Green private equity groups including Generation Management founded by Al Gore and David Blood manage a $10 billion sized portfolio of pure play green companies. Generate Capital has a pure play portfolio with similar companies as well as many using the popular power purchase agreements (PPAs) helping retail customers and businesses to install solar panels.55 Envision Solar, based in San Diego has delivered its solarpowered EV-charging stations to many cities and is still covering parking lots with its electricity-generating “solar trees.”56 These solar EV chargers require no digging, or permitting, and avoid grid-based fossil-generated electricity while offering security during power outages.57 Meanwhile Impact Investing went mainstream in The Economist’s conference in New York on “Impact Investing: Mainstreaming PurposeDriven Finance,” February 15, 2015 co-sponsored by Bank of America and others with speakers from Morgan Stanley and Bain Capital and another such event in London, June 15, 2017. U.S. Trust-Merrill Lynch now offers socially responsible portfolios, and published Catalyzing Wealth for Change: A Guide to Impact Investing by economist Julia Balandina Jaquier.58 Pioneers include RS Finance in Portland, Oregon (based on the Austrian philosopher Rudolf Steiner’s social philosophy) whose founder Mark Finser serves on Ethical Markets Advisory Board as well as Green Alpha Advisors, Scarab Funds and London-based Menhaden Capital. We include these and many other boutique asset managers in our Ethical Money Directory59—which is a public service with no charge for our selected listers or for those seeking patient, ethical capital—unlike Wall Street’s conventional model of charging referral fees and brokering their contacts. London-based Aviva, one of the world’s largest insurance and asset management firms specializes in climate-risk and related green investing for its 33 million customers.60 A leader in targeting 100 percent of its portfolio to sustainable investments is San Francisco’s Sonen Capital, chosen by leading green investors Charly and Lisa Kleissner and their Felicitas Foundation.61 One of the most innovative start-ups is OpenInvest, which fills a key

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320   Handbook of energy politics niche, especially for concerned ethical investors and millennials tired of listening to the nay-saying of their traditional financial advisors. These investors can now take charge of the makeup of their portfolios, getting rid of polluting, unethical company stocks by moving their money to OpenInvest and activating their own value choices. Taking personal action in ridding portfolios of unwanted stocks appeals to many activists choosing fossil-free, gender-neutral, LGBTQ or more energy-efficient and socially responsible companies. Currently, OpenInvest offers only choices within publicly traded companies, but according to its co-founder Josh Levin, they hope to add more choices in private companies as they grow.62 An even deeper innovation is SolarCoin, a blockchain-based rewards currency for anyone who has successfully harvested free photons from the sun into usable electricity or power.63 This is the brainchild of Nick Gogerty, formerly with hedge fund Bridgewater and author of The Nature of Value (2012).64 SolarCoins are now worldwide and traded on a currency exchange in Zurich and are a partner of Ethical Markets. There is still a huge need to connect the dots in global green markets, and many conferences have been filling this role by convening investors, entrepreneurs and green technology innovations including Investors Circle, Business for Social Responsibility, The B Team, We Mean Business, SolarPlaza, SOCAP, Social Venture Network, ShareAction, BrightTALK, The Global Impact Investing Network, Sustainatopia, Skytop Strategies, the Future 500 and others, proliferating online every day. All these groups and networks including our own Ethical Markets and many business schools and universities complement the work of the UN’s PRI and Global Compact, as well as the UNEP and its Inquiry. Such conferences over the past 20 years were the most effective way to create the robust global green investments markets of today. Often they activated shareholders to bring proxy proposals to company annual meetings. This is still a viable strategy to engage many recalcitrant companies, as in the Future 500’s 2017 report.65 Thus in this chapter, we have documented some of the evidence—growing every day—that green finance is indeed deepening. So many official projections of market penetration of solar energy have clearly often fallen behind actual performance—as confirmed by our 2017 GTS total of private investments now at a cumulative $8.1 trillion since 2007.

NOTES   1. An alternative version of this paper can be found at www.ethicalmarkets.com.   2. P. Coy (2017) “Lies, damned lies and financial statistics,” Business Week, April 10–23.

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Deepening green finance  ­321   3. “Evaluating progress toward the sustainable development goals,” GlobeScan/ Sustainability, 2017.   4. TCFD (2016) “Phase 1 report of TCFD to the Financial Stability Board,” March 31.   5. CDP, formerly the Carbon Disclosure Project as well as 2° Investing Initiative (2017) “Asset-level data and climate-related financial analysis: A market survey.” January.   6. Power Engineering (2017) “FPL announces sites for eight solar plants,” March 2.   7. REN21 (2017) “Renewables Global Futures report: Great debates towards 100% renewable energy,” Paris: REN21 Secretariat.   8. H. Henderson (2008) “Fossilized asset allocation,” November 30, available at http://­hazel​ henderson.com/2008/11/30/updating-fossilized-asset-allocation-classes-november-2008.   9. Social Investment Forum, www.socialinvestmentforum.com. 10. KPMG and H2 Ventures (2016) “FINTECH100 leading global FINTECH innovators,” available at https://h2.vc/reports/fintechinnovators/2016, accessed December 11, 2017. 11. M-Pesa was launched in 2007 by Safaricom and Vodacom, it is now also in Tanzania, South Africa, India and other countries. 12. D. Rushkoff (2015) Throwing Rocks at the Google Bus, London: Portfolio Penguin. 13. Forbes, Interviewed by Christopher P. Skroupa, February 27, 2017. 14. H. Henderson (2016) “Bernanke and Friedman were right: Helicopter money or qualitative easing?” Just Means, June 8, available at http://www.ethicalmarkets.com/ben-­bern​ anke-and-milton-friedman-were-right-helicopter-money-or-qualitative-easing/, accessed December 1, 2016. 15. B. Gates (2017) Fortune, February 22. 16. Renewable Energy World (2017) “More than 3 million in US now work in clean energy,” February 22. 17. C. Krosinsky and S. Purdom (2017) Sustainable Investing, Abingdon: Routledge. 18. Carbon Tracker (2017) “Oil industry still in La La Land,” March 16. 19. Business Week (2017) “Floods of money. The upside of climate change”, March 27–April 2. 20. M. Bloomberg and C. Pope (2017) Climate of Hope, New York: St. Martin’s Press. 21. M. Bolis (2017) “In impact investing’s rush to the mainstream, who are we leaving behind?” Next Billion, April 3, available at https://nextbillion.net/in-impact-investingsrush-to-the-mainstream-who-are-we-leaving-behind/, accessed November 22, 2017. 22. Schneider Electric Energy and Sustainability Services (2017) “Global energy market trends,” April. 23. H. Henderson (2017) “New globalization trends: Nativist patriotism v. green glocalization,” American Sustainable Business Council, March 19, available at http://­asbcouncil. org/blog/new-globalization-trends-nativist-patriotism-v-green-glocalization#.WhV0n7a​ cYdU, accessed November 22, 2017. 24. E.F. Schumacher (1973) Small is Beautiful: A Study of Economics as if People Mattered, London: HarperCollins; and OTA (1981) An Assessment of Technology for Local Development, republished Gainesville: Library Press, University of Florida and Ethical Markets (2016). 25. IIRC (International Integrated Reporting Council) (2017) “Integrated reporting,” Newsletter, April. 26. Nick Robins is author of The Corporation that Changed the World: How the East India Company Shaped the Modern Multinational (2006) London: Pluto Press, now a BBC TV documentary. 27. N. Robins (2017) “2017: What next for green finance,” Huffington Post, sponsored by PWC, January 6. 28. Ethical Markets (2014) “Perspectives on reform of electronic markets and trading,” available at http://www.csrwire.com/blog/posts/1464-reforming-electronic-markets-andtrading, accessed November 21, 2017; Ethical Markets (2016) “FINTECH: Good and bad news for sustainable finance,” available at http://www.ethicalmarkets.com/fintechgood-and-bad-news-for-inclusive-sustainable-finance-2/, accessed November 21, 2017. 29. H. Henderson and T.J. Nash (2016) “Ending externalities: Full-spectrum accounting

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30. 31. 32. 33. 34. 35.

36. 37. 38. 39.

40.

41. 42. 43. 44. 45. 46. 47. 48. 49. 50. 51. 52. 53. 54.

clarifies transition management,” paper at the OECD’s Green Growth Knowledge Platform, Korea in September 2016. UN Inquiry (2015) “Establishing China’s green financial systems, Ma Jun and Simon Zadek, final report of the green task force, April. Climate Bonds (2016) “Green Bonds Highlights 2016,” available at https://www.­climate​ bonds.net/files/files/2016%20GB%20Market%20Roundup.pdf, accessed December 11, 2017. TCFD (2016) “Phase 1 report of TCFD to the Financial Stability Board;” and Climate Bonds Standards and Certification Scheme. H. Henderson (2016) “Greening Trump’s infrastructure plan,” Ethical Markets, November 18, available at http://www.ethicalmarkets.com/greening-trumps-infrastruc​ ture-plan/, accessed November 21, 2017. Green Bond Pioneer Awards: Leadership in Green Finance, London, 2017. UN Inquiry (2016) “Green finance for developing countries”; H. Henderson (2016) “FINTECH: Good and bad news for sustainable finance,” December, available at http://www.ethicalmarkets.com/fintech-good-and-bad-news-for-sustainable-finance/, accessed December 11, 2017. CDSB (Climate Disclosure Standards Board) (2017) “Response to the TCFD recommendations on climate related financial disclosure,” February 12. The European Union (EU) Roundtable on Green Securitization, April 24, 2017, Brussels. S. Kidney (2017) “Green securitization: Part of the climate finance suite: Can the EU lead the way?” Climate Bonds Initiative, April. Moody’s (2017) “Future US climate policy shifts would not stall global emissions reduction efforts,” February 16, available at https://www.moodys.com/research/ Moo​dys-Future-US-climate-policy-shifts-would-not-stall-global--PR_362012, accessed November 22, 2017. OECD (2017) “Working together to achieve the Sustainable Development Goals,” available at http://www.oecd.org/about/secretary-general/working-together-to-achieve-thesdgs-oecd-global-forum-development-2017-welcoming-address.htm, accessed November 22, 2017. UNEP (2016) “Montreal protocol adoption of hydrofluorocarbon standards,” Kigali, Rwanda, October 5. UNEP and Bloomberg Finance (2017) “Global trends in renewable energy investment 2017” Frankfurt School, UNEP Center, Frankfurt, Germany. C. Leaf (2016), “The business of humanity,” Fortune, December 27, pp. 9–16. UNEP (2017) “Media release: Ground-breaking UN-supported digital tool to enhance green financials,” January 20. The Economist (2015) “Rise of the supergrid,” January, p. 7. The Economist (2017) “The new Davos Man,” January 21, p. 33. The Economist (2017) “A world turned upside down,” February 25, pp. 18–20. J. Makower, M. Mykleby and P. Doherty (2016) The New Grand Strategy: Restoring America’s Prosperity, Security, and Sustainability in the 21st Century, New York: St Martin’s Press. H. Henderson (2016) “Assessing risk of fossil reserves: Are they fuel or feedstocks?” available at http://www.ethicalmarkets.com/?s=assessing+the+ris, accessed November 22, 2017. M. Le Page (2017) “The price of emission,” New Scientist, April 8, pp. 22–3. B. Burkholder (2017) “5 ways China is becoming the global leader on climate change,” EcoWatch, April 7. The Guardian (2017) “Electric cars and cheap solar could halt fossil fuel growth by 2020,” February 2. The Economist (2017) “Volts wagons, Electric cars are set to arrive far more speedily than anticipated,” February 18, pp. 53–4. The Economist (2017) “The richest seam: Mining companies have dug themselves out of a hole,” March 11.

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Deepening green finance  ­323 55. Business Week (2017) “Greening business, one project at a time,” December 26–January 8, p. 34l. 56. Envision Solar International, Inc. (2017) “Press release,” February. 57. Full disclosure: Hazel Henderson is an investor in Generate Capital and Envision Solar. 58. J. Balandina Jaquier (2016) Catalyzing Wealth for Change: A Guide to Impact Investing, with Foreword by Christopher Hyzy, Chief Investment Officer Bank of America Global Wealth and Investment Management, US Trust-Merrill Lynch. 59. Ethical Markets (2017) Ethical Money Directory 2017, available at http://4a5qvh23​ tbek30e0mg42uq87.wpengine.netdna-cdn.com/wp-content/uploads/2017/08/Ethical-Mo​ n​ey-Dire​ctory-2017.pdf, accessed November 21, 2017. 60. Aviva (2016) “Seeing beyond the tragedy of horizons,” report. 61. See our 2010 TV program “Private financing of green companies – Interview with Karl Kleissner – Transforming Finance Series” at www.ethicalmarkets.tv. 62. Business Week (2017) “Positive investing for the social activist,” February 13, p. 40. 63. See https://solarcoin.org. 64. N. Gogerty (2012) The Nature of Value: How to Invest in the Adaptive Economy, New York: Columbia University Press. 65. Future 500, March 2017.

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15.  Middle East and Asia: the oil trade and pricing nexus Tilak Doshi

The trade and pricing nexus that has developed between the Middle East oil producers and its oil-importing neighbours ‘East of Suez’ over the past half century is among the most fundamental variables of any global model of energy politics. Oil, as Daniel Yergin has eloquently reminded us,1 provides the lifeblood of trade and the sinews of war of many nations throughout its brief history since the late nineteenth century. The fossil fuel has had no less a central role in the co-evolution of the two key regions in the global oil trade: the Middle East and Asia. This chapter examines key dimensions which characterize the oil trade and pricing nexus between the two regions. Asia’s remarkable oil demand growth and it impact on inter-regional oil trade is the focus of Sections 1 and 2. In Sections 3 and 4, we look at the pricing formula used by Middle East national oil companies (NOCs) in term contract sales to Asia in the general context of commodity pricing in global trade. Section 5 provides a discussion of the ‘Asia premium’, one of the most contentious areas of debate in trading and policy circles concerning the Middle East–Asia oil trade. To place Middle East crude oil export pricing norms in context, Section 6 assesses multilateral attempts to regulate the work of price reporting agencies (PRAs). Section 5 reviews the outlook for alternatives to the status quo in crude oil pricing in Asia. We end with a few concluding remarks.

1 THE EMERGENCE OF ASIA IN GLOBAL OIL TRADE2 References to an ‘Asian century’ were already popular in the 1980s and 1990s. They reflected the shift in the centre of gravity of the global economy from North America and Northwest Europe towards Asia. This shift ranks among most important characteristics in modern economic history. One corollary of Asia’s economic ascent has been the supply of Middle East crude oil. The demand side of the equation accounted for by Asia over the past four decades or so constitutes the leading factor in any narrative of global energy politics. While Asia has had significant 324

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Middle East and Asia: the oil trade and pricing nexus  ­325 Table 15.1 GDP growth rates and share of world GDP for regions and select Asian countries

Country Name

annual average GDP growth rates 1990–2000 2000–15

% of world GDP

2015

2015

East Asia & Pacific East Asia & Pacific (excluding   high income) China India Japan Korea, Rep.

3.8 8.0

4.5 8.4

3.9 6.5

31.5 21.9

9.9 5.6 1.5 6.9

9.5 7.0 0.8 4.3

6.9 7.6 0.5 2.6

17.2 7.0 4.2 1.5

Europe & Central Asia North America Middle East & North Africa Latin America and the Caribbean Sub-Saharan Africa

1.7 3.2 4.5 2.9 2.1

1.8 2.0 4.3 2.9 5.0

1.5 2.2 2.9 -0.6 2.9

23.7 17.2 7.0 8.7 3.3

World

2.8

2.9

2.5

100.0

Notes:  GDP growth rates are simple averages of annual percentage growth rate of GDP at market prices based on constant local currency; aggregates are based on constant 2010 US dollars; percentage share of 2015 world GDP measured in PPP current international $. Source:  World Development Indicators Database, World Bank, accessed on 20 March 2017 at http://data.worldbank.org/indicator/NY.GDP.MKTP.KD.ZG.

domestic crude oil supplies from moderate-sized producers such as Indonesia and Malaysia as well as China (which is among the largest five crude oil producing countries in the world), the region as a whole has long been a large and increasingly weighty net importer of crude oil from other oil-producing regions. The scale and speed of demand growth for crude oil among the Asian developing countries has been a dominating element  in  the evolution of the global oil industry over the past few decades.3 Table 15.1 indicates average GDP growth rates for select Asian countries and other regions 1990–2000 and 2000–15 based on the World Bank’s database. The World Bank’s geographical delineation of the ‘East Asia and Pacific’ excludes South Asia and hence differs from the definition of

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326   Handbook of energy politics Asia adopted here. The East Asia and Pacific region accounts for 31.5 per cent of global GDP in 2015, and if India (the largest economy in South Asia by far) is added in, the region’s share increases to 38.5 per cent. The East Asia and Pacific region grew significantly faster since 1990 than all other regions save the far smaller region (by population and area) of Middle East and North Africa. India experienced higher growth rates than the East Asia and Pacific region over the past quarter century. Indeed, the slowdown in China’s growth rate in 2015 to less than 7 per cent has made India the fastest growing large economy in the world.4 Developing East Asian countries were among the fastest growing economies in the region after China. The dynamism of developing Asia is apparent by the very high aggregate growth rates shown for East Asia and Pacific region once the high-income countries are excluded from the sample with GDP growing by an annual average of between 8.0–8.5 per cent since 1990. This growth performance is exceeded only by China’s stellar average of close to 10 per cent through the period. Commensurate with the rapid economic growth of non-OECD Asia, oil demand growth in the region also exceeded that of most other regions in the world with the exception of the Middle East (where, with a few exceptions, oil consumption is heavily subsidized). Table 15.2 shows estimated regional oil demand growth from BP’s (2016) ‘Annual review of world energy statistics’ which uses a geographical definition of the ‘Asia Pacific region’ which matches that of ‘Asia’ adopted in this chapter. From accounting for just under 15 per cent of total global consumption Table 15.2  Oil consumption growth by region Thousand barrels daily

1970

1990

2015

2015 share of total

1990 share of total

1970 CAGR share 1970– 1990– of 90 2015 total

North America 16,593 20,316 23,644 23.9% 30.5% 36.7% S. & Cent. America 2,066 3,772 7,083 7.5% 5.7% 4.6% Europe & Eurasia 18,155 23,133 18,380 19.9% 34.7% 40.1% Middle East 1,051 3,599 9,570 9.8% 5.4% 2.3% Africa 703 1,993 3,888 4.2% 3.0% 1.6% Asia Pacific 6,661 13,854 32,444 34.7% 20.8% 14.7% Total World

1.0% 0.8% 3.1% 3.2% 1.2% −1.1% 6.3% 5.0% 5.3% 3.4% 3.7% 4.3%

45,229 66,667 95,008 100.0% 100.0% 100.0% 2.0%

1.8%

Note:  CAGR is compound annual growth rate. Source:  BP (2016) ‘Annual review of world energy statistics 2016’.

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Middle East and Asia: the oil trade and pricing nexus  ­327 of oil in 1970, Asia’s share grew to almost 35 per cent in 2015. Asian oil consumption grew by 3.7 per cent during 1970–90 and by 4.3 per cent during 1990–2015. This compares to the respective growth rates of 2.0 per cent and 1.8 per cent for global oil demand growth during the two periods. The rapid increase in Asia’s oil demand is perhaps best measured by the region’s share of global incremental demand. During the two decades 1970–90, global demand grew by 21.4 million barrels per day (b/d), of which 7.1 million b/d were accounted for by Asia – approximately a third of the world total. In the past quarter century, Asian demand increased by 18.5 million b/d, accounting for about two thirds share of global demand growth. China’s role in oil demand growth over the past two decades is remarkable (see Table 15.3). China accounted for a little less than a quarter of Asia’s increase in oil demand during 1970–90. If we take a longer period of almost half a century from 1970 to 2015, China accounted for 44 per cent of total Asian demand growth or almost a quarter of global demand growth. During the extraordinary commodity boom of the 2000s, China alone accounted for 70 per cent of total Asian oil demand increase or 40 per cent of global demand growth. By any standard, China’s weight on the demand side of global oil markets is extraordinary. India has emerged as the other large non-OECD Asian oil consumer, and accounted for between 11 per cent and 16 per cent of incremental Asian demand during the three time spans examined in Table 15.3. India over the past few years has become an increasingly important oil consumer although its weight in global incremental demand is still far smaller than China’s. For the most recent year 2015, India accounted for almost a quarter (23.4 per cent) of Table 15.3  Incremental oil demand (thousand barrels per day)

China India Total Asia Total World Asia as % of World China as % of Asia India as % of Asia China as % of World

1970–90

2000–2010

1970–2015

1,743 821 7,193 21,438

4,740 1,060 6,793 11,776

11,414 3,768 25,783 49,779

34% 24% 11%

58% 70% 16%

52% 44% 15%

8%

40%

23%

Source:  BP (2016) ‘Annual review of world energy statistics 2016’.

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328   Handbook of energy politics Table 15.4  U  S EIA forecasts for liquids consumption by region and country (million b/d) 2012

2040

Growth CAGR (2012–40)

OECD Americas OECD Europe OECD Asia Total OECD

23.245 14.052 8.241 45.539

24.648 13.975 7.474 46.097

0.2% 0.0% -0.3% 0.0%

Non-OECD Asia – China – India – Other Middle East Africa Central and South America Total Non-OECD Total World

21.502 10.175 3.618 7.709 7.705 3.609 6.68 44.765 90.304

38.909 16.358 8.263 14.289 13.232 6.929 9.602 74.792 120.889

2.1% 1.7% 3.0% 2.2% 2.0% 2.4% 1.3% 1.9% 1.0%

Source:  US Energy Information Administration (EIA) (2016) ‘World liquids consumption by region’, http://www.eia.gov/forecasts/aeo/data/browser/#/?id=5-IEO2016&sourcekey=0; accessed 25 October 2016.

Asian’s incremental demand (over 2014), while China contributed just under 58 per cent of Asia’s incremental demand.5 According to the US Energy Information Administration (EIA) longrange oil demand forecasts, OECD oil demand is stagnant to 2040, with negative or nil growth in OECD Europe and OECD Asia, with North America growing by a tepid 0.2 per cent per annum (see Table 15.5).6 Non-OECD Asia demand is forecast to grow annually by 2.1 per cent, over double the world average of 1.0 per cent. China’s share of future global incremental oil demand, as its economic growth rate, will likely diminish. Indeed, some observers have noted that were it not for China’s policy imperative to increase its strategic petroleum reserves in the past few years, the country’s imports would have been significantly lower in 2015 and 2016.7 As China progressively shifts from export-led manufacturing to a services-based economy, the country’s rates of oil demand growth will decelerate. While China’s relative share in oil demand growth declines, other Asian developing countries in South and Southeast Asia, particularly India, will play an increasing role. Asia and the Middle East will continue to be the fastest demand growth regions, growing at almost double the world demand growth rate of 0.9 per cent.

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Middle East and Asia: the oil trade and pricing nexus  ­329 Table 15.5  Crude oil inter-area flows in million b/d 2015 mn b/d

2011 %

mn b/d

change %

mn b/d

Middle East – Asia FSU – Europe Canada – US Middle East – Europe FSU – Asia West Africa – Asia Latin America – North   America West Africa – Europe Middle East – North America Latin America – Asia North Africa – Europe West Africa – North America

17.6 6.2 3.7 2.6 2.3 2.1 1.8

41.2% 14.6% 8.8% 6.2% 5.3% 4.9% 4.2%

14.5 6.0 2.7 2.5 1.7 1.8 2.3

37.9% 15.7% 7.0% 6.5% 4.4% 4.7% 6.0%

3.1 0.2 1.0 0.1 0.6 0.3 −0.5

1.7 1.6 1.5 1.1 0.4

4.1% 3.7% 3.5% 2.6% 0.8%

1.2 2.0 1.1 1.0 1.5

3.1% 5.2% 2.9% 2.6% 3.9%

0.5 −0.4 0.4 0.1 −1.1

Total

42.6

100.0%

38.3

100.0%

Global imports

60.7

54.6

Total listed flows as % of   global imports

70.2%

70.1%

Note:  Data for 2011 includes some refined product flows as there is no disaggregation between crude oil and refined products; 2015 data refers to crude oil flows only. Source:  BP (2012; 2016) ‘Annual statistical review of world energy’.

2  INTER-AREA TRADE FLOWS Asia’s appetite for oil is accommodated by imports primarily from the Middle East. For Middle Eastern oil exporters, Asia has been, and will continue to be for the foreseeable future, the largest growing importing region in the world. Given its proximity, Asia enjoys freight cost advantages for its baseload of imports from the Middle East. From an Asian perspective, the Middle East – endowed with the world’s largest low-cost reserves – is ideally positioned to meet Asia’s needs, although security concerns over geopolitical over-dependence and exposure to the instabilities of that tumultuous region have long been part of Asian energy policy. Dependence of course cuts both ways. Asia’s dependence on oil imports from the Middle East is balanced by the dependence that the ME

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330   Handbook of energy politics e­ xporters have on revenues for crude oil sales into Asia. A majority of Middle Eastern exports head to Asia while, in turn, Asia hauls most of its crude oil imports from the Middle East. According to recent estimates of inter-regional crude flows for 2015, more than two thirds of Asian oil imports were sourced from the Middle East; Asia, in turn, accounted for over three quarters of total Middle East oil exports.8 Table 15.5, drawn from BP data, estimates the most important interarea oil flows in million b/d in 2011 and 2015 accounting for about 70 per cent of global imports. Middle East crude oil exports to Asia constitute by far the single largest inter-area crude oil flow in the global oil trade. It accounted for 14.5 million b/d in 2011, and this increased by over 3 million b/d in 2015 accounting for 41.2 per cent of all the crude flows listed in the table. Former Soviet Union (primarily Russian) exports to Europe are the second largest inter-area flow, accounting for 15–16 per cent of the flows listed or around 6 million b/d. The largest change in trade flows between 2011 and 2015 is the increase in Middle East exports to Asia, reflecting Asia’s rapid growth in oil demand. The next major change is the sharp decreases in West African and Latin American oil exports to North America, which fell from 1.5 to 0.4 million b/d and from 2.3 to 1.8 million b/d respectively. Canadian exports to the US increased by 1 million b/d in the same period. Russia’s exports to Asia increased by 0.6 million b/d. The other major oil producing regions West Africa and Latin America also increased their exports to Asia, by 0.3 and 0.4 million b/d respectively. Two factors, one on the demand side and the other on the supply side, have led to the recent shift in inter-area oil movements. Major crude oil exporting regions are reorienting towards Asia simply because this is where much of the global incremental demand is located, apart from the Middle East itself. Import needs are expected to decline over the coming decades in the large but saturated oil markets of OECD Asia-Pacific (Japan and South Korea). Developing Asian countries such China, India and other non-OECD Asian importers’ need for imported barrels will continue to grow. The second factor is the dramatic surge in unconventional production of liquids (‘light tight oil’) in the US and continued growth in heavy oil output from Canada. These have displaced foreign imports into North America, especially from West Africa and Latin America. OPEC’s decision in November 2014 to maintain output and market share despite sharp falls in oil prices in the latter half of that year led major crude oil producers from outside the region to compete aggressively in Asian oil markets. With the shale oil boom in the US and sluggish demand in Europe, crude oil exports from the Russian Far East, West African and Latin American to Asian markets have increased, challenging the traditional large exporters in the Middle East. For many of the large

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Middle East and Asia: the oil trade and pricing nexus  ­331 Asian crude oil importers who had been intent on diversifying sources of crude oil imports, low oil prices since mid-2014 have provided momentum to Asian imports of non-Middle Eastern crude. In terms of perceived energy security, there is a diversification benefit for Asian importers from what was previously expected to be an inevitable growing dependence on Middle Eastern supplies.9 Middle East oil exporters such as Saudi Arabia and Kuwait compete for Asian market share not only with crude suppliers from other regions but also with other major exporters within their own region such as Iraq and Iran. Both these countries lost market share after years of wars and sanctions, and are intent on reclaiming their previous peak oil exports levels.

3  PRICING IN GLOBAL COMMODITY TRADE Commodity trade is typically executed through bilateral contracts which determine quantity and quality specifications, time and place of delivery, and price. At one end of the spectrum, these contracts can be private and confidential (‘P&C’) between buyer and seller, and may be based on opaque arrangements. For example, buyers may have equity stakes in, or make long-term loans to, commodity suppliers in return for a long-term commodity supply contract at ‘preferential’ prices.10 At the other end, trade takes place in electronic commodity exchanges which allow trade of highly standardized commodity contracts with strictly specified volumes, qualities, delivery schedules, modes of allowed delivery (ex-ship or exstorage facility), payment terms and so on. In exchange-traded commodity contracts, the counter-party to every buyer and seller is the exchange’s clearing house. It should be noted that in many exchange-traded commodity contracts, physical delivery often plays a smaller or minor role, as most futures contracts are liquidated via cash settlement; that is, the purchase of an equal and opposite position on the contract before its physical delivery due date. The group of commodities traded on modern electronic exchanges has expanded since the earliest ones based on an ‘open outcry’ systems were founded in the late nineteenth century in the US and the UK. The widely tracked Goldman Sachs Commodity Index (GSCI) for example includes six energy contracts,11 seven industrial and precious metals contracts, and 11 agriculture and livestock contracts. However, much of the physical trade still occurs outside of the formal commodity exchanges. Difficulty in grade standardization, dominant producers or buyers preferring direct bilateral negotiations, and government price or supply regulations often constrain the successful establishment of formal commodity exchanges.

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332   Handbook of energy politics In some highly concentrated industries, a few dominant sellers and buyers set market ‘guideline’ prices which are then used as a reference price for trading by numerous smaller buyers and sellers around the world.12 Relatively few commodity prices are directly discovered by the formal commodity exchanges. Instead, there are a large class of commodities which are priced off assessments published by price reporting agencies (PRAs). Indeed, the largest internationally traded commodity categories (by value) – crude oil and refined petroleum products – are mainly transacted using price assessments published by private companies such as Argus Media, Platts and ICIS. The influence of such PRAs extends across the global commodities trade, including petrochemicals, coal and liquefied natural gas (LNG), metals, as well as other goods or services outside of the traditional commodities space, such as oil freight rates and wholesale power. According to market observers, an estimated 60–70 per cent of all contracts in the over-the-counter (OTC) oil derivatives market are priced in reference to quotes published by PRAs.13 Among the PRAs, Platts plays a dominating role in oil-related price assessments. An estimated 80 per cent of global crude oil and refined products trading, including most of Middle East sales of crude oil to its largest markets ‘East of Suez’, is transacted on the basis of Platts published price quotes.

4  PRICING OF MIDDLE EAST CRUDE OIL IN ASIA14 Given that the Middle East–Asia oil trade is the largest among the world’s inter-area oil flows by far, the pricing of Middle East crudes is a perennial issue of concern in both industry and government circles. Crude oil prices have major impacts on national balance of payments and the balance-sheets of the world’s largest national and international oil companies. Formula prices were first adopted by Mexico in early 1986 and widely accepted by Middle East oil exporters soon after. This was in the aftermath of the 1985/86 collapse of the administered pricing system of the previous decade, where crude sales prices were directly set by OPEC oil ministers meetings. Crude oil sales by Middle East national oil companies (NOCs) to international buyers are executed via long-term crude oil sales agreements (COSAs), usually ‘evergreen’ contracts renewable annually on agreement between buyer and seller. The pricing formula generally has four components: point of sale, a market-related base price, an adjustment factor that is reflective of crude oil quality and the point of sale and a timing mechanism that stipulates when the value of the formula is to be calculated.15 For buyers of Saudi crude in Asia, the FOB crude oil price is

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Middle East and Asia: the oil trade and pricing nexus  ­333 Table 15.6  Saudi OSP FOB Gulf for Arab Light (official selling price) Saudi Selling Price Formulae Oct t-2

Nov t-1

Dec T

Jan t+1

Feb t+2

linked to the monthly average spot price of Oman and Dubai crude oils (O/D) during the month t in which the crude is loaded at a Saudi port for delivery to the Asian market.16 The base price for crude lifted at Ras Tanura or other Saudi ports17 is then adjusted by adding or subtracting an ‘offset’ or adjustment factor. Thus, the price for the Arab Light (AL) grade of crude oil is given by:

ALt = O/Dt + offset

The offset or adjustment factor takes into account the quality differential between the given Saudi crude grade and the reference crude it is being priced off. The quality differential is measured as the difference in Gross Product Worth (GPW) of the Saudi crude relative to the reference crude.18 The other two factors that determine the value of a commodity (apart from its quality differential) is its location and time of delivery; since AL, Oman and Dubai crudes all originate in nearby ports in the Arabian Gulf (AG), the freight differentials are marginal.19 And the time of delivery (on FOB basis at an Arabian Gulf port) are for the same month of lifting for all the three crudes. In the case of Arab Light for instance (see Table 15.6), the offset for ALt (Arab Light loading in month t, which is December in this example) is announced in the first week of t – 1 (November). At the time of the announcement of the December offset, the latest historical market data available is from month t – 2 (October). So, in determining the value of the offset for ALt, the GPW difference between AL and the reference crude (O/D) is calculated for the most recently available data in month t – 2. In Asia, the crude oil spot market trades two months ahead of delivery into Asian destinations, and Platts quotes for front-month Dubai in December are for February deliveries of 500,000 barrel cargo sizes.20 That is, when loading occurs in month t (December), the front month quotes for Oman and Dubai crudes are for t+2 (February) delivery. It is during t – 2 (October) that front month quotes for Oman and Dubai refer to the month of loading t (December) and 3rd month quotes refer to month t + 2 (February). Since December loading cargoes in the AG use the front month Platts

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334   Handbook of energy politics quotes (which are for pricing February deliveries in Asia), the time structure of the reference crude prices impacts the invoice price for the crude sale. That is, if the price of the reference crude Dubai in the month when AL is loaded exceeds the two-month forward price (the Dubai front month quote), it loses by that amount of backwardation. Hence a backwardation premium is added to reflect the value of December loading AL term contract FOB cargoes in the AG as shown below:

offset = (ALGPW(t-2) – ODGPW(t-2)) + (DM1(t-2) – DM3(t-2))

Apart from significant exceptions such as Oman and the UAE, Middle Eastern NOCs have typically shunned selling crude oil in spot markets, preferring term formula price contracts as the means to dispose of the bulk of their crude oil exports. However, ME NOCs have occasionally sold crude oil in the Asian spot market. According to press reports, Saudi Aramco sold its first cargo (to Japanese refiner Cosmo Oil) from the joint oil stockpiling facility in Okinawa in April 2012 (for May delivery) in the spot market.21 In the post second half 2014 environment of low prices and intense competition in the Asian crude oil market, the pressure for the ME NOCs to protect market share has increasingly led to engagements in spot markets with non-traditional customers. The recent Saudi Aramco sale of a spot cargo to a small, independent Chinese refiner sparked the attention of oil industry observers.22 According to veteran oil observer Ed Morse of Citibank: News that Saudi Arabia is selling a cargo on the spot market to Asia may mark the turning of a dramatic new chapter in the Saudi playbook . . . What is unusual is that the sale is spot rather than the initiation of a new term contract. Spot sales are about the only way the Kingdom can gain new market share in a world in which chunky buyers are interested in securing incremental purchases via spot rather than term arrangements.23

From the point of view of the ME NOC, the sales of crude oil on a spot basis could be considered so long as it does not lead to a revenue loss relative to if the crude seller were it to have sold the cargo FOB Arab Gulf under its usual term contract arrangements. If the sales of the spot cargo to new clients would offer prospects of converting some of the spot market buyers to becoming ‘regular customers’ under conventional term contracts preferred by the ME NOCs, the latter could be expected to pursue it opportunistically so long as it does not substitute or ‘cannibalize’ its existing term contracts. From the point of view of a crude oil customer in NEA, the market price of the ME crude sold on the spot market should be comparable to

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Middle East and Asia: the oil trade and pricing nexus  ­335 other similar crudes available for delivery in the region. A refiner in Asia would buy the most competitively priced crude oil adjusted for its relative quality and freight cost. As the spot market for crude oil in Asia is active two months forward, if an Asian refiner wanted to procure a prompt cargo one month ahead it would have to assess the month ahead market value of the reference crudes such as Dubai or Brent.24 As the front month Dubai crude contract is quoted for two months ahead, the crude oil buyer would have to use quotes in the ‘over-the-counter’ or derivatives market instead. The Dubai swap contract, quoted for one month ahead, is often used to hedge typical medium or heavy sour crude from the Middle East. Other spot crudes available to the NEA buyer from West Africa, Latin America and the US West Coast are priced off Brent, the leading global benchmark crude used for the Atlantic Basin crude oil trade. A buyer of prompt crude in NEA would have to consider the quality and freight cost of crude cargoes on offer as well as its price relative to the two global benchmarks Dubai and Brent. Dubai swaps are settled against the average of Platts’ front-month spot Dubai crude assessments. The cash-settled Dubai paper assessment reflects paper transactions of a minimum of 50,000 barrels. An Asian refiner wanting to buy a cargo in December for a January loading would assess offers based on alternative crudes priced off Brent or Dubai. Whether the buyer hedges his purchases or not, these pricing relationships present the context in which offers for prompt delivery by crude sellers would be assessed. The relationship between crudes priced off Brent and off Dubai is outlined in Table 15.7. The price of crude oil at any point in time in the Asian spot market may be higher or lower than the opportunity cost facing ME NOCs, which sell the vast majority of their crudes via term contracts on an FOB Arabian Gulf basis. In weak markets, the tendency is for spot prices to be lower than term contract prices, and vice versa. While formula prices for crude oil purchased under term contract are typically referenced to spot crude prices, term contract price movements would be expected to lag spot price movements under most market circumstances. Term contract prices are ‘sticky’ relative to spot prices other things being equal.

5  THE ‘ASIA PREMIUM’ DEBATE25 Assertions that Asian refiners pays higher prices for crude oil exported from the Middle East relative to their counterparts in Europe and the US have been made since the advent of formula pricing in the second half of the 1980s. This adverse price differential that Asian refiners claimed to

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336   Handbook of energy politics Table 15.7  R  elationship between Dubai and Brent, swaps and physical contracts (Asia close time-stamp) ICE Jan Brent Futures

+/−

ICE Jan Brent EFP* =

ICE Jan Brent Physical +/−

ICE Jan Brent-Dubai = EFS** Dec/Jan Dubai swap = spread

Jan Dubai swap

+/−

ICE Jan Brent Physical Jan Dubai swap Dec Dubai swap

*Exchange of futures for physical; **Exchange of futures for swaps

face is referred to as the ‘Asian premium’. Researchers from large Asian crude oil-importing countries such as Japan, South Korea and China have estimated the magnitude and variation of the so-called premium.26 According to the Institute of Energy Economics, Japan (IEEJ), ‘crude oil prices for Asia have remained higher than those of European and US markets by $ 1.00 – $1.50/bbl [per barrel] throughout the 1990s’.27 In another paper by the IEEJ, the Asia crude oil premium to Europe was estimated to have averaged $0.95 per barrel (bbl) over the period January 1991 to June 2002.28 In 2010, an article in the Wall Street Journal indicated that the Asian premium had been, on average, ‘about $1.20 a barrel since 1988’, without attributing sources.29 Utilizing data for the period 1990–97, Soligo and Jaffe found that Saudi FOB prices for crude oil destined for Asian markets have been, on average, $0.83 higher per barrel than for Western Europe, and $0.93 higher than for the United States.30 In another paper, the authors calculate the Asia–Europe differential for Saudi Arab Light FOB sales to average $0.90/bbl over 1988–2002, increasing to $1.48/bbl over 1997–2002.31 In an earlier study, covering January 1992 to November 1996, the Asia-destined loadings for Saudi Arab Light realized prices were found to be, on average, $1.00 to $1.20/bbl higher than for European loadings.32 While the empirical data cited in these studies supports the existence of a persistent Asian premium during the 1990s and 2000s, there have also been periods of time when Asia has enjoyed discounts. According to the Petroleum Intelligence Weekly, Saudi Arabia sold Arab Light crude to Asia for about $6.40 less per barrel than it charged European buyers in March 2010. Utilizing a daily price data set for 2007–2009, another study found the Ras Tanura FOB price differentials between regions to be highly volatile with Asia-destined cargoes trading at both premiums and discounts to Europe-destined cargoes during that period.33 In 2007, Asia experienced a large ‘discount’ relative to Europe, ranging from $2.00/

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Middle East and Asia: the oil trade and pricing nexus  ­337 bbl to $3.57/bbl. Then, in 2008, Asia experienced a very large premium compared to Europe, ranging from $4.59/bbl to $7.00/bbl. In 2009, the premium reversed again, and Arab Light sold to Asian buyers was at a discount to Europe, this time ranging from $0.04/bbl to $0.50/bbl. Over the three years studied, Asia paid a small overall premium of $0.19 relative to Europe. Reflecting on the reversal of the ‘Asian premium’, Chiu and Pleven (2010) in the Wall Street Journal opined that the ‘rising power of Asian oil consumers is increasingly helping them buy oil more cheaply than their counterparts in the West, a reversal of the historical pattern’.34 Tom Wallin, president of PIW, predicted that ‘an Asian discount is looking more likely to be the new normal’; Dave Ernsberger, the global oil director at Platts stated that ‘It’s a game changer . . . the balance of power in pricing is drifting to Eastern markets’.35 The discussion of the ‘Asia premium’ in much of the literature has been cast as an empirical question, with little theoretical underpinning to understanding why such a state of affairs could persist for such long periods of time. An exception has been the work published by Soligo and Jaffe which explains the Asian premium in a model of constrained price discrimination among segmented markets.36 They argue that Saudi Aramco’s abilities to restrict the destination of its oil sales, and to charge a price according to destination, are prerequisites for the existence of the Asia premium. At the margin, the price differential between Asia and the US or European markets is limited by the difference between the freight costs of transporting alternative non-Middle East crude oil supplies (such as West African cargoes) to Asia and to the Atlantic markets. The constrained optimization model presented by Soligo and Jaffe shows how region-specific prices can be set by the seller in order to allocate crude oil exports to maximize global revenues, so long as the regions cannot freely trade that commodity with one another. This is a straightforward exposition of the micro-economics model of price discrimination, with segmented markets exhibiting different price elasticities of demand. The price discrimination model however fails to explain how the formula price system adopted by Saudi Arabia in the aftermath of the 1986 oil price collapse can be practiced without a system of regionally differentiated prices. The failure of the previous administered pricing system made it imperative that OPEC countries switch over to selling crude oil to end users through term contracts that used liquid reference crude oil prices in each of the major consuming regions (Asia, Europe and North America). It was imperative for Saudi Arabia in the aftermath of the 1985/86 price collapse to adopt a ‘market responsiveness with a low profile’ in order to avoid being a price leader.37 Saudi crude exports – and, by extension, other

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338   Handbook of energy politics OPEC crude exporters – had to be price responsive to growing non-OPEC crude oil supplies in the 1980s and 1990s, such that there did not emerge a two-tier pricing regime as it did under the administered price system. The large crude oil exporters would be expected to have marketing strategies based on maintaining ‘significant’ market share in key consuming regions around the world and avoid being exclusively dependent on any single major market. To achieve this risk-optimizing marketing strategy, a necessary corollary of oil policy would be to disable the customer’s right to ‘onward sell’ its allotment of crude oil, and thereby inhibit independent selling price signals. Saudi crude prices had to be market determined, not market determining, and this could only be achieved by fixing a relationship with regional reference crude oils whose prices were discovered in large, liquid markets. As remarked by Ali Al-Naimi, the Saudi Minister of Petroleum and Mineral Resources, ‘The fact is that within the existing complex market framework, with its wide diversity of players, no one can claim to have a Midas touch. We aim at a reference price, leaving markets to determine actual prices through their own dynamics.’38 If Saudi policy were to allow for resale of crudes by its customers, this would immediately lead to further transactions downstream. Crude oil would be re-shipped to higher-priced markets from lower-priced markets, so long as inter-regional price differentials were higher than freight costs. This defines absolute price discovery, and, once again, independent price signals for a global absolute spot price for Arabian crudes, adjusted for freight costs, would emerge – the very opposite of what the formula price system intended to achieve. While the large OPEC oil-exporting countries could ‘globalize’ their prices by ending end-user and resale restrictions on their crude oil exports, this would in effect be a regression to a situation approximating the pre-1985 administered pricing system, and discarding the formula-based regional market-responsive pricing system. Among the ‘proposals’ offered by East Asian research institutes in response to the perceived Asian premium, two are noteworthy: 1. adopt Brent crude as the reference price for Asian sales, rather than the PRAdiscovered Oman/Dubai average as is currently the case; or 2. allow spot trading of Arab Light, thereby making it the ‘marker’ crude for Middle East crude oil grades in Asia. In the light of the previous discussion of formula pricing and oil markets post-1986 (see Table 15.7), the critical link between Brent and Dubai crude oils via the EFS (Exchange of Futures for Swaps) contract is well traded and among the most active derivative contracts in Asia. Via the EFS, companies shift their price risk exposure from Dubai to the Brent futures contract which is easier to mitigate. The argument for adopting Brent as the reference price for Asian markets as a means of mitigating the ‘Asian premium’ is misconstrued in that it fails

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Middle East and Asia: the oil trade and pricing nexus  ­339 to recognize that the Dubai reference price is itself a relative price to Brent futures. Trade in the Brent–Dubai EFS contract yields the fixed price for Dubai swaps, with the Brent complex providing the pricing ‘anchor’. As for the argument that Saudi Arabia should allow for the spot trading of Arab Light cargoes, this is no less than a call for the abandonment of the entire formula price system as practised since the collapse of the administered pricing system in 1985/86. It should be no surprise that such a proposition would be hardly countenanced by Saudi Arabian officials for whom the experience of the 1985/86 oil price collapse was both traumatic and pedagogical. One of the more controversial if journalistic ‘solutions’ to the Asian premium issue has been talk of a ‘combined challenge’ by China, Japan and South Korea to Middle Eastern oil producers, by leveraging joint purchases of crude oil for collective bargaining power.39 To date, nothing has come about of this initiative, although the report stated that ‘China, Japan and Korea are together searching for ways to eliminate the [Asian] premium through an ad hoc body known as the “Committee on Northeast Asian Co-operative Initiative’’’.40 The difficulty in taking this ‘bargaining’ approach to oil price determination as a credible threat is that it miscasts the current pricing system. Formula prices, as the name implies, are quite mechanical in their formulation. They are not set by direct bargaining between large buyers and sellers as much as by the relative refining values (adjusted for freight) of the Middle East crude oil exports relative to reference crude oils traded in regional spot and futures markets in Asia, Europe and the Americas.

6  THE POLITICS OF OIL PRICE DISCOVERY Crude oil reference prices in the Atlantic Basin market (Brent Blend and West Texas Intermediate) are discovered in formal futures markets such as the Intercontinental Exchange (ICE) and the New York Mercantile Exchange. As described earlier, the reference or ‘marker’ price for Middle East crudes sold in Asian markets, however, is assessed by price reporting agencies (PRAs). The ‘Oman–Dubai average’ base price in typical crude oil sales invoices refers to price assessments published by Platts, a leading PRA and a division of Standard & Poor’s. The problems with crude oil price discovery in Asia, and specifically with the assessment methodology related to Platts Dubai price quotes, have long been issues of concern for editorials in industry journals and the trade press. It has also been subject to academic attention.41 After the Libor scandal in 2012, regulatory authorities in the US and

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340   Handbook of energy politics Europe began to examine the risks implicit in relying on PRAs in crude oil price discovery and the potential for price manipulation by market actors.42 BP, Statoil and Royal Dutch Shell offices as well as those of the price reporting agency Platts were raided by European Commission officials in May 2013. In June of the same year, the US Federal Trade Commission (FTC) opened a formal investigation into crude and refined oil price manipulation on the heels of the inquiry by the EC.43 To date, no charges have been laid and both the EC and the US authorities have ceased pursuing the investigation.44 The G20 Leaders’ Cannes Summit Final Declaration (2011) called for work relating to oil price reporting agencies (PRAs) and ‘the proper functioning of oil markets’.45 In 2012, the International Organization of Securities Commissions (IOSCO) responded (jointly with the International Energy Forum (IEF), the IEA and OPEC) to the Cannes Declaration. It deliberated on increasing oversight of PRAs involved in oil price assessments, issuing a consultation report and solicited comments from various stakeholders prior to the completion of the Final Report.46 In the wideranging commentary in the trade press and the news media that followed the Libor scandal and IOSCO’s call for comments on oil PRAs, one criticism commonly brought up was that the oil PRAs have ‘too much power’ and that PRAs use that power ‘to determine the contractual framework in which trades take place rather than simply reporting trades’.47 From a legal point of view, the charge that PRAs are ‘too powerful’ is difficult to pin down. Any such ‘power’ exercised by the PRA is the outcome of purely voluntary actions on the part of the PRA’s service users. As the use of price assessments published by PRAs are solely at the discretion of buyer and seller for effecting physical or derivative transactions, it is not clear just what ‘power’ the PRA possesses in the market place beyond that of delivering its service to willing buyers. So long as PRAs publish price assessments within methodological and editorial guidelines that are made known to all participants and to appropriate regulatory authorities, the charge that they have ‘too much power’ remains unactionable from a regulatory or policy viewpoint. For PRAs to derive reasonable price assessments, it would be a requirement that their editorial guidelines for the assessment process reflect transactions, bids or offers where market participants are willing and able to perform under typical contractual terms adopted as industry norms. To that extent, PRAs are compelled to specify contractual terms as practiced in the industry in order to clearly signal which transactions, bid and offers would qualify as relevant data for inclusion in their price assessment process. In other words, ‘simply reporting trades’ necessitates detailed rules as to what terms (in terms of logistics, timing, deliverability, quantity

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Middle East and Asia: the oil trade and pricing nexus  ­341 tolerances and so on) would govern the reporting of transactions, bids and offers by the PRA. Some observers have noted that PRAs effectively engage in ‘selective reporting’, since they do not require oil market participants to submit data on all their trades. A further concern is that a narrow pool of market participants could ‘game’ or collude in price assessments for their own benefit at the cost of consumer welfare. As one Financial Times report by Tett opined: ‘PRAs do not create these indices just based on prices established by actual trades; instead, they also rely (sometimes heavily) on reported quotes from a pool of selected financial players, with sometimes as few as five participants taking part’.48 In this view, the PRA price assessment processes reflects a market for ‘big boys’, described by one oil trader as an ‘oligopoly of large “too big to fail” companies with close links to governments and regulators with a vested interest to keep the ‘status quo’ which they find so profitable’.49 Given the voluntary nature of price reporting by oil market participants, PRAs cannot ‘require’ anything of oil traders; nor can they sanction oil traders from reporting only a selection of their transactions. Aside from ensuring that all reported transactions are confirmed as bona fide transactions (on both the buy and sell sides) and that reported bids and offers are firm and open to the market at large and executable, it is not clear just what the charge of ‘selective reporting’ by PRAs entails. So long as there are no barriers to entry for oil traders willing and able to participate in the price assessment process, any ‘selective’ reporting can always be challenged by competitors in the market place who can engage in counter bids or offers to reflect their opposing (buy or sell) side of the market. Presumably if there were an ‘oligopoly’ of traders influencing the price assessment process, existing market regulations on collusive behaviour and rigged markets would elicit the attention of the relevant statutory agencies in various jurisdictions. The discontinued investigations initiated by EU and US officials suggest that there was no actionable evidence of market collusion. For the PRAs, one would assume that the threat of customer dissatisfaction and market sanctions would ensure at least a modicum of integrity to the price assessment process. If any particular PRA’s assessment methodologies and its implementation are perceived as biased against either buyers or sellers, competition in the market place for price assessments would naturally lead customers away from that PRA’s (deficient) services. PRAs, after all, have every incentive to produce accurate data since the parties on both sides of any transaction rely on them. Any PRA that loses the trust of market participants would lose its revenues from subscription services for price assessments.

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342   Handbook of energy politics One unintended consequence of attempts to regulate PRAs is that the fear of liability would lead oil market participants to refrain from reporting transactions. If regulations were imposed that would make both traders that submit price quotes and the reporters that publish them legally liable for any losses in oil markets resulting from ‘incorrect’ prices however defined, this would naturally lead oil traders to withdraw from making any information on oil transactions publicly available. This in turn would lead to opacity in market activity and a reversal from open and freely traded oil markets. It could also constrain PRAs from performing their price assessment functions as government officials determine how PRA reporters and editors should assess prices.50 As IOSCO itself concedes, ‘Because data are submitted on a voluntary basis, precipitous regulation of PRAs or requirements that oil market participants who submit data to PRAs submit all of their transaction data potentially could result in some oil market participants to decrease or even cease their submission of data to PRAs.’51 The threat of legal liability would make oil companies and their compliance departments more cautious about submitting data and opt to trade privately. A return to opacity in oil and other energy markets is the very opposite of what regulatory regimes are designed to achieve. An intrusive regulatory regime for PRAs would lead oil market pricing back to the earlier system when the oil industry was largely based on global vertically integrated oligopolistic firms which controlled markets from upstream exploration and production to downstream oil refining and marketing and erected formidable barriers to entry for smaller competing firms. Indeed, markets hardly existed as most flows from ‘source rock to petrol pump’ were transactions that were carried out within the globally integrated oil firms at opaque internal transfer prices established by the major oil companies. After the dislocations and nationalization of oil resources in the 1970s, global oil markets have become far more fungible. There is a much larger role for market forces and oil markets are much more flexible as a result. By the 1980s, spot physical and derivative markets including futures and swaps helped establish competitive price signals for global trade in crude oils and refined oil products. PRAs played a critical role in this process of increased price transparency and competitive markets. The fact remains that the world’s largest inter-regional flows of crude oil – including the flow from the Middle East to Asia, amounting to over 17 mmbd in 2015 – are priced off PRA assessments. To date, the Saudi, Kuwaiti, Iranian and other Middle East OSPs for Asia-destined long-term crude oil sales are based on PRA assessments, and there is no reason to believe that this will change anytime soon.52 No official announcements have been made by the region’s NOCs or their

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Middle East and Asia: the oil trade and pricing nexus  ­343 governing ministries regarding intentions to adopt alternative benchmarks as their pricing basis in Asian sales. The current system of price assessments by PRAs is subject to the IOSCO Principles for Oil Price Reporting Agencies, which on the whole seem reasonably modest in their regulatory requirements for appropriate oversight. The potential for regulatory over-reach – and its unintended adverse consequences – in the EU or the US in the area of oil price discovery seems alleviated for now.

7 ALTERNATIVE TO THE STATUS QUO IN ASIAN OIL PRICING Three potential alternatives to the Dubai price assessments published by the PRAs have been noted in the trade press on Asian crude oil benchmark pricing: the Oman Futures contract traded on the Dubai Mercantile Exchange (DME); ESPO crude in Russia’s Far East and the proposed sour crude futures contract on the Shanghai International Energy Exchange (INE). The Oman Futures contract was launched in June 2007, and since then established itself as the key instrument for physical Oman crude oil delivery. However, its estimated average daily traded volumes of 5,000–6,000 contracts pale in comparison to the daily volume of over 800,000 Brent futures contracts traded on the Intercontinental Exchange (ICE) in September 2016.53 The emergence of the DME Oman Futures contract as a viable instrument for establishing a reference price for Middle East crude oil exports to Asia is contingent on whether key market participants support the use of that instrument as a mechanism for price discovery. Until a major Middle East national oil company elects to use the DME Oman Futures contract price as a price benchmark (to replace the current Oman–Dubai average reported by PRAs), the contract will continue being traded as a tool for effecting physical delivery of Oman crude.54 For all those with price exposure to Dubai-linked crudes sold on term contracts (accounting for the vast majority of Middle East crude exports to Asia), the ability to shift risk from Dubai to the Brent futures contract is a critical requirement, and the most liquid instrument for that remains the Brent–Dubai EFS contract traded on ICE in London. DME’s ambitions for the contract’s wider role as a pricing reference and risk management instrument for Middle East crudes sold in Asia will likely remain out of reach until a major stakeholder or group of stakeholders find the existing PRA assessments of oil benchmark prices too dysfunctional and unilaterally opts for an alternative. This is precisely what happened in the case of Saudi crude oil sales in the US. In 2008 and

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344   Handbook of energy politics 2009, WTI crude was often ‘disconnected’ and sold at steep discounts to the Brent global benchmark as a result of logistical bottlenecks at the Cushing delivery point. Faced with the large revenue losses due to the WTI discounts, Saudi Aramco announced a switch in their price reference in January 2010 from the Platts’ benchmark WTI assessments for delivery at Cushing (Oklahoma) to a competing PRA’s (Argus Media) price assessments of an alternative sour crude index.55 Known as the Argus Sour Crude Index (ASCI), it is a volume-weighted average of daily spot sales of the three US Gulf Coast medium sour crudes Mars, Poseidon and Southern Green Canyon. The completion of the ESPO (East Siberia–Pacific Ocean) oil pipeline in 2010 allowed crude oil cargoes to be loaded out of the port of Kozmino in Russia’s Far East. Kozmino’s proximity to the oil refineries of Northeast Asia, within three to five days’ sailing time from markets in China, South Korea and Japan (which account for over half of total Asian demand for crude oil), confers significant locational rents to ESPO Blend crude oil relative to similar quality crudes which need to be imported from much further distances in the Middle East, West Africa and Latin America. It can take anywhere from two to three weeks to ship oil cargoes from these latter locations to Northeast Asian destination ports. ESPO Blend exports from Kozmino led several market observers to suggest that the new crude marketed into Asia had the attributes that could lead it to serve as a new pricing benchmark.56 Although deliveries of ESPO crude at Kozmino are significant in volume (estimated to be over 500,000 b/d in 2014–15), sales of the crude away from spot trade in favour of long-term supply commitments and sales via tender to invited participants have limited spot market liquidity.57 Concerns about concentration on the supply side, with two companies – Rosneft and Surgutneftegaz – accounting for almost three quarters of ESPO production also works against ESPO spot trade leading to independent price discovery. On the demand side, when the ESPO trade out of Kozmino gained momentum from 2010 onward, it drew a wide range of customers including Singapore, Malaysia, Australia and the US outside of the core markets of Northeast Asia (China, Japan and South Korea). In the past two years, however, the list of buyers has narrowed considerably.58 Effectively customers from only two countries are left – China and Japan. As the ESPO Blend draws new supply from different oilfields in Eastern Siberia, there are also concerns about the stability of crude oil quality over the long term. For these reasons as well as uncertainty over government policy and perceptions that the ESPO market could be influenced by political exigencies of Rosneft, a state-owned company, suggest that the spot trade in ESPO is unlikely to lead to independent price

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Middle East and Asia: the oil trade and pricing nexus  ­345 discovery. ESPO crude will most likely continue to be priced off Dubai price assessments. In 2012, the Shanghai Futures Exchange (SHFE) announced its plan to launch a crude oil contract based on a medium sour crude oil with specific gravity ranging from 30 to 34 degrees API and a maximum sulphur content of 2 per cent. The proposed contract would include the commonly spot traded ME crudes such as Oman, Dubai, Basra Light, Upper Zakum and Qatar Marine as well as Shengli, a domestic crude, delivered to specified locations in China. The Shanghai crude oil futures contract was initially planned to start trading on the SHFE. Since its announcement, the launch of the contract has been continually delayed.59 In 2013 the planned launch of the futures contract was moved to a new exchange, the Shanghai International Energy Exchange (INE) located in Shanghai’s new free trade zone. The contract was set to be the first Chinese commodities contract to be fully open to foreign investors, a landmark in the opening of China’s financial markets with tax incentives and promise of full convertibility of the yuan. In 2015, expectations rose that China’s first internationally traded crude futures would be ready to begin traded later in the year. According to the latest reports, however, the INE preparations may not be completed until year-end (2016), essentially pushing the launch date into the next year at the earliest. That Asian crude oil markets need is a genuinely Asian marker is a popular sentiment even among seasoned market participants. In this view, a shift of crude pricing benchmarks ‘eastward’ is a natural move given the shift in the centre of gravity in crude oil trading to Asia.60 A variant of this argument is that the sheer size of China’s oil market ‘is enough to justify its own pricing benchmark’. The scale of Chinese demand in global commodity markets can indeed lead to rapid growth in domestic liquidity on the commodity exchanges; for instance, the Dalian Commodities Exchange is home to the world’s first and third most actively traded commodity contracts (steel reinforcement bars and iron ore).61 China’s efforts in launching a crude oil futures contract seem to be geared towards having their commodity imports to be ‘priced as much as possible off of Chinese reference contracts whenever they can’.62 While the development of successful futures contracts requires both buyers and sellers to have confidence in the contract’s specifications and in the futures exchange that offers the platform for executing trades in the contract, it is also critical that governments provide an environment conducive to the operation of futures markets. In that context, the sharp sell-off in China’s stock market in mid-2015, followed by the government’s rushed regulatory shifts to reassert control over the market, dampened foreign interest in the INE sour crude contract. More recently, actions by

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346   Handbook of energy politics the country’s National Development and Reform Commission (NDRC) to rein in surging coal prices by administrative fiat again brought attention to the government’s reluctance to allow commodity markets to trade freely and openly.63 Crude oil pricing benchmarks are the outcome of market evolution, rather than the result of any policy push by governments in any particular jurisdiction. The status quo in Asian oil markets where the pricing benchmarks are discovered by PRAs seems to have shown resilience and a longevity that may seem surprising to some observers. But an appreciation of how the Dubai benchmark works as an integral part of global oil market pricing and risk management goes a long way in explaining the robustness of the Middle East crude oil pricing norms.

8  CONCLUDING REMARKS As the largest oil consuming region in the world, Asia occupies a central place in the planning and analysis departments of most state-owned or publicly listed corporations in the oil industry. Given that the OECD countries are already into, or facing impending, ‘peak oil demand’ in their energy outlooks, Asia is commonly seen as the major demand growth region for oil in the coming decades. In a context of low oil prices and robust production of unconventional oil in North America, the major crude oil producers in West Africa, Latin America and Russia are aggressively competing with the Middle East exporters for market share in Asia. Asian consumers, spoilt for choice in a buyers’ market after almost a decade of high oil prices, now actively look at spot purchases of crude oil from Latin America and even the North Sea, apart from their regular supplies from the Middle East, West Africa and Central Asia. West African crude oil, having dramatically lost market share in the US with the surge of light tight oil output as a result of the ‘shale revolution’, now faces static demand in Europe and an imperative to compete in Asia for incremental demand alongside other crude oil producers. Unlike the Atlantic Basin where crude reference prices (Brent and West Texas Intermediate) are discovered in liquid futures exchanges such as ICE and NYMEX, the Asian market does not have any traded futures contract for crude oil which serves as widely used pricing benchmark for sour crude. The reference Dubai crude price is, as already noted, discovered by PRAs such as Platts and Argus Media. While the role of PRAs in oil price discovery have been the subject of considerable debate and controversy, there seem to be no plausible alternatives. The current system of voluntary reporting of trades, bids and offers to PRAs, evolved since the mid-1980s at the end of the

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Middle East and Asia: the oil trade and pricing nexus  ­347 OPEC administered-pricing system in place previously, has proved resilient despite the many deficiencies emphasized by market observers.

NOTES   1. D. Yergin (1990) The Prize: The Epic Quest for Oil, Money, and Power, New York: Simon & Schuster.   2. This section draws primarily from chapter ‘Oil in Asia’, in S.C. Bhattacharyya (ed.) (forthcoming) Routledge Handbook of Energy in Asia, Abingdon: Routledge.   3. In the context of the global oil industry, the most useful geographical definition of Asia comprises countries east of, and including, Pakistan, tracing an arc around the Pacific Rim of the Eurasian landmass to Northeast Asia (China, Japan, South Korea and Taiwan). This geographical definition excludes countries in West Asia such as Afghanistan as well as the Central Asian republics of the former Soviet Union (FSU), all of which are minor oil consumers. In this definition, Asia includes South Asia (that is, the countries of the Indian sub-continent), Southeast Asia, Oceania (that is, Australia, New Zealand and the Pacific Islands) and Northeast Asia.   4. IMF (2016) ‘World economic outlook’, October.   5. BP (2016) ‘Annual review of world energy statistics 2016’.   6. Other well-cited long-range forecasts are published by the International Energy Agency (IEA), and the large oil companies BP and Exxon-Mobil. Their long run outlooks for regional fossil fuel demand are broadly consistent with each other.   7. Bloomberg News (2016) ‘Oil bulls beware because China’s almost done amassing crude’, 30 June.   8. BP (2016) ‘BP statistical review of world energy 2016’, June 2016, accessed 1 June 2017 at bp.com/statisticalreview#BPstats.   9. For instance, forecasts in the 1990s suggested that up to 95 per cent of Asian imports of crude oil would be sourced from the Middle East by 2010 (F. Fehsaraki, A. Clark and D. Intarapravich (1995) ‘Pacific energy outlook: Strategies and policy initiatives to 2010’, East West Centre Occasional Paper, March). 10. See for instance, C. Balding (2017) ‘Venezuela’s road to disaster is littered with Chinese cash’, Foreign Policy, 6 June. 11. Brent Blend crude oil, West Texas Intermediate (WTI) crude oil, US gasoline, US heating oil (gasoil) and US natural gas. 12. N. Hume and H. Sanderson (2016) ‘How is iron ore priced?’, Financial Times, 9 March, accessed 1 March 2017 at https://www.ft.com/content/aeaaddf4-e5de-11e5-a09b-1f8b0​ d268c39. 13. L. Bossley cited in G. Tett (2014) ‘Oil markets should heed Libor lessons: Setting of oil prices may come under similar scrutiny’, Financial Times, April 13; P. Verleger (2012) ‘Regulating oil prices to infinity’, 12 August, accessed 1 March 2017 at http://www. pkverlegerllc.com/assets/documents/120812_Regulating_Oil_Prices_to_Infinity.pdf. 14. This section draws primarily from T. Doshi and S. Six (2017) ‘Joint oil stockpiling between Middle East exporters and North East Asian importers’, available at www. kapsarc.org (April / KS-2017–DP06). 15. Kuwait, Iran, Qatar and Abu Dhabi are among the other Gulf oil producers using some form of formula prices for long-term contracts. Among the few Gulf crudes sold on the ‘spot’ market (that is, not based on term contracts with end-user and resale restrictions) are Oman and Dubai. For a full if dated description of Middle East crude exports and pricing in Asia, see P. Horsnell (1997) Oil in Asia: Markets, Trading, Refining and Deregulation, Oxford: Oxford University Press. 16. The sales invoice prices in crude oil sales agreements use quotes provided by the price reporting agency Platts, a division of Standard & Poor’s. This is unlike the situation in

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17. 18. 19. 20. 21. 22. 23. 24.

25. 26.

27.

28.

29.

30. 31.

the Atlantic markets of Europe and North America which have liquid exchange traded futures in West Texas Intermediate and Brent contracts which serve as the reference prices for Saudi and other GCC producers which export to the two major regions. The ports of Ras Tanura and Ras al-Ju’aymah on the Persian Gulf handles most of Saudi Arabia’s crude oil exports from the Gulf. Most of the remaining volumes are exported from the Yanbu terminal on the Red Sea. The GPW measures the total value of all the refined product processed from the crude and determines the crude oil’s refining value. In Asia, refined product prices quoted at FOB Singapore are taken as the reference prices for calculating the GPW of the crude oil. Crude oil delivered from the Saudi port of Yanbu on the Red Sea would be an exception. For a full description of how Platts assesses Dubai and Oman physical crude oil prices, see Platts website at http://www.platts.com/IM.Platts.Content/MethodologyReferences/ MethodologySpecs/Crude-oil-methodology.pdf. C. Aizhu (2016) ‘Update 1 – Aramco in first spot crude sale to Chinese teapot refiner – source’, Reuters, 25 April. H. Gloystein and F. Tan (2016) ‘Saudis open new phase in Asia oil market turf war with China spot sale’, Reuters, 27 April. S. Cho (2016) ‘Saudi spot oil deal in China seen by Citi a “dramatic’ shift”, Bloomberg, 26 April, accessed 1 March 2017 at http://www.rigzone.com/news/oil_gas/a/144194/ Saudi_Spot_Oil_Deal_In_China_Seen_By_Citi_A_Dramatic_Shift. While Middle East crudes in Asia are priced off reference Dubai crude prices, spot cargoes from West Africa, Latin America and the North Sea are priced off the Brent Blend prices. Russian ESPO crude sold FOB at Kozmino port in Russia’s Far East is sold on a Dubai related basis. This section draws on T. Doshi and A. Imsirovic (2013) ‘The “Asian Premium” in crude oil markets: Fact or fiction?’ in Z. Daoijong (ed.) Managing Regional Energy Vulnerabilities in East Asia, Abingdon: Routledge. See for instance, Y. Ogawa (2003) ‘Asian Premium of crude oil and importance of development of oil market in Northeast Asia’, paper prepared for international workshop on Cooperative Measures in Northeast Asian Petroleum Sector: Focusing on Asian Premium Issue, Seoul, Republic of Korea, September; Y-S. Moon and D-S. Lee (2003) ‘Asian Premium of crude oil’, paper prepared for international workshop on Cooperative Measures in Northeast Asian Petroleum Sector: Focusing on Asian Premium Issue, Seoul, Republic of Korea, September. For a critique of the concept of the ‘Asian premium’, see T.K. Doshi and N.S. D’Souza (2011) ‘The “Asia Premium” in crude oil markets and energy market integration’, in F. Kimura and X. Shi (eds.) Deepen Understanding and Move Forward: Energy Market Integration in East Asia. ERIA Research Project Report, March, accessed 1 March 2017 at http://www.eria. org/publications/research_project_reports/deepen-understanding-and-move-forwardenergy-market-integration-in-east-asia.html Y. Ogawa (2003)‘Asian premium of crude oil and importance of development of oil market in Northeast Asia’, paper prepared for international workshop on Cooperative Measures in Northeast Asian Petroleum Sector: Focusing on Asian Premium Issue, Seoul, Republic of Korea, September. Y. Ogawa (2002) ‘Asia oil price analysis 1: Middle Eastern crude for Asian market at comparatively higher levels and switchover of marker crude inevitable to gain market’s confidence’, Institute of Energy Economics, Japan (September), accessed 17 January 2012 at http://eneken.ieej.or.jp/en/data/pdf/133.pdf. C. Chiu and L. Pleven (2010) ‘Economic clout earns Asia an oil discount’, Wall Street Journal, 25 May, accessed on 17 January 2012 at http://online.wsj.com/article/SB1 0001424052748703341904575266913913683300.html?mod=WSJ_Markets_section_​ WorldMarkets. R. Soligo and A.M. Jaffe (2000) ‘A note on Saudi Arabian price discrimination’, The Energy Journal, 21(1), 121–33. R. Soligo and A.M. Jaffe (2004) ‘The future of Saudi price discrimination: The effect

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32. 33. 34. 35. 36. 37. 38. 39. 40. 41.

42. 43. 44. 45. 46. 47. 48. 49. 50. 51. 52.

53. 54.

of Russian production’, paper prepared for the James A. Baker III Institute for Public Policy Energy Forum, Houston, Texas. P. Horsnell (1997) Oil in Asia: Markets, Trading, Refining and Deregulation, Oxford: Oxford University Press, p. 305. T. Doshi and A. Imsirovic (2013) ‘The “Asian premium” in crude oil markets: Fact or fiction?’ in Z. Daoijong (ed.) Managing Regional Energy Vulnerabilities in East Asia, Abingdon: Routledge. C. Chiu and L. Pleven (2010) ‘Economic clout earns Asia an oil discount’, Wall Street Journal, 25 May. A. Raval and D. Sheppard (2015) “Oil futures plan fuels up China’s ambitions”, Financial Times, 17 September. R. Soligo and A.M. Jaffe (2000) ‘A note on Saudi Arabian price discrimination’, The Energy Journal, 21(1), 121–33. A phrase used by P. Horsnell (1997) Oil in Asia, Oxford: Oxford University Press H.E. Ali Al-Naimi (2001) ‘OPEC and the changing world energy scene’, OPEC Seminar. Vienna, September 5. Teo, K. (2004) ‘Big three to fight “Asian premium” on Saudi oil sales’, The Standard, 24 November. Ibid. B. Fattouh (2011) ‘An anatomy of the crude oil pricing system’, Oxford Institute of Energy Studies, January; A. Imsirovic (2014) ‘Oil markets in transition and the Dubai crude oil benchmark’, Oxford Energy Comment, Oxford Institute of Energy Studies, October. See A. Kwiatkowski and W. Zhu (2013) ‘EU oil manipulation probes shines light on Platts pricing’, Bloomberg, 15 May; R. Campbell (2013) ‘How to manipulate oil price assessments’, Reuters, 15 May. A. Makan and J. Blas (2013) ‘European Commission raids oil groups over price benchmarks’, Financial Times, 15 May; S. Forden (2013) ‘U.S. FTC said to open probe of oil price-fixing after EU’, Bloomberg, June 25. A. Hoffman and A. White (2015) ‘Oil traders spared as EU Commission drops pricerigging probe’, Bloomberg, 8 December. IOSCO (2012a) ‘Principles for oil price reporting agencies final report’, October 5, accessed 1 March 2017 at https://www.iosco.org/library/pubdocs/pdf/IOSCOPD391.pdf. IOSCO (2012b) ‘Functioning and oversight of oil price reporting agencies: Consultation report’, March, accessed 1 March 2017 at http://www.iosco.org/library/pubdocs/pdf/ IOSCOPD375.pdf. L. Bossley, quoted in A. Lawler and R. Mably (2012) ‘Oil price agency Platts too powerful, regulator told’, Reuters, 5 April. G. Tett (2012) ‘Oil markets should heed Libor lessons’, Financial Times, April 13. A. Imsirovic (2013) ‘Don’t blame PRAs for oil industry’s structural failures’, Letters, Financial Times, May 20. P. Verleger (2012) ‘Regulating oil prices to infinity’, August 12, accessed 1 March 2017 at http://www.pkverlegerllc.com/assets/documents/120812_Regulating_Oil_Prices_to_ Infinity.pdf. IOSCO (2012) ‘Principles for oil price reporting agencies: Final report’, October 12, accessed 1 March 2017 at https://www.iosco.org/library/pubdocs/pdf/IOSCOPD391.pdf. Among the few Gulf crudes sold on the ‘spot’ market (that is, not based on term contracts with end-user and resale restrictions) are Oman and Dubai. For a full if dated description of Middle East crude exports and pricing in Asia, see P. Horsnell (1997) Oil in Asia: Markets, Trading, Refining and Deregulation, Oxford: Oxford University Press. Data from ICE website for historical monthly volumes of contracts traded on the Exchange, accessed 1 March 2017 at https://www.theice.com/marketdata/reports/. It is assumed that a month has 22 working days on average. For a careful assessment of the DME Oman Futures contract and its outlook, see B. Fattouh (2008) ‘Prospects of the DME Oman crude oil futures contract’, Oxford

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55. 56.

57. 58. 59. 60. 61. 62. 63.

Energy Comment, March, accessed 20 August 2016 at http://www.oxfordenergy.org/ wpcms/wp-content/uploads/2011/01/March2008-DMECrudeOil-BassamFattouh.pdf. S. Fletcher (2009) ‘Aramco switches from WTI benchmark’, Oil and Gas Journal, 11 September. Among such attributes would be that the crude oil should be freely tradable (that is, with no restrictions on its resale), its spot trade should have adequate liquidity without dominant buyers or sellers, there should be adequate loading facilities with transparently set loading schedules agreed between buyers and sellers, and there should be a stable regulatory environment for trading the crude oil. See for instance, S. Hall (2011) ‘IEA: Russia’s ESPO crude may become an Asian benchmark’, Dow Jones Newswires, 18 January. F. Weber (2015) ‘Eastward shifting oil markets and the future of Middle Eastern benchmarks’, Oxford Energy Comment (Oxford Institute of Energy Studies), July. O. Yagova (2015) ‘Russia’s ESPO Blend crude still struggles in Asia-Pacific’, Reuters, December 30. Platts (2016) ‘Launch of China’s first crude futures contract pushed to late 2016’, 21 March, accessed 25 September at http://www.platts.com/latest-news/oil/singapore/ launch-of-chinas-first-crude-futures-contract-27373565. F. Weber (2015) ‘Eastward shifting oil markets and the future of Middle Eastern benchmarks’, Oxford Energy Comment (Oxford Institute of Energy Studies), July. H. Sanderson (2016) ‘Speculators march into China commodities’, Financial Times, 27 April. D. Ernsberger, quoted in A. Raval and D. Sheppard (2015) ‘Oil futures plan fuels up China’s ambitions’, Financial Times, 17 September. M. Meng and J. Mason (2016) ‘China coal fumble casts doubt on its global commodities pricing goal’, Reuters, 11 November, accessed 1 March 2017 at http://www.reuters. com/article/us-china-coal-idUSKBN1360GU.

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16.  The economics of the smart grid technological innovation

Luciano de Castro, Joisa Dutra and Vivian Figer

1.  INTRODUCTION The power system was recently described as a “central nervous system”1 and is in the midst of the digital revolution, driven by environmental concerns and rapidly evolving technology. The grid2 is evolving from a one-way power flow (from central station power plants to end-users) to two-way power flow on both transmission lines and local distribution networks. Multidirectional power flows enable the development of microgrids and on-site distributed generation (DG). The timescales of power balancing have shifted from daily to second-to-second to millisecond-to-millisecond. The demands of the modern electricity system will increasingly require innovation in technologies, markets and system operations (for example, balancing authorities). The technologies that offer two-way communications and intelligent controls allow for a range of electricity services related products that rely on computer-based remote control and automation, boosting the adoption of distributed energy resources (DERs). The core of the modernization policy for the electric grid is to ensure that the electricity system is reliable, resilient and secure, while environmentally responsible at a cost-effective way. Those are the pillars of the modern electricity agenda. Until the mid-1990s, electricity was produced and delivered to consumers by vertically integrated state-controlled monopolies (being the majority served by investor-owned utilities – IOUs), operating under cost-of-service regulation. From the 1980s onwards, mainly between 1995 and 2002 the industry went through major regulatory reform, or the “electricity restructuring.” The one-way power flow and consequently solid value of its product – electricity delivered – had protected utilities from disruptive threats. The 2001 California electricity crisis and increasing environmental concerns had shifted the focus of electricity policy as technology innovation and the two-way power flow changes the role of consumers in the value network and forces utilities to review its own value proposition. The power sector is going through a radical transformation and may be facing some disruptive threats, although it is still not clear which 351

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352   Handbook of energy politics i­nnovations will be disruptive. If the regulatory framework does not follow the transformation to provide incentives for efficient changing of the recovery paradigms the impact on utilities, investors and consumers will be adverse. Lessons should be learned by the deregulation in two other industries: airlines and telecommunications, which were also price regulated and capital intensive.3 New technologies that improve the performance of a product – whether radically or marginally – consumers already know and value are called sustaining technologies.4 They increase firm’s sales to their most profitable customers, or their mainstream consumers. While disruptive technologies “introduce a different package of attributes from the ones mainstream consumers historically value,”5 creating a new value proposition, and they generally underperform in the mainstream market in the short-term. Disruptive innovation, on the other hand, is an innovation that helps create a new market and value network. They are initially considered inferior by most in the mainstream market. Disruptive innovation shouldn’t be confused with major breakthroughs, even those that change the industry’s competitive patterns (Uber and Netflix).6 The disrupter begins targeting a neglected share of consumers by the incumbent, which in turns fails to realize the innovation process in course. Eventually, the advent of a novel technology or business model allows new entrants to move upmarket and challenge incumbents with lower costs (through a disruptive path). In a 2013 report,7 Kind argued that – probably given the low share of DERs in the national load – investors were not worried enough of the disruptive threat from these new technologies. As extreme weather events (climate change) are becoming more frequent, policymakers also seek for new technologies that allow for fast recovery from disruptions (higher resilience). Driven by climate change8 and the urge to decrease GHG emissions, allied with technological innovation, countries are increasing the deployment of renewable sources, especially solar and wind. The integration of intermittent resources will also bring more complexity for the operation of the system. It will change the overall management of the network, capacity expansion and planning, as well as the economics of the power system. The intermittency inherent to these new resources comprises two distinct features: high limited-controllable variability and unpredictability. It demands a more flexible response of the power system, highlighting the importance of ancillary services. Market rules and the regulatory framework should evolve to create an environment for a new business model for delivering these services. Flexibility in the generation resources, additional operating reserves, integration of balancing areas and enhancement of balancing markets, integration of

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The economics of the smart grid technological innovation  ­353 Demand Response (DR), storage technologies, Electric Vehicles (EV) and market rules will have to be thought together to guarantee lower operation cost, market price and system stability. Smart Grid (SG) technologies increase the visibility of the system and allow for better remote real-time monitoring and automation, data acquisition and analysis of the state of the transmission and distribution (T&D) system. For instance, advanced metering infrastructure (AMI – smart meters) combine meters with two-way communication c­apabilities, ­enabling a variety of dynamic pricing mechanisms and demand response programs. Those, in turn, can contribute in reducing the volatility of demand, the peak demand and the ability of suppliers to exercise market power. Another technology at the core of the smart grid that may change how requirements are set is the phasor measurement unit (PMU). This allows synchronized real-time measurements of multiple remote measurement points on the grid and will help balance supply and demand continuously at a lower cost upon the significant increase of intermittent generation on the high voltage network. Widespread connection of DERs also increase digital complexity and attack surfaces, raising data security, cybersecurity and privacy-related issues. As services become more digital and automated, power disruptions have greater consequences. To unlock the potential of smart grid (SG) technologies, industry and utilities need to prepare for management and analysis of the huge amount of data that can be collected every moment. The commoditization of information arises as a strong new activity. The ability to collect and transform the data into valuable information is at the core of the smart grid transformation and in the value network of new business models to arise. The new flow of information has the potential to be disruptive to many other sectors and the workforce within them, such as building design, public safety-related services and appliance makers. Increasingly widespread consumption data also raises questions over the ownership and privacy concerns. Regulators have a key role in guiding data access by researchers and industries and maintaining privacy and security of data.9 The regulatory framework has to be revised to become more adaptive, allowing the innovation process to be efficient, fair and transparent. Since investing in SG technologies can either decrease operating costs or increase power quality, it is crucial to understand how the costs and benefits will be split among stakeholders: SG is not just a physical structure, but one that encompasses a range of actors and needs.10 We discuss the smart grid, address how the policy and regulatory environment should embrace the technological changes to increase efficiency and security of the power system and the opportunities and challenges associated to the deployment

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354   Handbook of energy politics of smart grid technologies at the transmission and distribution network as well as at the end-use metering level.

2.  UNDERSTANDING SMART GRID 2.1  What is smart grid? The term “smart grid” refers to a wide variety of electric grid modernization efforts and ideas, being best described as the “expanded use of new communications, sensing, and control systems throughout all levels of the electric grid.”11 It means, “computerizing” the electric utility grid.12 The National Energy Technology Laboratory (NETL, 2009) defines five categories of smart-grid systems to describe this modernization (see also GAO, 2011): 1. integrated communications, including broadband and wireless communication 2. advanced grid components to improve system performance (smart devices such as switches, transformers, storage devices, and microgrids) 3. advanced control methods (including methods that automate distribution and locate or correct faults or potential faults) 4. sensing and measurement technologies that enable information flows from physical grid components to system operators and consumers 5. improved interfaces and decision support, which organize the information in item Smart grid technologies are categorized by the Department of Energy13 into customer systems (CS), advanced metering infrastructure (AMI), electric distribution systems (EDS) and electric transmission systems (ETS). Capabilities of the SG are: outage management; grid self-healing; DR; dynamic pricing; preventive maintenance of grid assets; integration of DERs and two-way communication between utilities and consumers. According to the DOE’s (2015a) Quadrennial Technology Review (QTR), technologies expected to have great impact over the next 25 years include: energy storage, distributed energy resources (DERs), variable generation resources (most notably solar and wind), electric vehicles (EVs), power flow controllers and information and processing technology.

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The economics of the smart grid technological innovation  ­355 2.2  Drivers Driven by environmental concerns – climate change, local opposition to building new power plants and transmission lines, particulate matter, acid precipitation, water use, land and ecosystem impact – the urge to decrease GHG emissions, technological innovation and decreasing costs, countries are experiencing the increased deployment of renewable sources (especially solar and wind) and DERs. This requires more fast-acting, finer control of distribution grid operations to integrate variable, intermittent generation resources while maintaining high reliability. Big companies have already announced their intentions to run operations largely on renewables.14 The DOE’s (2015b, 2017) Quadrennial Energy Review identifies as key trends of the electricity sector: the changing generation mix; low load growth; increasing vulnerabilities to severe weather/climate change; the proliferation of new technologies, services and market entrants; increasing consumer choice; emerging cyber/physical threats; aging infrastructure and workforce and the growing interdependence of regulatory jurisdictions. Costs for many of the emerging energy supply technologies (grid-scale batteries, solar PV, LEDs) have fallen during the last decade, although their competitiveness against conventional ones is still in progress.15 Although some believe that even without Obama’s climate regulation, state regulations may be enough for renewables to be competitive against coal.16 The cost of photovoltaics (PV) has declined by a factor of almost 100 times since the 1950s.17 Solar deployment (PV and CSP) has been growing steadily. From 2009 to 2014 the compound annual growth rate was 31 percent.18 Cost reductions of high-bandwidth communications systems are enabling more timely and granular information about conditions along power lines and within buildings.19 The number of homes in the United States with solar PV installations grew from 15,500 in 2004 to more than 600,000 in 2014, and represents more than 80 percent of the capacity added in the past four years.20 The GDP X energy growth has diverged significantly across countries. Among the OECD countries, growth in GPD was associated with a slight decline in primary energy demand for the period 2000–2014.21 Energy efficiency and the transition to a more service-based economy explain part of this trend. In less developed countries – although this trend is not yet happening – energy theft also disturbs this relation.22 Smart grid technologies can help address both technical and non-technical loss problem with its enhanced monitoring, communication and control capabilities. As levels of non-dispatchable resources increase, system operators have to maintain reliability while addressing the need for short, steeper ramps;

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356   Handbook of energy politics the potential for over-generation (curtailment is not readily achievable for some distributed generations) and decreased frequency response.23 When the sun is shining, demand for utility electricity is pushed down and as the sun sets net load rises very quickly the more solar PV is deployed. The California “Duck Curve” illustrates those new needs.24 Solar and wind are also not synchronously connected to the grid, in contrast to conventional generation, that may thus contribute to the system inertia as they can serve as baseload resources and as spinning reserves. This illustrates how the massive deployment of intermittent generation sources demands a more flexible response of the power system. We examine the impact of the penetration of Non-Conventional Energy Resources (NCER) and DG on operation of generation plants. We look at the more technical aspects related to the security of the power system (stress of the system, voltage and frequency control, stability) and the efficient use of generation to meet demand. We discuss how the smart grid can be part of the solution for power system stability through varied ­control capabilities of the smart grid.25 The adoption of new communication  – sensing and control systems – allows the ISO to have real-time information on every plant operating conditions, and better remote monitor and control remotely in real time the distribution system. Other technologies, such as automatic breakers and switches accommodate significant quantities of DGs efficiently and safely. Although technology already exists for that, regulators must be active in structuring the markets to welcome new business models that unlock its potential. The evolution of the grid rests on how stakeholders and the regulatory framework evolve to provide enough financial incentives for retail consumers and service providers to make the necessary investments in new technologies. The potential of smart grid is huge. It could reduce network operation and maintenance costs, improve reliability and resilience, integration of distributed renewable energy sources, accommodate demands for recharging of the electric vehicle of the future, expand the range of products that competing retail suppliers of electricity can offer, boosting competition and innovation in the retail sector. However, investments in smart grid technologies and its return lean on stakeholders determining the costs and benefits associated with integrating new services and technologies into the grid. It is important to understand how stakeholders and policymakers can efficiently value and integrate the services that new technologies can provide to the power system. It is not an easy task.26 Academics and policymakers are currently actively debating how to assign these costs of intermittency to specific generators to promote incentives.27 Deployment of ICT also requires policymakers to address privacy issues.

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The economics of the smart grid technological innovation  ­357 2.3  Challenges The present electric power delivery infrastructure was not designed to meet the increased demands of a digital society, with increased consumer participation and share of intermittent renewable power production. The power system of the present and the future has to integrate variable power from renewable energy resources that are located within transmission and distribution systems, the two-way power and communication flows, the participation of other actors other than utilities in generation of energy, advanced communications and control technologies, cybersecurity and physical threats magnified by the increase in extreme weather events. Energy policy, regulation and markets have to provide for incentives to unlock the potential of the smart grid to resolve the challenges posed by its own adoption and ensure electricity is safely and reliably delivered in a cost-effective way. Throughout this chapter we will examine this efficient/ optimal use. The increased deployment of DERs brings the challenge of integration. They have to be connected and integrated to the grid. Otherwise, its value is not realized (provide support for grid reliability, voltage, frequency and reactive power). Experience in Germany28 provides a useful case study regarding the potential consequences of adding extensive amounts of DER without appropriate collaboration, planning, and strategic development. Starting in 2000 a FIT program (for a period of 20 years) was set for solar power installations. In the meantime, electricity rates have increased. Increased production volume and technology advancements boosted adoption of solar PV in a self-reinforcing cycle. In addition, contrary to common sense, carbon emissions increased.29 For the sake of illustration, EPRI estimates that the cost of providing grid services for customers with distributed energy systems is currently about $51/month on average. In residential PV systems, for example, providing that same service completely independent of the grid would be four to eight times more expensive in the current configuration.30 In the absence of cost-effective storage, supply and demand must be balanced in real time. Further ahead, integration of all types of storage and other resources such as plug-in EV may become the most efficient way to counter the variability of renewables. Most analyses currently focus on the integration of renewables without the deployment of cost-effective storage on a large scale. The dissemination of such technologies will change with the diffusion of plug-in vehicles and the dissemination of cost-effective distributed storage, that will facilitate the demand and supply balance, and in the limit, electricity may be traded as other commodity. However, the important lesson to learn is the process per se – how stakeholders

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358   Handbook of energy politics navigate through this transformation, with possible disruptive technologies. As described in the DOE report,31 the grid of the future is a “tale of two timelines”: the building of a “smarter grid” with the deployment of valuable technologies within the very near future or present, and the longer-term promise of “a grid remarkable in its intelligence and impressive in its scope, although it is universally considered to be a decade or more from realization.” In addition, as the number of integrated intelligent assets increase, so will the speed of required communication, coordination and control. The increasing range of “subsecond” events requires, in turn, the management of “subsecond” decisions, humanly not possible. Thus, automated (machine-to-machine) intelligence will be required. The smart grid will likely need to evolve to a smarter grid to include machine learning to manage those requirements. The deployment of those technologies, however, faces multiple challenges, such as incentives to invest and privacy regarding the data produced. Policymakers have a key role in identifying and removing those barriers. In short, in order to take full advantage of the range of energy sources and technologies that can contribute to meeting climate change goals – such as energy efficiency; energy storage; electric vehicles; microgrids; renewable and clean energy generation – governments need to resolve institutional, regulatory and business model issues.

3.  BENEFITS The penetration of Non-Conventional Energy Resources (NCER) and Distributed Energy Resources (DER)32 should bring challenges but have also the potential to be part of the solution for power system stability through varied control capabilities. While the current state of technology already allows for that, regulators must be active in structuring the markets to welcome new business models that create the most value as providers of this type of services. Flexibility in the generation resources,33 additional operation reserves, integration of balancing areas and enhancement of balancing markets, integration of DERs and market rules have to be aligned to guarantee lower operation cost and system stability. Flexibility of the power system is in the core of the debate. It requires visibility into connected resources. Advances in information and communications technologies can to enhance system visibility, understanding and control in order to improve reliability and resilience. SG technologies, such as synchrophasors and smart metering allied with data collection, analysis and transparency can provide for the required visibility across

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The economics of the smart grid technological innovation  ­359 various dimensions: temporal; geographic; and analytical. It will improve evaluation of societal impacts, regulatory impacts, and of ­vertical industry boundaries. 3.1  Reliability and Resilience The grid of the future will need to adapt to new technologies, threats and vulnerabilities in cost-effective ways to reach the main general goal of energy policy in most countries: the security of supply at lower GHG emission rates in an efficient way and still affordable for economically disadvantaged users. The security of supply, in turn, rests on a reliable, resilient, safe and secure grid. For the purposes of this chapter, we borrow the definition of reliability from the Quadrennial Energy Review (DOE 2017, chapter 4): reliability is the ability of the system or its components to withstand instability, uncontrolled events, cascading failures, or unanticipated loss of system components. Resilience is the ability of a system or its components to adapt to changing conditions and withstand and rapidly recover from disruptions. Security refers specifically to the ability of a system or its components to withstand attacks (including physical and cyber incidents) on its integrity and operations.

The growing digitalization of the economy magnifies the damage of a grid power outage (data centers). The dependence of a country in a reliable and resilience grid is magnified as homes, business and communities integrate more automated systems and technologies into their activities. The digitalization increases the economic loss of even very short power outages. The 2003 Northeast blackout affected an estimated 50 million people (61,800 MW of electric load). Current estimates for the outagerelated costs that do not include extreme weather events range from $20 billion to $55 billion dollars in the US, and are increasing.34 Although EPRI already recognized that the economic cost of power outages is largely related to the length of the outage, digitalization strengthens this relation. However, although many metrics are available for reliability,35 it is hard to build a standardized measure for resilience.36 In the US, the threshold for an extended outage is five minutes, while in many European countries it is three minutes. Different metrics and different conditions (extreme weather occurrence) makes comparisons between power systems difficult. In addition, in the face of climate change, natural hazards, physical attacks, cyber threats, traditional measures of reliability based on the frequency, duration and extent of power outages seem to be incomplete to ensure system integrity and availability of electric power. It is especially

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360   Handbook of energy politics challenging to measure reliability in the developing world,37 where the efforts are usually highly concentrated in number of connections instead of power quality and reliability even though there is no evidence on how policymakers should direct their efforts. There is no established method for quantifying the benefits of SG investments regarding reliability and resilience, with the exception of New York.38 The provision of metrics and analytics to improve the grid’s performance is included in the Multi-Year Program Plan (MYPP) of the Grid Modernization Initiative (GMI) from the Energy Department (DOE, 2015c). 3.2  Visibility and Controllability As noted earlier, balancing supply and demand becomes more challenging as intermittent sources in the system increase. Although the undergrounding of distribution and transmission lines can contribute to improving reliability, it comes at a high cost.39 In some cases smart grid technologies can help reduce some of its costs. As most of the infrastructure of the power system in the US is aging, and components of the system are retired, it means that newer components – often linked to communications or automated systems – are gaining momentum. The incorporation of information-processing capabilities improves controls and operations monitoring, as the system can detect and alert system operators with better precision on the location of a problem. They contribute for an optimized generation, faster diagnosis of the state of the system, and better understanding of consumer behavior. Operators need to respond very quickly to changes in power flows at different locations on the network. As the changes in the power flow become more abrupt, operators need to hold more dispatchable generation in operating reserve status. SG technologies allow System Operators to better monitor and control adjust power flows on the T&D network to balance supply and demand at lower costs. Aligning with the propitious market configuration allows for a more efficient participation of other actors to provide electricity services. Since smart grid technologies in the transmission and distribution network allow for better monitoring and control, they will alter network requirements, such as reducing the reserve and contingency margin needs. In the Grid Modernization MYPP (2015) it was estimated that a drop from 13 to 10 percent in the average planning reserve margin that could be achieved through the deployment of modernization technology by retailers would result in a $2 billion annual saving to the economy.40

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The economics of the smart grid technological innovation  ­361 With the increased visibility and controllability enabled by SG technologies, a myriad of electricity services emerges. Services that contribute to increase the economic efficiency of the grid while maintaining the security of supply at a lower GHG emission rates if the proper incentives are in place. They include activities and products with commercial value that are procured by or on behalf of electricity consumers, and vary in their nature, format and economic implications.41 Demand and supply must be balanced at all times to ensure system reliability (frequency must stay within a narrow band). If markets and information were perfect and free-riding did not exist, consumers and agents would create contracts to insure themselves from sudden imbalances and the markets would clear at the price of operating reserves. Given imperfections and economic (dis)incentives, regulatory intervention is necessary to insure the system reliability. SOs set requirements to ensure that the power system operates within a certain limit. The definition of these limits and requirements (for example, the amount of needed operating reserve), and how those will be provided bring economic and engineering theory together. The need of each type of reserve (types of operating reserves depends on the quickness of response and length),42 ancillary services, firm capacity and black start will depend on the requirements for the system flexibility that should be align to the generation mix, forecast technology, and control capabilities and the state of technology in general.43 Regulators and System Operators have to be continuously updating such requirements as the power system is experiencing this incredible transformation.44 3.3  Distributed Energy Resources Distributed generation can provide backup power to the owner of the installation, and also provide power to the SO when needed if the correct incentives are in place. It can also be used as an alternative source of power if the owner wants to maintain its electrical use and still provide energy services through demand response services if regulation prepares for that. Demand Response (DR) has the potential to increase the volume of real-time flexible resources available, being very effective to support large-scale integration of variable renewable generation. While demand response shifts the timing of the response, storage has the potential to shift the timing of supply. As more behind the meter storage is deployed, regulators will be able to evaluate its impact on the power grid and consumer behavior. In the presence of Real Time Prices (RTP) rates, consumers or retailers may want to play the system, shifting demand through storage. Along with other DERs, DR can also provide multiple benefits for the

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362   Handbook of energy politics grid, such as the provision of firm capacity and ancillary services. For each type of DR pricing scheme (TOU, RTP, CPP, peak time rebates), the program economic impact and effectiveness relies on the adhesion policy, communication technology, market mechanisms and consumer engagement. The efficacy of the pricing scheme for reflecting the actual real-time supply/demand state of the market relies on the price interval (real-time, hourly or larger intervals) and on the lag between the announcement and implementation of prices. On the other hand, the more granular in time the price is, the higher the transaction costs for consumers. Consumers are an active and essential element of the smart grid, and the economic efficiency of the smart grid requires a comprehensive understanding of consumer types and behavior.45 The advent of the use of behavioral science alongside economic theory has provided many advances in this regard. Technologies enablers – smart grid and behind the meter technologies – can also play a crucial role in increasing the economic efficiency of the grid by reducing the transaction costs for consumers and reduce the trade-off between efficient pricing versus transaction costs. In the long term, the regulatory framework must aim at guaranteeing that market mechanisms provide demand response and energy efficiency enough opportunities (access, compensation and risk management).46 Policymakers’ efforts to increase investments to improve remote and automatic control of distribution and transmission networks (high and low voltage) must take into account general equilibrium results when large-scale deployment of these technologies are (to be) deployed. Disaggregated data on the appliance level, enabled by SG technologies (consumer-based technologies) would have the ability to diagnose overconsumption and detect faulty electronics that lead to overconsumption. It will allow for quick, automatic, inexpensive diagnosis, without the need for an on-site visit by a qualified electrician.

4.  COSTS, ALLOCATION AND INVESTMENTS Financial pressures and higher risks for investors adversely affect the availability of capital. It is imperative that stakeholders have a transparent signal of how will regulatory framework will deal with the recovery cost paradigm so that the financial markets can provide clearer signals to investors. Without fundamental changes in the regulatory framework, DESs may have an adverse effect on utilities’ revenues, investors’ incentives and prices to end-users. If, however, we manage to mitigate cross-subsidies and provide realistic price signals we can aim at successfully supporting implementation of DERs without overburdening other customers.

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The economics of the smart grid technological innovation  ­363 Uncertainty represents another barrier for investors. In addition to the natural uncertainty in an innovation process, investors have to cope with uncertainty from the political arena, with President Trump’s withdrawal from the Paris Agreement. Although some states and industries’ CEOs had announced their intention to keep pursuing a clean energy future, firms in states that have strict regulations to decrease GHG emissions may have a competitive disadvantage without the support of the federal government. Burger and Luke (2016) work on an empirical review of 144 distributed energy business models for solar PV, electricity and thermal storage and demand response, and can provide a comprehensive guide for business model (BM) options. They found that the regulatory and policy environment is a larger driver of BM structure than technology innovation. They also highlight that since BMs compete for the provision of the same electricity services, markets should allow for more competition. As the grid is modernized and new services arise along within the change in the generation mix, it will be essential to update interconnection standards and interoperability. Wholesale market and retail rate structures have to evolve to value both capacity and energy. The lack of consolidated, enforceable standards can be a deterrent to investment. The lack of a solid and predictable framework of standards can reduce investors’ willingness to take risks, since the prospect of needing to retrofit assets due changed standards turning them obsolete – reducing the benefit of a given investment. In a survey among project managers in Europe, the lack of interoperability between system elements was the most cited barrier for smart grid investments.47 In 2009, the US Department of Energy (DOE) launched the Smart Grid Investment Grant (SGIG) program, funded by $3.4 billion invested through the American Recovery and Reinvestment Act of 2009 (ARRA) to modernize the nation’s electricity system; see US Congress (2009). Projects began in 2010, and the program was completed in 2015. The ARRA has also been identified as a key funding source for storage projects. AMI investments have also been largely driven by state legislative and regulatory requirements, as well as ARRA funding.48 Other incentives for smart grid technology deployment for energy savings are energy conservation requirements; see FERC (2016). SG investments have the strength of a legal act, but they are not necessarily efficient, since regulators are not perfectly informed; that is, there is information asymmetry.

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364   Handbook of energy politics 4.1  Cost Benefit Analysis and Allocation Smart grid technologies are necessary as new developments require that the grid functions in ways for which it was never originally designed. As pointed out in an EPRI (2011) report, “the present electric power delivery infrastructure was not designed to meet the needs of a restructured electricity marketplace, or the increased use of renewable power production.”49 As rates increase with the deployment of smart grid technologies, cost benefit analysis is economically and politically important. Understanding the cost and benefits is as important as informing them. In addition, since different electricity generation technologies have different temporal and spatial production profiles, valuing the cost of intermittency is per se more complex than the levelized cost framework.50 Some researchers are addressing this issue.51 A cost benefit analysis should be capable of taking into account the benefits it brings to the system, such as avoided build capacity and impact on transmission, distribution costs, losses and environmental value. A better understanding of the full costs and benefits of the new services enabled by the SG will contribute to a fairer pricing structure. Currently, there is no transparent, broadly accepted framework, but progress is being made.52 As the DOE53 points out, it “will take time to adequately assess and validate the costs and benefits of the technology for utilities, their customers, and society.” Costs should be allocated according to benefits. The beneficiary-pays principle is not only fair, but also more efficient in determining whether an investment should be made. Those types of analyses of new technologies can’t be accurate ex ante. As smart grid technologies are deployed, more real-world data on its costs and benefits allow for an improved evaluation along with best practice. SG technologies have the potential to improve locational signals, and contribute to a more accurate allocation on prices and estimation of beneficiaries. However, large volumes of data require good tools and highly skilled workers for data management, visualization and analytics. This estimation process is per se costly. This highlights the importance on establishing a framework or guidelines for a continuous cost benefits evaluation. For instance, smart grid technologies may postpone or even avoid the construction of new transmission lines. Its cost benefit analysis has to take into account what are the benefits of the lines avoided. Additionally, the load benefits from increased reliability and less need of new lines (which would require costly investments). Other benefits include reduced reserve requirements, reduced energy losses, avoided project costs, improved

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The economics of the smart grid technological innovation  ­365 r­ eliability and improved access to generation resources. On the other hand, there are environmental costs from the construction of the line. Separate transmission charges and commercial transactions are allocated ex ante.54 As the deployment of grid-scale wind and solar generation in remote areas increases, the transmission grid becomes more interconnected. Therefore, the cost allocation problem is mutating. It requires continuous analysis and procedures for attracting the optimal amount and type of investment. All these points highlight the importance that detailed data on the bulk power system enabled by the new technologies should be made available to researchers. Of course, climate policy and other policy goals (to promote a specific energy resource, universal access) result in a certain degree of cost misallocation. Renewable energy policies (RPS, FIT and cap-and-trade) are a clear illustration. In this case, transparency and predictability is of paramount importance to reduce risks and misalignment of incentives. The costs and benefits of deploying a technology depends on scale and also on the time frame. Economy of scale and learning must be considered. Larger facilities can exploit economies of scale. Nemet (2006) found that plant size accounts for 43 percent of reduction in PV costs between 1980 and 2001. Popp (2002) uses patent data from 1970 to 1994 to estimate the effect of energy prices on energy-efficient innovations. He found a significant increase in patenting activity of around 2 percent resulting from the average change in energy prices.55 “Learning by doing” is the cost reduction of a given technology as deployment increases and experience accumulates. Photovoltaic modules have a demonstrated a 20 percent cost reduction per kilowatt with each doubling of production over the past 40 years.56 This brings up a chicken-and-egg problem for manufacturing: large volumes drive prices down but low prices are required to sell into the market to increase production volumes. R&D and government investment have a key role to play in the innovation process. Note that the previous analysis does not take into account the dynamic nature of the power system. An increase in solar PV systems may increase the cost of grid integration if the higher share of intermittent generation increases the demand for ancillary services (increased backup generation and reserves’ needs) and is not accompanied by other developments, such as the diffusion of demand response. In the longer-term, GHG ­emission targets also affect the cost of smart grid technologies. Large-scale integrated assessment models that take into account the evolution of the global energy system and climate goals to provide inputs for a longer-term assessment of DERs’ cost benefit analysis.57

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366   Handbook of energy politics 4.2  Workforce In the previous electricity delivery framework, utilities had to send workers out to gather the data (they read meters, look for broken equipment, measure voltage). Jobs in the electricity industry require a varied range of skills. With the transformation of the grid, the set of skills required are also changing. The new business models that are and will emerge within the transformation to a smart grid will also require a new array of skills: cybersecurity concerns demand a workforce that can build and manage cyber-physical systems. The flow of data requires a workforce with high technical skills, and the increased consumer participation demands an increased participation of behavioral scientists. One of the challenges facing the industry is the amount of time required to train new workers in response to fast changing industry needs. Another concern in the industry is retirement and the aging workforce (baby boomers and the shift from rural to urban areas).58 As already mentioned, solar deployment (PV and CSP) has been growing steadily. Changes in the workforce follow. From 2010 to 2015, the solar industry created 115,000 new jobs. By the end of 2014, 174,000 workers in the United States were documented as employed by the solar industry. In 2016 the solar workforce increased by 25 percent and approximately 374,000 individuals worked for solar firms.59,60 While over 1.9 million people are employed in jobs related to electric power generation and fuels, 2.2 million people are working in industries directly or partially related to energy efficiency.61 RPS policies are also affecting the workforce distribution. According to DOE (2017), RPS created 200,000 gross domestic renewable energy jobs in 2013. In addition, production and export of energy equipment represents a substantial market opportunity for the United States that would generate high-value jobs. The United States is the world’s largest producer and consumer of environmental technologies: in 2015, the environmental technologies and services industry employed 1.6 million people. The Paris Agreement and increased concern with climate change will likely boost these figures.

5.  WHAT ARE THE UTILITIES OF THE FUTURE? Traditionally, utilities managed a predictable system in terms of the supply and demand of electricity with one-way flow from large, centralized generation plants to customers. The current and future delivery structure have to handle variable power from renewable energy resources that are

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The economics of the smart grid technological innovation  ­367 intermittent and located within transmission and distribution systems. The two-way power flows from DERs, the active management and generation of energy by utility customers and other providers, and advanced communications and control technologies that will be more exposed to cyber and physical threats with increase the potential damage that a digitalized economy/society will face. As DERs penetrate the system and DR and energy efficiency programs reduce the electricity demand growth, traditional utilities will play a significantly different role, and a disruptive change in the generation and electricity delivery business is likely to happen. The two-sided flow of information and communication presents a huge potential for being disruptive to the current utilities. The smart grid technologies enable consumers to become also suppliers, more environmentally friendly and increase their ability to understand and control its electricity usage (and consequently its bill). Coupled with the current trend (and threats of climate change), electricity users are becoming more environmentally friendly. Consumers are now demanding other sources of value besides electricity. As their value proposition evolves, so do governments’, whose preferences are interdependent with consumers’ (voters): currently, the uptake of EV and renewables is largely driven by government policy. In this scenario, what will be utilities’ value proposition? As the two-way power flow changes the role of consumers in the value network, firms have to change their value proposition. There are many ways that the new technologies could alter firms’ value proposition: integration of demand response improves balance of supply and demand, energy efficiency-related services allow consumers to decrease their bill and feel better about the environment, integration of DERs provide electricity firms with access to sources of power generation cheaper than fossil power plants. While the smart grid threatens the current business model focused on selling electricity at the lowest cost based on scale economies, it enables the integration of DERs. Besides the possibility of reducing operating costs, it also allows them to create value and respond faster to the new environmentally friendly consumers and policy requirements emerging and in transition. The traditional utility business models rely on continued demand growth, steady economic returns and long payback horizons. The current industry structure with long-term (up to 30 years in some countries) cost recovery of investment is becoming vulnerable to cost-recovery threats from these disruptive forces. Despite the loss load due to energy efficiency and DERs that could be better handled through changes in the tariff structure,62 some argue that this would hinder incentives for innovation

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368   Handbook of energy politics by discouraging adoption of new technologies and consumer behavior focused programs. The pace of technology changes and the uncertainty typical of an innovation process makes it especially hard to reconcile in an industry with a 30-year cost recovery of investment. It is uncertain if and when DG customers will disconnect from the grid. If the current recovery paradigm is not broken, a perverse cycle can harm utilities (as experienced in the telecom and airline industries). As DER penetrates the network, (traditional) end-users become able to control their consumption and become a supplier to the utilities. The latter however are still responsible for maintaining reliability and security of supply, providing interconnection and backup supply for variable resources, creating an additional burden on them that they pass on as costs to all consumers. This leads to higher utility rates, which in turn promotes a greater adoption of DERs, pressing the rates even more. There is much concern with the so-called “death spiral of utilities”:63 as the cost of renewables decreases, more customers leave the grid (or consume less from the grid while putting energy back into it). This pushes up grid costs for the remaining customers. Some of them will then leave the grid too, and the relative cost of producing energy versus consuming from the grid decreases even more. Realizing the high risk, investors will require a higher rate of return, and the increased cost of capital pressures rates even more. The cost-recovery paradigm that forces the cost to be spread over all consumers would expose non-DER consumers to increasing prices. This can trigger social and political pressure to keep electricity prices artificially low – a movement that can be legitimated at the policy level. If it is not predictable how the government would react, utilities may become too exposed. Utilities are well positioned to compete to turn into distribution platform providers as the grid changes from one-way to bidirectional power flow to accommodate DERs and alternative business models. They are uniquely positioned to collect the data, their future core business may rely less on installing the SG devices (smart meters, batteries, solar PV) and more with their connectivity. However, electricity firms should be investing in skills to make sense of big data and prepare for new players and possible disruptive and innovative business models that may emerge. Big data can be produced by the SG, to be used or sold, enabling for a myriad of new services. This trend is already in motion: New York and Illinois started the process to allow utilities to capitalize investments in cloud-based software solutions, and the National Association of Regulatory Utility Commissioner (NARUC); issued a resolution declaring “utilities need to make the best

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The economics of the smart grid technological innovation  ­369 software procurement decisions regardless of the delivery method or payment model.”64 The New York REV Track 2 order65 highlights the recognition and efforts by governments (regulators) to better align utility shareholder financial interests with consumer interests. It acknowledges system and energy efficiency must be at the core of the utilities business. Although utilities are still natural monopolies, their revenue streams must be tied to customers’ needs. Utilities will have to operate the system by providing “distributed system platforms” to welcome third-party service providers (DER providers). The commission have been working to provide guidance for the transition.

6. HOW THE SMART GRID IS CHANGING THE ELECTRICITY DELIVERY SYSTEM 6.1  Transmission System SG technologies have the potential to improve real time monitoring and control of the high voltage transmission network. It increases the effective capacity of the high voltage grid by reducing contingency-related congestion, and improves the network operator ability to respond to rapid and higher swings in the power flow that result from a higher diffusion of intermittent resources. Phasor measurement unit (PMU) is one of the technologies at the core of the smart grid discussion. It is a device that measures the electrical waves on the grid using a common time source for synchronization, which allows synchronized real-time measurements of multiple remote measurement points. The resulting measurement is known as a synchrophasor. In short, it increases the visibility and awareness of the grid condition in shorter time frames, allowing operators to identify and correct for system instabilities, such as frequency and voltage oscillations. They provide data 100 times faster than conventional technology.66 PMUs can detect the phaseangle separation, an indicator of grid stress. They form the foundation for advanced applications, such as wide-area situational awareness and state estimation, system dynamics monitoring, system model validation, and in the near future, automated response-based controls.67 However, the density of PMUs has to be high enough to provide visibility of the entire network. Improved visibility can prevent blackouts such as the 2003 Northeast blackout that cascaded across eight states and two Canadian provinces. According to investigators of that blackout the limited visibility was one of its main causes.68,69 This same report70 recognized that many

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370   Handbook of energy politics of North America’s major blackouts have been caused by inadequate visibility of the grid, which can be improved by the deployment of PMUs. Under the 2009 American Recovery and Reinvestment Act (ARRA), DOE supported the deployment of more than 1,300 PMUs in the US. Before the ARRA, the transmission grid had fewer than 166 PMUs.71 By 2015, there were more than 1,700 networked synchrophasors providing visibility into transmission systems that serve about 88 percent of total US load. Although it receives a small share of the ARRA funds, according to EPRI estimates, investments in high voltage transmission networks is the most cost-effective smart grid investment. High voltage transformers are critical to the grid and represent one of its most vulnerable components. Other benefits of the rapid deployment of PMUs upon the Smart Grid Investment Grant in ARRA are the rapid identification of failing these transformers, which can also help preventing outages. PMU data can also be used to detect a malfunctioning automatic voltage regulator controller in one generating station and failed power system stabilizers, as the New York Independent System Operator (NYISO) has experienced. The Independent System Operator of New England (ISO-NE) can now automatically collect and analyze synchrophasor data from PMUs all across the region, enabling engineers to analyze two or three events per week (up from two events per year).72 Some events are too fast for human response. As data management capability improves and interventions can be automated, more outages will be avoided. The 2011 Southwest blackout, for example, may have been one of them. Cascade outages in the Pacific Southwest left approximately 2.7 million customers without power, some for up to 12 hours.73 The loss in the T&D system was about 6 percent from 2000–2012.74 The rapid deployment of intermittent sources is producing power flows that the grid was built to accommodate, and increases system congestions. Over the last decade, annual congestion costs ranged between $529 million and more than $2 billion in PJM.75 According to a DOE report,76 information technologies and operational strategies can help grid operators reduce losses. The same DOE report states that superconductors and power flow control technologies can reduce transmission loss by 50 percent or more, while the distribution system, reducing overloading lines through reconfiguration have identified loss reductions of up to 40 percent. The incorporation of EV charging in the dispatch algorithm also have the potential to reduce loss. Other transmission smart grid technologies are Microprocessor Based Protection, Digital Disturbance Recorders and Intelligent Electronic Devices.77

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The economics of the smart grid technological innovation  ­371 Congestion margins are also higher when the local system operator cannot see the state of a neighboring network, and therefore, has to be prepared for even more unanticipated events. The differences of transmission pricing and wholesale markets rules and design also increase transaction costs for the power flow between transmission networks. The SG technologies that increase the network visibility and allow for more rapid communication can improve the cost of this power flow. 6.2  Low Voltage Network The distribution system is the most expensive part of the electricity delivery system and most difficult to upgrade and approximately 90 percent of outage minutes originate on the distribution system.78 The deployment of SG technologies also increases the visibility and response capabilities. These technologies include automated feeder switches, capacitor ­controllers, fault indicators, throw-over switches and network protector monitors.79 Integrated with sensing, communications and control technologies, they also have the potential to increase the reliability and resilience of the grid, by automatically locating and isolating faults, dynamically optimizing voltage and reactive power levels, and better monitoring of the asset conditions. Equipment health monitors can measure temperature, voltage and the levels of other parameters in transformers and other devices, giving utilities a higher level of visibility. They can help utilities reduce costs by optimizing the need for infrastructure repairs (no need for meter readers and manual disconnects). By dynamically optimizing voltage and reactive power levels, utilities can reduce power loss and deliver electricity at a lower cost. Conservation voltage reduction (CVR) also helps reduce peak demand. The result is fewer unpredictable outages and higher-quality power. The report found that CVR could result in savings of 2–4 percent on affected feeders system-wide. Investments to increase the power quality of the grid can have an overall benefit higher that the cost. According to EPRI’s estimates,80 the deployment of technologies on the local distribution systems would cost one fourth of its overall estimated benefits. However, consumers value power quality differently (those on medical equipment, data centers and so on) and it may be more efficient to install equipment on those customer premises than making large investments on the distribution network. This would be more aligned with the beneficiary pays. Although efforts are still in the early stages, the DOE’s Smart Grid Investment Grants helped install thousands of automated feeder switches and capacitor banks. They also installed power line and equipment health sensors that have shown the potential to reduce the frequency and

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372   Handbook of energy politics duration of outages, as well as to reduce energy requirements by using automated controls for voltage and reactive power management. For example, the city of Chattanooga was able to instantly restore power to half of the residents affected by a severe windstorm on July 5, 2012 (from 80,000 affected customers to less than 40,000 within two seconds) using automated feeder switching. The uncertainty on the geographical distribution of the DG and its demands challenges the planning and operation of distribution systems. The distribution network will be required to accommodate increasing amounts of intermittent output from distributed generation resources that causes rapid variation in the demand on distribution feeders. In this case, how could regulation allow for the “cost causers” (owners of PV-DG) to bear most of the costs? Automation to upgrade distribution systems should consider DG penetration and diffusion (PV, batteries, plug-in EV)  – and the resulting load placed on the system when choosing the targeted feeders. Another challenge is how to provide price signal granular enough to account for large variations of electricity and electricity services usage. For example, in areas with a higher EV penetration, the peak demand may be late at night, when wholesale prices are low. This may place a stress on the local distribution network (which translates into a high cost) if EV owners are concentrated in a few distribution feeders. As discussed earlier, many portions of the US electricity infrastructure (and especially the lower voltage distribution network), are aging and need to be replaced.81 This presents a good opportunity to invest in new (and cutting-edge) technologies, since replacement investments are long-lived. But because they are long-lived, the issues raised earlier are of paramount importance when choosing how to target these investments in an economically efficient way. Advanced communication systems with intelligent devices such as smart meters, digital controls, switches and sensors also contributes for outages managements. Advanced Metering Infrastructure (AMI) comprises smart meters, communication networks and information management systems, and it can help utilities better and faster identify an outage and disruptions, without having to rely on customers to identify flaws in the line and delivery system. However, the most praised contribution of AMIs is their ability to provide customers with information on their electricity usage and real-time pricing, helping them to manage their energy consumption more efficiently. Customer-based technologies (we also refer to them as enablers) – including in-home displays (IHD), programmable communicating thermostats (PCT), direct load control devices (DLC), building energy management systems for commercial and industrial customers

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The economics of the smart grid technological innovation  ­373 – combine with AMI to magnify its benefits. We will review in more detail the enormous range of possibilities enabled by AMI and customer-based technologies in providing the grid more flexibility, and the myriad of new business models that may arise. There are around 58.5 million smart meters installed in the US, which represents more than 40 percent of electricity customers.82 Among them, more than 16.3 million smart meters were deployed by SGIG utilities from 2009 to 2015 with the ARRA. The SGIG final report states that the SGIG installed nearly 82,000 intelligent devices to upgrade about 6,500 distribution circuits. According to the report, utilities reduced the average number of affected customers by as much as 55 percent and reduced the duration by up to 53 percent using FLISR capabilities.83 Those improvements also reduce utilities costs. The report also presents estimates on utilities savings and measures for improvement in resilience indexes (SAIDI and SAIFI) by upgrading distribution systems. Deploying AMI with residential customer technologies can also reduce electricity demand during peak periods, resulting in more efficient use of the T&D infrastructure and investment in system replacements and upgrades. Oklahoma Gas & Electric observed up to 30 percent peak demand reduction for customers enrolled in its variable rate program.84 To maximize the benefits from those technologies, further advancement is needed in the management of these data. The high frequency of data, and short-time frame for response and analysis requires automated, coordinated and system-level control that is still at the academia level (research).85

7.  MARKETS AND POLICY Traditionally, grid operators have procured reserve generation services and charged it to the whole system, dividing the costs across all generators. Prices cannot reflect the time-varying value of power.86 In vertically integrated markets with low intermittent generation sources this was not such an important issue, since the utility could internalize the externalities created by intermittency. Within the current market configuration, however, the failure to assign the costs of intermittency to specific generators can distort incentives. The efforts to modernize the transmission and distribution networks and build the smart grid should be aligned with retail and wholesale market rules for better integrating demand-side management and other DERs into energy, and electricity services markets. SG technologies

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374   Handbook of energy politics requires but also contribute to a better alignment of costs and prices of electricity. According to the IEA, “there is little doubt that electricity markets are needed.”87 For instance, the Chilean solar market, has been increasing very fast without any explicit tax on carbon or subsidy for renewables and in spite of low electricity prices and limited transmission capacity in part due to a free, transparent market. Generally speaking, decentralization requires prices. As the number of DERs increase, SOs may no longer centralize all the necessary information. Therefore, electricity prices will have a key role to play in ensuring decentralized coordination. Short-term markets are important to provide a more accurate signal for the real value of electricity. It allows market players to better manage volatilities in production and provides incentives for a more efficient adoption of DERs. A regulatory framework for the participation of other players in the ancillary services provision should also be design. FERC Order 825, issued in June 201688 establishes settlement interval and shortage pricing requirements for organized markets for better aligning settlement and dispatch intervals and to reflect the shortage condition. This is in order to compensate resources more accurately at prices that reflect the value of the service provided to the system. The price of ancillary services should be the cost of the marginal resource providing the ancillary service in general, which also includes the lost opportunity cost from forgoing the energy market or other ancillary services markets.89 Regulation should incorporate this if other actors are to participate in this market and new business models for DG, DR and DS will emerge to provide for electricity services other than energy. In the long term, the regulatory framework must aim at guaranteeing that DERs have comparable market opportunities to level the playing field. This means comparable access to markets, comparable compensation and fair and reasonable risk management.90 There should be no functional difference between a megawatt of power from a power plant and a megawatt of reduced power from efficiency or demand response (as it is in PJM’s Capacity Market).91 Economists should work alongside network engineering – responsible for the definition of physical network requirements standards – to design market mechanisms and provide investment incentives for the efficient adoption of smart grid technologies. They should improve the remote monitoring and control and automation of the network (distribution and transmission) as well as in technologies located in the consumer premises (smart meters and its communication capabilities). Control and regulation over wholesale prices and retail prices are among the main causes of preventing efficient pricing.92 Market mechanisms, on the other hand,

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The economics of the smart grid technological innovation  ­375 may not provide a fast enough response to unanticipated imbalances in supply/demand to achieve the network’s physical operating parameters in all contingencies. Until recently, reliability planning and operating standards and requirements set by network engineering were defined in a parallel independent process to the design and evaluation of alternative market mechanisms. As pointed out by Joskow (2008), “reliability standards and emergency protocols established by engineering have to be integrated into wholesale market mechanisms.” The transition to the smart grid will also address failure of wholesale markets to provide adequate revenues to build new generating facilities to match forecasts of resource needs and help estimating consumer real marginal valuation for lost load. Electricity markets cannot optimize blackouts: there is no competitive market price during blackouts, and market mechanism cannot capture the cost of catastrophic blackouts and network collapse. Since market mechanisms in general fail to capture the expected social costs of a network collapse (because they also collapse upon a network collapse), Joskow and Tirole (2007) argue that operating reserves have a public good nature. As a result, the efficient level of operating reserves is under-provided by market mechanisms, requiring regulatory action to complement it. See also the discussion of related economic matters of de Castro and Dutra (2013). The need for capacity market stems from several market failures. Its fundamental purpose is to provide the amount of capacity that optimizes the duration of blackouts. This is the resource “adequacy problem” (Cramton et al., 2013). The root cause of the RA problem is a pair of demand side flaws which make it impossible for the market to access, even approximately, the value placed on reliability by consumers (Cramton and Stoft, 2006). One of the possibilities enabled by the SG is the huge amount of data for understanding consumers’ preferences and estimating the VOLL. As consumers take more market actions through participating in electricity services markets enabled by the SG. Energy policy and regulation has to take into account its effects on the market. Californian power plants are estimated to be able to produce 21 percent more electricity than needed by 2020,93 and retail electricity prices have been reported to be 50 percent higher than the rest of the United States.94 California renewable portfolio standards (RPS) requires all firms (utilities and retailers) that sells electricity to end-users to procure an increasing fraction (33 percent by 2020, 50 percent by 2030) of this energy from renewable sources. As an increasing amount of low marginal cost energy is entering a wholesale market that already has enough energy, it pressures wholesale prices down. To support the cost of the excessive generation the gap between wholesale and retail prices increases. This

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376   Handbook of energy politics illustrates the need to think the overall modernization policy altogether. The challenge is to redesign power markets to reflect the new needs for flexibility realizing new customer demands. Incorporating externalities on prices is a hard task and subject to an ongoing debate. Economists agree that free market is not suffice to address the environmental damages of GHG emissions.95 Pricing GHG or subsidizing green power, Feed-in-Tariffs (FIT) can be politically acceptable, but they have their drawbacks. While a carbon price increases prices in electricity markets, renewables policies and energy efficiency policies can have the opposite effect of reducing wholesale electricity prices. Pricing GHG helps all low-carbon alternatives without “putting a thumb on the scale”96 on technologies that are still being developed and there is a lot of uncertainty regarding which one will be socially better. The increased use of renewables increases low-carbon generation, the cap on emissions becomes easily achieved and cheap coal power plants could displace less pollutants than more expensive gas ones. The transition to decarbonization is also challenged (or enabled) by politically motivated actors. One of the drivers of the smart grid transformation, the environmental regulations, have faced enormous political opposition. Some politicians97 have referred to environmental regulation as “job-killing.” However, empirical evidence doesn’t corroborate those claims.98 President Trump did  promise that upon taking office, he’d “rescind all job-destroying Obama executive actions . . . including the Climate Action Plan.”99 On June 1, 2017 he announced his decision to pull out of the Paris climate accord. The process to exit the accord is not immediate and some analysts believe states and industries may take the lead to pursue the goals of the treaty in any case.100 7.1  Allocating Costs and Benefits to Value DERs – Recent Developments The deployment and integration of DERs brings the system costs and benefits. Factors that influence the value of DERs include loss reduction, voltage control, investment deferral, environmental benefits, reliability and resilience. They can vary based on the size and location, and have to be taken into account. Although policy in general had not kept pace with the speed of technological innovations, this is changing as more states increase their efforts to enable the deployment of new technologies and grid modernization. The majority of the reforms had been on the transition to a default timevarying rate for residential consumers.101 Although not expected to happen in the shorter-run, large-scale deployment of energy storage can bring disruptive changes to the power system.

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The economics of the smart grid technological innovation  ­377 Their rapid response capability makes them suited for frequency regulation and primary reserve, thus a strong competitor for ancillary service provisions. On a very large scale it can even provide electricity to the grid and displace other plants. Regulation and energy policy has to provide the correct incentives and rates to allow enough revenue streams over their working lives. Although the increasing need for flexibility creates market opportunities for storage, its high costs and the difficulties associated with quantifying the value of the array of services it provides is a major barrier. Some states are moving forward in efforts to provide a sound regulatory environment for welcoming a smarter grid.102 California is currently debating special rate structures for residential, commercial and industries to invest in solar PV, storage and EV. Rates with large price differentials between peak and off-peak time may hurt consumers that cannot change their consumption pattern, but may also provide financial incentives to investing in batteries for a solar PV installation or in a solar PV with storage. The options are being debated in the general rate cases (GRCs) of the state’s investors owned utilities. Demand charges are also under debate and highlight the conflicts between the industry and utilities.103 On March 1, 2017, Arizona Public Service (APS) and solar industry representatives reached a rate design settlement104 (to be approved by the Arizona Corporation Commission (ACC)) in which rooftop solar customers will be able to choose from four rate designs and demand charges are not mandatory, as originally requested by APS. Whatever the optimal rate design for overall welfare, it is an important step as it provides more policy stability for solar PV installers. New York State had established a 50 percent clean energy goal within their “Reforming the Energy Vision” to “transition from the historic model of a unidirectional electric system serving inelastic demand, to a dynamic model of a grid that encompasses both sides of the utility meter and relies increasingly on distributed resources and dynamic load management.”105 The commission issued the Value of Distributed Energy Resources order establishing the rates – called the new “value of distributed energy resources” (VDER) – consists of the value of energy value, a capacity value, an environmental value and the market transition credit (MTC). Although they still need to clarify the methodology for calculating them, the uncertainty surrounding the “detail” is natural in any innovation problem, and is to be minimized if there is institutional safety backing the process. Although the commission hadn’t moved away from the netmetering, it does clarify its intention to do so, as the PSC notes that retail rate net metering is “unsustainable” over the long term in New York.

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8. UNLOCKING THE POTENTIAL OF SG TECHNOLOGIES 8.1  DG Solar Solar PV plants can be installed much faster than other generation technologies. As discussed earlier, if there is a quick deployment of intermittent generation in the power system that was not adapt to incorporate it, the environmental impact and cost of electricity could be magnified. As is the case for residential consumers’ DR, many opportunities arise from the possible gains of aggregating residential consumers. The output variability of one plant is much higher than the variability of many dispersed plants – this is spatial diversification (Holttinen et al., 2013). Diversification and on-site generation contribute to a more resilient grid. The power of many small plants to improve resilience is magnified if the location and types of installation are defined in order to do so (each individual does not take into account the externalities and contribution from each own PV, only the private benefits). Thus, the aggregation of several plants can bring many benefits and a business opportunity. Welcoming this type of business model also helps avoid the problems that arise with a rapid deployment of solar PV installations. One of the major barriers to PV adoption is the high capital costs for production and installation. There is still much to be done in terms of regulation and policy to incentivize efficient business models involving financing the installation of panels, under direct or third-party ownership. These new business models create an opportunity for investors and project developers, helping overcome the difficulties that we currently face to boost installation. The new business models that will arise depends on the fiscal incentives for installation, and market rules for the electricity produced on-site. Customer-side business model requires a more active management of customer interface. Utilities’ knowledge of their consumers puts them in a privileged position to take advantage of climate policies to provide options for DER uptake. A recent solar consumer survey exposes many possible directions:106 solar customers are willing to help their community and contribute to the environment, even at cost; and are interested in connecting to the grid as a source of backup power and are willing to pay for it. In addition, 43 percent of people said community solar or green power plans were their preferred solar option, not rooftop PV. Utility-side business models  are also evolving alongside government clean energy policies. One type of existing business involves community solar providers installing large solar PV plants away from customers, who

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The economics of the smart grid technological innovation  ­379 can buy the rights to a portion of the energy of the plant. The business charges the consumer a brokerage fee and sell the output under a longterm PPA to the regulated utility (see the Nexamp in the USA). Long-term PPAs for solar energy is used for the development of utility-scale PV finance and installation business model, where large-scale solar businesses sell the energy through PPAs and sell the renewable energy credits to a third party in the presence of a renewable portfolio standards policy. Designing the incentives to properly remunerate solar plants is one of the main challenges faced by regulators. Researchers and regulators agree that the current net metering policies (retail net metering – RNM), where consumers are paid almost the full retail price for the energy exported into the system distorts price signals and creates cross-subsidies in favor of PV-DG users.107 It also distorts the social value of solar relative to other renewables.108 In fact, estimates show that these subsidies are socially regressive.109 Under RNM policies the PV-DG consumers export to the grid when there is excess solar energy produced and receive the full retail price, without regard to the fixed cost incurred for the distribution infrastructure (PV-DG owners do not incorporate distribution and transmission costs). In contrast to wholesale net metering, RNM is also structured with no regard to when and where (in a more granular level) the energy is produced, thus it does not provide an accurate price signal to customers. The economic inefficiencies of this policy were not a concern when the penetration of PV solar was very low and a better policy was not feasible due to meters with very little capability. In addition, implementation is administratively and technically simple. However, the perverse economic impact of increased deployment of DERs and technical improvements are leading many states to review this policy.110 Understanding the whole cost structure of providing electricity to end-users is the first step to efficiently allocate it. It requires assessing the cost structure, estimating the benefits for each agent and the system (which encapsulates the energy value, capacity value and reliability) and allocating it efficiently to provide incentives for investment, and for a smart use of electricity in alignment with environmental needs. Economic regulation should aim to allocate costs to beneficiaries as much as possible – to recover investments. The flat rates and price signal distortions of RNM provides incentives for panel users to maximize quantity produced regardless of the time of the day. A curious outcome of this policy is the inefficient installation of panels: if solar were paid at a time-variable rate, solar panels in the USA would generally be installed facing west, instead of south.111 Of course, estimating the beneficiaries and cost causers is no easy task.

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380   Handbook of energy politics Regulators and industry players should be aware of the importance of gathering data and making it available to researchers. Another (necessary) challenge is to estimate system-wide impacts: on prices (volatility and level), on competition and on job creation (direct and indirect – for instance, through the effects on the pricing structure). Although sometimes distortive policies may be justifiable for boosting a nascent technology short-term, as was the case for solar PV, regulators should have in mind that profits must be earned, not guaranteed. It should still provide incentives for producers to become more efficient and attain grid parity. 8.2  Demand Response According to the Federal Energy Regulatory Commission (FERC), DR can be defined as “changes in electric usage by end-use customers from their normal consumption patterns in response to changes in the price of electricity over time, or to incentive payments designed to induce lower electricity use at times of high wholesale market prices or when system reliability is jeopardized.”112 Management of electricity consumption in response to dynamic- and location-varying spot price can reduce the peak demand and volatility of demand (and prices) and the ability of suppliers to exercise market power. It can provide the grid with the increased flexibility required to integrate intermittent energy resources and reduced costs through peak capacity reduction. The deployment of DEGs close to load centers combined with DR can also contribute to the system reliability by aiding the management of transmission congestions. In short, it is a powerful resource for a more efficient, reliable and resilient grid. Borenstein (2005) and Borenstein and Holland (2005) estimate the efficiency loss due to flat retail rates at 5 to 10 percent of wholesale electricity costs. The smart grid relies heavily on consumer engagement. End-users can play a more active role in balancing demand and supply if they receive the correct economic incentives. There are a number of ways to increase demand participation: price-based demand response including several varying pricing schemes (TOU, CPP and RTP) and incentive-based demand response including interruptible contracts, direct load control, demand bidding and buyback, emergency demand response, capacity market and ancillary services programs.113 There are two main categories of DR programs: dispatchable and non-dispatchable. In dispatchable programs, consumers allow an operator to control the electric appliance directly and are verifiable and capable of responding within the operator. Rates are classified according to two important characteristics: granularity – the

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The economics of the smart grid technological innovation  ­381 frequency with which rates change; and timeliness – the lag between the time that a new rate is announced and the time that it is in effect.114 Time-of-Use (TOU) pricing is a static-time varying scheme where prices are set for predetermined hours, days and seasons. Since they don’t capture the price variation within a price block (the rates are adjusted infrequently) they don’t capture accurately generation costs and wholesale prices. Borenstein (2005) shows that TOU is likely to capture only a small share of the efficiency gains of RTP. However, given their more static nature, it has a lower implementation cost of implementation. Transaction costs are also minimal for this type of scheme, due to the low complexity. Dynamic pricing schemes include Real Time Price (RTP) and Critical Peak Pricing (CPP) and may better reflect real-time variations in electricity prices and scarcity – and changes in wholesale prices and demand/supply balance. CPP is a combination of traditional TOU rates and real-time pricing. The critical peak price is designed to replace the normal peak price in order to respond to specific critical conditions (when system reliability and stability is compromised, wholesale prices are too high, or forecast of extreme weather conditions). In the short-run, the lack of dynamic pricing schemes is inefficient because consumers use more than the optimal at peak times and less at off-peak times. In the long-run it is also inefficient, since capacity-building will be above the optimal level. Traditionally, for larger consumers, dynamic prices imply lower transaction (or relative) costs. This is because they are able to access technologies and personnel to enable demand response (energy management systems, real-time metering, and departments with skills to manage electricity consumption and participate in demand response). However, recent advances are altering the landscape: reductions in the metering installation costs, government (state) policies to increase deployment of smart meters, consumer-based technologies, the advancement in consumer behavior research and new business models with innovative solutions to promote DR (residential and industrial). Smart appliances, for instance, can be programmed to automatically adjust energy use, reducing transaction costs. Although RTP is technologically feasible, it is politically challenging: given the cross-subsidies from flat tariff rates, it may require unpopular transfer payments (Borenstein, 2007). Some argue that ­low-income consumers and other groups (for example, someone with medical equipment who would still have to run the equipment at peak times) would be negatively affected, given their alleged flatter pattern and more difficulty in adapting their electricity usage. According to Joskow and Wolfram (2012), recent experiences suggest that the press and consumer advocates will focus attention on those consumers. However, empirical evidence doesn’t corroborate the view that low-income consumers would be adversely affected. Hledik and

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382   Handbook of energy politics Greenstein (2016) found that demand charges do not disproportionately impact low-income customers. In an earlier study, Faruqui et al. (2010a) assess three dynamic pricing programs in Connecticut, the District of Columbia and Maryland (in addition to some other results).115 They also found that most low-income consumers would respond to dynamic pricing and benefit from it. A commonly used and – politically more feasible – incentive-based mechanism is peak time rebates (demand-reduction programs). They provide incentives to  reduce consumption  during a critical event. One challenge for these programs is the lack of a reliable baseline from which to pay for the reduction and the set-up of the contrafactual to measure the impact of the program (an adverse selection problem may arise). If incentives to reduce demand are not well calibrated they may also be inefficient due to an over-reduction.116 The long-term impacts of reward programs should also be taken into account: McClelland and Cook (1980) find that energy savings associated with reward have disappeared, and some argue they can even rebound upon withdrawal. In interruptible contracts, direct load control (DLC) and emergency DR programs, consumers receive different types of incentives to reduce their loads. Those programs are the more efficient to quickly reduce the system load, and therefore are more fit for dealing with sudden reliability threats that price signals do not suffice (especially when prices are capped). Consumers can also offer load reduction through capacity market programs or demand bidding. Direct control programs can be more effective in the short-term, but raise more concerns regarding privacy and autonomy. In the long-term, other issues should be considered. In addition, voluntary curtailment provides the customer with many opportunities to engage in energy conservation efforts, and may consequently foster environmental identity and lead to performance of other environmentally beneficial behaviors.117 Aggregators and remote controlling (or some other automatic enabling technology) can help overcome the difficulties in engaging residential consumers in DR programs. Residential customers have an important role to play in demand response, especially when peak residential demand coincides with the system peak. Aggregators enroll end-users of electricity to participate in demand response and sell the combined load reduction to utilities and the ISO, and can thus spread the risk (since they build a diverse portfolio of consumers).

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The economics of the smart grid technological innovation  ­383 8.3  Consumers For each type of scheme, the program economic impact and effectiveness will depend on: whether it is voluntary adhesion and rate of adhesion,118 communication technology, market mechanisms and consumer engagement. It also requires a comprehensive understanding of consumer types and behavior. Borenstein (2002) shows that consumers with a flat load profile or that consume proportionally more at off-peak times will benefit the most. However, in a general equilibrium setting, consumers with a peak demand at peak hours could also benefit if incentives to reduce consumption are enough to decrease equilibrium prices at that time. In the longer run, if generation capacity investments decrease following a reduction in overall peak consumption, even those consumers can see a reduction in electricity bills. Up until recently, there was less consensus in the demand response research on whether higher peak prices simply reduce peak demand, or whether they shift the demand from peak to non-peak periods (Joskow, 2011). However, the recent fast increase in smart meter deployment accompanied by research stimulus given by the SGIG and the ARRA fund and advance the use of randomized controlled experiments informed by behavioral science is providing policymakers with an increased knowledge of consumers. Regulators, policymakers, industry and researchers are already working together to learn how deployments and pilot projects can be designed to result in higher quality evaluations. Randomized control trials119 provide credible estimation of causal relations between policy and outcomes, although predictions based on experiments in other sites have to be carefully extrapolated.120 As more data becomes available from (quasi) experiments and new communication technologies, program implementation and evaluation must be though together. The Department of Energy encouraged recipients of Recovery Act funding to engage in pricing experiments.121 It is important to ensure consumers have the information and control they need to make wise decisions about their energy consumption. The degree to which demand response can be realized will be greatly affected by the willingness and ability of customers to respond to changes in price. If consumers have a low demand elasticity and generators are operating at their capacity constrain, a slight reduction in output could raise prices significantly. In electricity markets demand is too volatile and storage capacity is decreasing (this trend can revert in the longer run if cost-effective storage becomes widely available). The smart grid affords the ability for real-time interventions and measurement. However, to unlock its potential the implementation process is crucial for a correct identification of causal effects and effectiveness of the

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384   Handbook of energy politics intervention. Faruqui and Palmer (2011) access a database of dynamic rate experiments compiled by the Brattle Group with empirical data on 109 dynamic-pricing studies. They argue against the “top seven myths about residential dynamic pricing” and find that consumers do respond to higher prices by decreasing usage during peak periods. The magnitude of the response varied according to the rate designs, the availability of enabling technologies and the price rates tested. The wide variation in demand response reflects the wide variation in rate design, program implementation, underlying variation in consumer attributes and other factors. For instance, temperature may impact consumers’ response to price incentives, and is important when predicting program impact based on an experiment in a different site.122 Technology enablers can be used to increase consumer elasticity. More granular appliance-level data can also contribute to improve forecastingdemand models, increasing the efficiency of planning and operations of SOs. There is also more evidence that households may reduce electricity consumption even in the absence of dynamic pricing if they have in-home displays and increase it upon signing up for automatic bill payment.123 Enablers include effective real-time pricing, improved metering (lowered costs and improved functionality for meters, automated demand response technologies), energy management systems and customer displays. Bollinger and Hartmann (2015) find that households demand reduction was more than twice as large when they were given automation technology rather than technology that only informed the prices. Jessoe and Rapson (2014) designed a randomized experiment in which treatment households were exposed to a CPP plan and a subset of these households were also given an in-home display allowing them to be better informed on which appliance to turn off. They found the group with the display reduced their usage by between 8 to 22 percent on average during pricing events, up from 0 and 7 percent of the other group relative to control. They also found some evidence of habit formation, since conservation extends beyond pricing events, which is far from a consensus in the literature.124 Blonz (2016), studies the impacts of peak pricing in the commercial and industrial sector.125 He uses a quasi-experimental126 approach from Pacific Gas and Electric Company’s (PG&E) “Peak Pricing” peak demand program and finds that establishments reduce their peak usage by 13.4 percent during peak hours. He finds that when PG&E calls a CPP day on hot summer afternoons, inland customers’ demand reduction is larger than coastal ones’ (who face more pleasant temperatures), highlighting the importance of air conditioning to dynamic price response and gives further support for enablers. Another important finding is how different types of consumers face different incentives: Blonz provides further

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The economics of the smart grid technological innovation  ­385 evidence that consumer-facing establishments (theaters, restaurants) do not show a significant response to peak pricing. Informing and educating is crucial for consumer acceptance and consequently, the program’s success. The following episode highlights this challenge: after installation of the new meters as part of PG&E’s Smart Meter program (Bakersfield, California) some consumers found their monthly bill doubled compared with the previous year. A class-action lawsuit was filed that questioned the devices’ accuracy. PG&E concluded that the timing of installation had coincided with an increase in conventional rates, which had also coincided with unseasonably hot temperatures.127 This illustrates that promises to consumers regarding their savings in electricity bills upon the adoption of dynamic rates may increase the credibility gap between consumers and utilities. Until recently, policymakers, academics and stakeholders have focused on prices as the main determinant of energy demand. Some drawbacks and limitations of price-based policies have led to an increased interest in non-price energy conservation programs and behavior science.128 The latter can be instrumental in understanding and engaging end-users to maximize the impact of SG technology. Following Sintov and Schultz (2015), electricity consumption reduction relies on consumers to undertake a series of decisions: attending to the alert; mentally cataloging energy use in home; deciding what action(s) to take to reduce energy use; executing such actions and maintaining this lower level of use over some period of time. We will go through a rich set of studies. The Sacramento Municipal Utility District (SMUD) implemented a CPP plan, the “Smart Pricing Plan.” In the plan roll-out, some randomly selected customers stayed on flat pricing while others had the time-varying option. This randomization allowed for a more accurate evaluation. Some interesting results emerged: customers on the time-varying rates cut consumption relative to the control group (peak price was $750 for 12 afternoons compared to $100 in the other days and $160 for consumers under the flat rate) as expected. Interestingly, they also did so during other days.129 This can shed some light on how they cut their consumption. Experiments conducted by the utility provides crucial insights for program implementation. According to the “default bias” theory, when confronted by a choice in which one option is viewed as the default, people stick to that option. SMUD’s customers showed this in spades: 95 percent of them stayed with time-varying pricing when it was the default, but only 18 percent chose to opt in (the selection was also random).130 Fowlie et al. (2017) study the impacts of opt-in versus opt-out peak pricing programs (TOU and CPP). They find a significant reduction in peak electricity usage for both groups, with a larger effect for the opt-in group, as expected.

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386   Handbook of energy politics They also find that consumers on the CPP plan reduced their consumption on non-event day, which can be consistent with habit formation, fixed adjustment costs or learning. They also explore the reasons for the default bias behavior, which is crucial for understanding program welfare implications. The new behavioral business that doesn’t provide explicit control or dispatch signals is emerging.131 They provide information and tips to consumers. An example of this type of business model is Opower. They send personal energy reports to households with information on own energy use, social comparisons (how they compare with similar households’ consumption) and energy conservation information and tips. Currently, 100 utilities use the Opower platform. As of 2014, 6.2 million households were receiving home energy reports.132 Allcott (2011)133 and Allcott and Rogers (2014) evaluate a series of programs run by Opower. In their home energy report letters they compared consumers’ electricity use with that of their neighbors. In behavioral science it is well-documented that social comparisons induce a decrease in energy demand.134 Allcott (2011) finds that the average program reduces energy consumption by 2.0 percent. They also find that the effect of non-price intervention is equivalent to that of a short-run electricity price increase from 11 to 20 percent, providing evidence of the cost-effectiveness of this type of model. Ayres et al. (2013) also analyze the importance of social comparisons to energy usage reduction. Using data from a largescale, random-assignment field experiment conducted by the Sacramento Municipal Utility District they find a reduction in energy consumption of 2.1 percent in the treatment group that received periodically reports with peer comparison. Schultz et al. (2007) reported a boomerang effect for consumers who deviated in the desired direction from the norm (that is, consuming under the desire level). In order to avoid this, they employed an injunctive norm,135 which in this case were smiley faces on the descriptive norm feedback reports given to these relatively low users and reported it had the power to avoid the boomerang effect. Allcott (2011) also provides some evidence of the power of injunctive norms. Allcott and Rogers (2014) find a persistence (albeit deteriorated) of the effect of home comparison reports even after they are discontinued. This persistence should be taken into account when evaluating costeffectiveness of different policies.136 In order to understand this channel through which a policy intervention alters consumption decisions, Ito et al. (2015) study the effects of two types of interventions in consumers’ electricity consumption at peak times: a moral suasion (intrinsic motivation) and an economic incentive (extrinsic

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The economics of the smart grid technological innovation  ­387 motivation). The latter presented persistent and spillover effects (change in consumption at other than the interventions times), and the moral suasion group the persistency was large and they found no evidence of habit formation. Interventions that appeal to consumers’ desire to conform with social norms may be effective for conservation purposes, but the same may not be true for peak time reductions. Another issue raised by consumer theory is how to sell the program if consumers are expected to permanently change their consumption pattern. Self-determination theory suggests that providing reward (demand reduction programs) for behavior that might otherwise occur through intrinsic motivation (climate change, outage concerns) can weaken intrinsic motives and be counterproductive over the long-term if they undermine intrinsic motivation to act.137 For instance, technologies that provide energy feedback at the appliance level – disaggregation ­technology – inform consumers exactly which appliances are consuming energy, providing them with a clear action plan, which may lead to an enhanced sense of competence or perceived control (self-determination theory and theory of planned behavior). As we discussed, utilities can use smart grid technologies to directly control a variety of home equipment without consumer permissions or opt-out options. At first glance, this seems very effective, since it provides information on specific behaviors of the customer’s electricity usage and “makes it easier” for consumers. However, although direct control technologies facilitate savings, Leijten et al. (2014) found that consumers still preferred the option of choosing how to curtail consumption. These finding are in alignment with the theory of planned behavior, which states that perceived control is an important predecessor of behavior. In general, emerging technology faces financial, technical and social barriers. Thus, each technology should be evaluated in light of consumer behavior science to uncover the best strategies to boost adoption of such technologies. Purchasing a car or installing a solar PV panel is an infrequent behavior, so financial incentives would probably be a good strategy. Some studies have found social influence plays an important role in the installation of rooftop solar PV systems: adding a solar PV system to a single home in a neighborhood significantly increases the average number of installations within a half-mile radius (Bollinger and Gillingham, 2012; Graziano and Gillingham, 2014). These findings may help drive fiscal policy regarding DERs.

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388   Handbook of energy politics

9.  ADDITIONAL CHALLENGES 9.1  Jurisdictional Challenge The three main components of the traditional power delivery system are the generation source, long-distance high voltage transmission lines and the local distribution system, where voltage has to be lowered to be carried. Electricity has traditionally been produced by large-scale generation and flowed in one direction to consumers, allowing for reasonably clear demarcations of regulatory jurisdictional and oversight boundaries. The Federal Power Act establishes the current jurisdictional divide of regulatory authority between the federal government and the states (in general, federal regulators have authority over the bulk power system and interstate commerce while state and local regulators have oversight of the distribution system and retail sales). Most European countries have a single regulatory body responsible for overseeing and maintaining reliability of the countries’ power system. This division of authorities between the federal government and states is becoming more challenging with the advent of distributed generation and the two-way power flow. As DGs, distributed storage can also be interconnected with high or low voltage lines, as well as behind the meter, and along with DR, they can provide electricity services within the wholesale or retail markets for both transmission and distribution systems. Significant wholesale and retail competition in some locations among many diverse entities adds to the challenge. The difficulty in defining the regulatory environment for DR is better exemplified by the judicial process that culminated in the Supreme Court decision ruling in favor of the FERC’s authority over DR.138 The Appeals Court decided that states had the right to regulate its utility markets. Balancing area limits becomes also more challenging. Larger balancing areas139 could help manage variability with an increased geographic diversity and higher aggregation of generation.140 The integration of PacifiCorp and the California ISO Energy Imbalance Market reduced the amount of required flexibility reserves by 36 percent.141 In addition, the lack of common principals for transmission cost allocation across regions magnifies the difficulties. 9.2  Cybersecurity and Privacy Traditionally, reliability of the grid has mainly referred to its physical system. However, the growing digitization and reliance on data brings the information infrastructure to the core of the reliability requirements.

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The economics of the smart grid technological innovation  ­389 The increasingly widely distributed energy generation and consumption data raises questions over the ownership and privacy concerns. As services become more digital and automated, power disruptions have greater consequences. Cybersecurity threats and vulnerabilities include: physical vulnerabilities; cybersecurity vulnerabilities that refers to all the approaches taken to protect data, systems and networks; control system vulnerabilities; electrical system vulnerabilities from electromagnetic pulse; utility electricity pricing system and billing vulnerabilities; data communication vulnerabilities; privacy and data confidentiality; observation vulnerabilities.142 This trend exacerbates the need for regulatory standards for cybersecurity, privacy and coordination to combat threats and information sharing.143 Utilities’ challenge in securing their information and operation technology systems is magnified by their dependence on each other: “systems are only as strong as their weakest links.”144 The increased amount of information on consumers also raises privacy concerns and the need to create privacy guidelines. Both standards and guidelines cannot be in conflict. Cybersecurity regulations needs some degree of flexibility to keep pace with evolving threats, which poses the challenge of building a transparent regulation that can evolve in the same pace of threats, as in the case of regulations for embracing the smart grid in general. As more “cloud-based” services and cloud computing for data storage and processing are employed, new cybersecurity methods have to be required. The December 2015 cyberattack on the Ukrainian power grid demonstrated how exposed utilities are, the impact size and increased stakeholders’ concerns. Security issues were the most pressing concern according to the latest Utility Dive’s 2017 State of the Electric Utility Survey, after being ranked sixth in the previous years.145 Although there had been no devastating cyberattacks against US utilities,146 the same Russian hacker may be involved in both the attack on the Ukrainian grid and the hacking of Hillary Clinton during the 2016 presidential election.147 The estimated economic impact of a cyberattack on the US grid is also huge:148 $243 billion if 50 out of the 676 large generators were disabled (plus insurance claims costs). Given the high connectivity of the grid, it is crucial that everyone connected to the electric grid adhere to minimum cybersecurity standards. The dissemination of DERs and ICTs can also be part of the solution against cyber threats if the current network topology extends optimally to integrate microgrids at the customer or community level: it can help isolate failures, provide alternative pathways for avoiding component failures, resolve local failures before the entire network is exposed to

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390   Handbook of energy politics instability, and maintain continuity of service and assist in black start with the use of “islanding” operations.149 The valuation of DERs also needs to take cybersecurity into account in two dimensions: the process of pricing and the price itself. DERs participation in the price formation requires digital connections, and pricing and accounting systems need to be protected and monitored. This protection, in turn, costs, and needs to be recovered.

NOTES   1. Kelly-Detwiler (2015).   2. Following the DOE (2015b), the grid comprises of six elements: generation, transmission, distribution, storage, information infrastructure and demand.   3. Major carriers faced bankruptcy after deregulation while the services (fixed telephone lines) in the telecom sector had radically changed.   4. See Christensen, 1997.   5. Bower and Christensen, 1995.   6. Christensen et al. (2005).   7. Kind (2013).   8. IPCC (2014) “Climate change 2014 synthesis report,” available at http://www.ipcc.ch/ report/ar5/syr/, accessed November 28, 2017.   9. ACEEE (2016) “Energy usage data access: A getting-started guide for regulators,” available at http://aceee.org/sector/state-policy/toolkit/data-access, accessed November 28, 2017.   10. E. Ela and B. Kirby (2008) “ERCOT event on February 26, 2008: Lessons learned,” National Renewable Energy Laboratory, July.   11. MITEI (2011) “The future of the electric grid,” available at http://energy.mit.edu/ research/future-electric-grid/, accessed November 28, 2017.   12. Office of Electricity Delivery & Energy Reliability (n.d.) “Grid modernization and the smart grid,” available at http://energy.gov/oe/services/technology-development/smartgrid, accessed November 28, 2017.   13. Department of Energy (DOE) 2012.   14. U. Hölzle (2016) “We’re set to reach 100% renewable energy — and it's just the beginning,” Google Blog, December 6, available at https://blog.google/topics/environment/100-percent-renewable-energy/, accessed Novem​ ber 28, 2017.   15. IEA (2016a).   16. https://www.greentechmedia.com/articles/read/wind-is-killing-coal-in-America.   17. Nemet (2006).   18. DOE (2017).   19. DOE (2015a).   20. DOE (2015a).   21. IEA (2016a).   22. According to Giordano et al. (2013) electricity losses in LAC were 17 percent in 2007–2011 compared to 6 and 8 percent in high-income countries of the OECD.   23. System frequency must be managed to balance supply and demand of electricity at all times. While conventional generation are synchronously connected to the grid, they serve as baseload resources and as spinning reserves to provide system inertia.   24. NERL (2015).   25. Maintaining system reliability, providing real-time control of voltage.

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The economics of the smart grid technological innovation  ­391   26. For starters, electricity generation technologies have different temporal and spatial production profiles.   27. Borenstein (2012).   28. Richter (2013).   29. The environmental externalities benefits are far too difficult to measure, but still invoked as a reason to promote solar (and other clean) energy.   30. EPRI (2011).   31. DOE (n.d.) “The Smart Grid: an introduction,” available at https://www.energy.gov/ sites/prod/files/oeprod/DocumentsandMedia/DOE_SG_Book_Single_Pages%281%29. pdf, accessed November 28, 2017.   32. DERs are smaller power sources that can be aggregated to provide power and include Distributed Generation (DG), Distributed Storage (DS), Electric Vehicle (EV) and Demand Response (DR).   33. Eureletric (2014) defines flexibility as “the modification of generation injection and/ or consumption patterns in reaction to an external signal (price signal or activation) in order to provide a service within the energy system. The parameters used to characterize flexibility in electricity include: the amount of power modulation, the duration, the rate of change, the response time, the location etc.” Following NERC (2016), there are different capabilities for flexibility: ramping of the variable generation, regulating and contingency reserve, reactive power reserve, quick start capability, low minimum generation level, ability to frequently cycle the resources’ output, operation of structured markets, shorter market scheduling interval, DSM, reservoir hydro system, energy storage and improved wind and solar forecast techniques.   34. Campbell (2012).   35. System Average Interruption Duration Index (SAIDI), the Customer Average Interruption Duration Index (CAIDI) and the System Average Interruption Frequency Index (SAIFI), which measures the average number of times that a customer experiences an outage during the year (SAIFI is calculated by dividing SAIDI by CAIDI).   36. The Grid Modernization Laboratory Consortium is launching the “Foundational Metrics Analysis project” aiming to develop some standardize resilience metrics.   37. Taneja (2017).   38. DPS (2015a) CASE 14-M-0101 “Proceeding on motion of the commission in regard to reforming the energy vision: Order establishing the benefit cost analysis framework,” May 29, http://www3.dps.ny.gov/W/PSCWeb.nsf/All/C12C0A18F55877E785257E6F0 05D533E?OpenDocument, accessed November 28, 2017.   39. Estimated to be ten times more expensive than overhead cables: https://ucononline. com/2010/06/14/underground-electric-transmission-installations-gaining-traction/.   40. Grid Modernization Multi-Year Program Plan, 2015.   41. For a more detailed characterization of those see Pérez-Arriaga et al. (2011).   42. See Ela et al. (2011b) for a review of reserve types.   43. See Pérez-Arriaga (2011) for the needs of reserve with the penetration of intermittent in the power system.   44. Pérez-Arriaga et al. (2016).   45. See Borenstein et al. (2002), Faruqui and Sergici (2009) and Borenstein (2005). Consumer behavior studies can be found at DOE (2013b).   46. SEDC (2014).   47. See Giordano et al. (2013).   48. DOE (2014) “Smart Grid system report,” available at https://www.smartgrid.gov/ files/2014-Smart-Grid-System-Report.pdf, accessed November 28, 2017.   49. EPRI (2011).   50. Joskow (2011).   51. See Gowrisankaran et al. (2016).   52. EPRI (2011) are the most comprehensive guidelines we are aware of, but investment in SG technologies are being accompanied by estimates, as the SGIG reports show.   53. DOE (2014).

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392   Handbook of energy politics   54. MITEI (2011).   55. For a review of the role of technological change in green growth see Popp (2012).   56. QTR (2015).   57. Baker et al. (2013) provide a comprehensive review of cost benefit analysis for solar electricity in the short, medium and longer term.   58. QTR (2015). According to DOE (2017), the decrease in training programs in the electricity industry from the 1980s contributes to this workforce gap as the large number of baby boomers retire.   59. In whole or in part.   60. DOE (2017).   61. Ibid.   62. Although state commissions are in the early stages of this process and facing some strong opposition, as is exemplified by the recent decision of Nevada Assembly to restore retail net metering (Assembly Bill 405).   63. MIT Energy Initiative (2016).   64. http://pubs.naruc.org/pub/2E54C6FF-FEE9-5368-21AB-638C00554476.   65. DPS (2016).   66. QTR (2015).   67. Ibid.   68. DOE (2016b).   69. Figure 3.7 on p. 61 of the QTR, 2015 shows the phase-angle separation that occurred shortly before the 2003 blackout, and what the operators could have observed had the technology been in place at that time.   70. US–Canada Power System Outage Task Force (2014) “Final report on the August 14, 2003 blackout in the United States and Canada: Causes and recommendations,” April.   71. DOE (2016).   72. See more in DOE (2016b).   73. QTR (2015).   74. DOE (2015d).   75. QTR (2015).   76. DOE (2015d).   77. See DOE (2014).   78. QTR.   79. For more detail, see DOE (2016c).   80. EPRI (2011).   81. According to the QTR (2015) 70 percent of large power transformers and transmission lines are at least 25 years old and 60 percent of circuit breakers are at least 30 years old.   82. US Energy Information Administration (2016) “Electric power sales, revenue, and energy efficiency: Form EIA-861 detailed data files,” final yearly data (last release date October 6).   83. Automated feeder switches enables “self-healing” fault location, isolation and service restoration capabilities (FLISR).   84. QTR (2015); DOE (2013).   85. QTR (2015).   86. Borenstein (2012).   87. IEA (2016b).   88. US Federal Energy Regulatory Commission (2016) “Settlement intervals and shortage pricing in markets operated by regional transmission organizations and independent system operators,” available at https://www.ferc.gov/whats-new/comm-meet/2016/061616/E-2. pdf, accessed November 28, 2017.   89. See Ela et al. (2011a).   90. SEDC (2014).   91. For more on PJM Capacity Markets visit its webpage: http://learn.pjm.com/threepriorities/buying-and-selling-energy/capacity-markets.aspx, accessed on December 20, 2017.

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The economics of the smart grid technological innovation  ­393   92. Hogan (2005, 2013), Joskow (2008), Joskow and Tirole (2006, 2007).   93. This figure does not include the production of electricity by rooftop solar PV.   94. I. Penn and R. Menezes (2017) “Californians are paying billions for power they don’t need,” LA Times, February 5, available at http://www.latimes.com/projects/la-fielectricity-capacity/, accessed November 28, 2017.   95. Borenstein, 2012.   96. Ibid.   97. Pete Wilson (California’s former governor), Senator Don Nickles (former Oklahoma senator), Michele Bachmann (a former congresswoman) and Mitt Romney. See: https://www. theatlantic.com/business/archive/2017/01/regulations-jobs/513563/, accessed December 20, 2017.   98. See Berman and Bui (2001) and Greenstone (2002).   99. R. Schoof and D. Scott (2016) “Trump says plan to end climate spending would save $100B,” Bloomberg BNA, November 2, available at http://www.bna.com/trump-saysplan-n57982082131/, accessed November 28, 2017. 100. The Tesla and SpaceX CEO announced he would leave the president’s advisory boards following President’s Trump withdrawal, and California, Washington and New York announced their intention to form an alliance to comply with the goals of the treaty, see G. Bade (2017) “Utilities post-Paris: Uncertainty rules power sector as Trump shatters climate consensus,” Utility Dive, June 2, available at http://www.utilitydive.com/ news/utilities-post-paris-uncertainty-rules-power-sector-as-trump-shatters-clim/444124/, accessed November 28, 2017. 101. EPA (2015). 102. Ohio, Minnesota, New Hampshire, Maryland and Illinois have recently joined New York, California and Texas, undertaking utility of the future proceedings. 103. Utilities tend to support demand charges for solar net metering customers, while solar industry groups are opposed to them. 104. Arizona Corporation Committee (2017) March 1, available at http://docket.images. azcc.gov/0000177680.pdf, accessed November 28, 2017. 105. DPS (2015b) Case 14-M-0101 “Proceeding on motion of the commission in regard to reforming the energy vision, order adopting regulatory policy framework and implementation plan” (issued February 26) (Track One Order). 106. Smart Grid Consumer Collaborative (SGCC) (2016) “Consumer driven technologies, 2016,” available at http://smartenergycc.org/wp-content/uploads/2016/10/SGCCConsumer-Driven-Technologies-Study-Executive-Summary-10-19-16.pdf, accessed November 28, 2017. 107. Regarding how the non-energy utility costs are paid, the low capacity value of solar and need for contracting for a backup and ramping costs magnified by solar PV penetration. 108. See Brown (2013) “Matching prices and value for distributed solar PV: SRP’s proposal,” available at http://www.srpnet.com/prices/priceprocess/pdfx/ABReport.pdf, accessed November 28, 2017. 109. Brown (2013) “Matching prices and value for distributed solar PV: SRP’s proposal.” 110. More on that in the VER section below. 111. M.L. Wald (2014) “How grid efficiency went south,” New York Times, October 7, available at https://www.nytimes.com/2014/10/08/business/energy-environment/howgrid-efficiency-went-south-.html?_r=0, accessed November 28, 2017. 112. See https://www.ferc.gov/industries/electric/indus-act/demand-response/dem-res-advmetering.asp, accessed on December 20, 2017. 113. IEA (2011). 114. Borenstein (2005). 115. Connecticut Light & Power’s (CL&P’s) Plan-it Wise Energy Pilot (PWEP), Pepco’s PowerCentsDC Program (Pepco DC) and Baltimore Gas & Electric’s Smart Energy Pricing Pilot (BGE, 2008). 116. The US FERC order 745 from March 2011 established that providers of economic

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394   Handbook of energy politics demand response that participate in wholesale power markets be compensated for demand reduction. A number of energy economists has opposed the order: according to HKS Professor Hogan order 745 overcompensates providers of demand response, resulting in a disuse of electricity when economic value exceeds the cost of producing. See Hogan (2010) for more. 117. See Sintov and Schultz (2015). 118. If very few engage, they may have to pay too high peak prices, since the total electricity demanded will still be too high in peak times. 119. See Banerjee and Duflo (2009) for randomized control trials. 120. See Allcott (2015) for site selection bias. 121. Study descriptions and evaluation can be found in DOE (n.d.) “Consumer behavior studies,” available at https://www.smartgrid.gov/recovery_act/overview/consumer_behavior_​ studies.html, accessed November 28, 2017. 122. Reiss and White (2005) and Blonz (2016). 123. Gans et al. (2013), Faruqui et al. (2010b), Sexton (2015). 124. Further, Gilbert and Graff Zivin (2014). 125. I haven’t been able to find published papers on the impact of peak pricing in the ­commercial and industrial sector. 126. He compares establishments that just missed the eligibility criteria. 127. See Smith (2010). 128. Sintov and Schultz (2015), Christensen et al. (2015), Allcott (2011). 129. C. Wolfram (2013) “Smart meters but dumb pricing? Not in Sacramento,” Berkeley Blog, November 21, available at http://blogs.berkeley.edu/2013/11/21/smart-meters-but-dumbpricing-not-in-sacramento/, accessed November 28, 2017. 130. See Fowlie et al. (2017). 131. See Burger and Luke (2016). 132. Allcott and Rogers (2014). 133. In this paper, the experiment comprised 600,000 households. 134. Sintov and Schultz (2015). 135. See Cialdini et al. (1991) for more on descriptive and injunctive norms. 136. See also Ito et al. (2015). 137. See Benabou and Tirole (2003) for more on extrinsic and intrinsic motivations. 138. US FERC order 745 from March 2011 established that providers of economic demand response that participate in wholesale power markets be compensated for demand reduction. 139. FERC requires balancing authorities to constantly match supply and demand within their respective balancing areas. 140. National Renewable Energy Laboratory (NREL) (2016). 141. CAISO (2016). 142. C.W. Draffin, Jr. (2016) “Cybersecurity, white paper,” MIT Energy Initiative Utility of the Future, December 15, available at https://energy.mit.edu/wp-content/ uploads/2016/12/CybersecurityWhitePaper_MITUtilityofFuture_-2016-12-05_Draffin. pdf, accessed November 28, 2017. 143. The North American Electric Reliability Corporation (NERC) has developed ­cybersecurity regulations at the bulk power and transmission levels (NERC, 2016), however they are still lacking at the distribution level. The first European legislation on cybersecurity, the Network and Information Security (NIS) Directive, is also very recent (2016). 144. DOE (2017). 145. The increased concern has been related to the Ukrainian cyberattack: H.K. Trabish (2017) “Why utilities say grid security is the most pressing sector issue of 2017,” Utility Dive, available at http://www.utilitydive.com/news/why-utilities-say-grid-security-isthe-most-pressing-sector-issue-of-2017/440056/, accessed November 28, 2017. 146. Idaho National Laboratory (INL) (2016). 147. J. Condliffe (2016) “Ukraine’s power grid gets hacked again, a worrying sign for

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The economics of the smart grid technological innovation  ­395 infrastructure attacks,” Technology Review, December 21, available at https://www. technologyreview.com/s/603262/ukraines-power-grid-gets-hacked-again-a-worrying-si​gnfor-infrastructure-attacks/, accessed November 28, 2017. 148. Lloyd’s (2015) “Emerging risk report 2015,” Centre for Risk Studies: University of Cambridge, Judge Business School. 149. C.W. Draffin, Jr. (2016) “Cybersecurity, white paper.”

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The economics of the smart grid technological innovation  ­401 Schultz, Wesley, Nolan, Jessica, Cialdini, Robert, Goldstein, Noah, and Griskevicius, Vladas (2007) “The Constructive, Destructive, and Reconstructive Power of Social Norms,” Psychological Science, 18, pp. 429–34. Sexton, Steven (2015) “Automatic Bill Payment and Salience Effects: Evidence from Electricity Consumption,” Review of Economics and Statistics, 97 (2), pp. 229–41. Sintov, Nicole D. and Schultz, P. Wesley (2015) “Unlocking the potential of smart grid technologies with behavioral science,” Frontiers in Psychology, 1–8. Smart Energy Demand Coalition (SEDC) (2014) “Mapping Demand Response in Europe Today,” available at http://www.smarten.eu/wp-content/uploads/2015/09/Mapping-Dema​ nd-Response-in-Europe-Today-2015.pdf, accessed on November 27, 2017. Smart Grid Consumer Collaborative (SGCC) (2016) “Consumer driven technologies, 2016,” available at http://smartenergycc.org/wp-content/uploads/2016/10/SGCC-Consumer-Dri​ ven-Technologies-Study-Executive-Summary-10-19-16.pdf, accessed November 28, 2017. Smith, Rebecca. “What Utilities Have Learned From Smart-Meter Tests. . .,” Wall Street Journal, February 22, 2010, available at https://www.wsj.com/articles/SB10001424052748 704878904575031020562238094, accessed on November 28, 2017. Taneja, Jay (2017) “Measuring Electricity Reliability in Kenya,” Working paper, available at http://blogs.umass.edu/jtaneja/files/2017/05/outages.pdf, accessed on November 27, 2017. Trabish, H.K. (2017) “Why utilities say grid security is the most pressing sector issue of 2017,” Utility Dive, available at http://www.utilitydive.com/news/why-utilities-say-grid-security-isthe-most-pressing-sector-issue-of-2017/440056/, accessed November 28, 2017. US Congress (2009),  Public Law 111 – 5 – American Recovery and Reinvestment Act of 2009, available at https://www.gpo.gov/fdsys/pkg/PLAW-111publ5/pdf/PLAW-111publ5. pdf, accessed December 20, 2017.

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PART V ENVIRONMENTAL ISSUES AND RENEWABLE ENERGY POLICY

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17.  Policy risk, politics and low carbon energy Geoffrey Wood

INTRODUCTION Over the last few years, low carbon energy has seen record levels of global investment and capacity additions. Out of the 189 countries that submitted Intended Nationally Determined Contributions under the historic 2015 Paris Agreement on Climate Change (COP 21) to limit global warming to well below 2°C, 147 mentioned renewable energy. Globally, more renewable power (RES-E) capacity was added than for all fossil fuels combined, with around 150 gigawatts (GW) of RES-E installed in 2015. The renewable heat and transport sectors also showed continued increases albeit at a significantly lower level than RES-E, with approximately 8 per cent of final energy for heating worldwide in buildings and industry and 4 per cent of global fuel for road transport supplied by renewable transport, respectively. Overall, renewables supplied one-fifth of global final energy consumption (Renewable Energy Policy Network, 2017). Supplying roughly 10 per cent of global electricity and around one-third of the world’s low carbon electricity supply, nuclear power also reached a 25-year record for the industry in the construction of new nuclear units with ten new reactors coming online in 2015 (World Nuclear Association, 2016). Currently, the least successful member of the so-called ‘low carbon energy family’, Carbon Capture and Storage (CCS) continues to face serious challenges in playing a role in the Paris Agreement objectives, with the first large-scale projects expected to come online around 2015 now facing delays to the end of the decade (Global CCS Institute, 2016). On the face of it, the low carbon energy sector appears overall to be doing well: capacity is up, records are being broken, novel technologies are reaching market maturity and costs are falling. Renewables are now accepted globally as mainstream sources of energy. This is taking place despite a collapse in fossil fuel prices, the ongoing and contentious issues of fossil fuel subsidies and other challenges (for example, the nuclear disaster at Fukushima Daiichi in Japan, fiscal constraints, regulatory barriers and how to integrate rising shares of intermittent renewables). Yet in May 2017, the World Energy Council (WEC) stated in no 405

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406   Handbook of energy politics uncertain terms that policy risk, and the lack of clear long-term goals on the climate and energy, have hindered the sector’s ability to invest in low carbon growth (World Energy Council, 2017). As Christoph Frei, secretary general of the WEC said: It is increasingly clear that traditional mechanisms, known technology, policy and rates of innovation will not deliver the change needed to balance energy security concerns within countries and meet global climate targets. New and ambitious thinking is needed. This new thinking will require stable economic and policy platforms in order to boost investment and establish clear, consistent goals that guide the development of new energy infrastructure that will support the lower carbon transition. (Harvey, 2015)

Despite decades of global policy and practice in deploying low carbon energy technologies, why is policy risk still an issue, and an apparently growing concern at that? In recent years, energy policy has ‘accelerated almost breathlessly’, with an unprecedented increase in the pace and breadth of government involvement and action since privatisation in the early 1990s (Pearson and Watson, 2012: 2). This has been driven by governments committing to increasingly demanding climate change and renewable energy targets for 2020 and beyond, with the concomitant need to increase low carbon energy capacity and address the barriers thereof, alongside the need to somehow square-off the three core dimensions of the energy trilemma – energy security, energy equity and environmental sustainability – to ensure the transition to a fair, justiciable and sustainable low carbon energy system (World Energy Council, 2015). Such state intervention is also partly a consequence of the 2008 global financial collapse and the recent dominance of ideologically driven austerity measures (Onyango and Wood, forthcoming 2018) and the growing awareness that energy and climate change initiatives are currently insufficient to address climate change, the “greatest example of market failure we have ever seen” (Stern, 2006: 1). We have increasingly seen accounts of policy risk affecting low carbon energy. Recent announcements by European governments, including Germany, Spain, Italy, Denmark and the United Kingdom (UK) and the United States (US) since the inauguration of President Trump, to invoke sudden reversals or changes in policy have made investors increasingly nervous. The UK is a classic example of the impact of long-term policy risk on renewables. Despite operating a delivery programme for RES-E since 1990, UK renewable targets and policy goals have not been achieved and the country continues to lag behind other EU Member States (Wood and Dow, 2011). The UK has repeatedly reformed and replaced the policy, legal and regulatory framework to promote renewables and it is argued

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Policy risk, politics and low carbon energy  ­407 subsequently in this chapter that the constant changes have themselves acted as policy risk to actively constrain RES-E deployment, and worse, led to the continual cycle of government intervention and the increased role of policy risk as a barrier to deployment. The outcome of the EU Referendum in 2016 only serves to increase policy risk as investors, developers and others await the aftermath of the Brexit negotiations. This chapter seeks to answer these questions and highlight the issue of policy risk by looking at the negative consequences of policy risk and to determine what lessons can be learned to address policy risk as a barrier to low carbon energy deployment. This chapter does not purport to advise for or against different low carbon technologies or to critique them per se but rather to add to the debate in a relatively ignored area of energy studies. Further, this chapter will look at examples from the European Union (EU) and the US, with an in-depth focus on the UK as examples of countries with long-term national and supra-national policy and legal frameworks for energy and climate change that are rightly praised around the world. But first, in order to set out the context of the discussion, this chapter will look at what we mean by low carbon energy and policy risk.

WHAT WE TALK ABOUT WHEN WE TALK ABOUT LOW CARBON ENERGY Low carbon, renewable, green, clean, sustainable, naturally replenishing. It is common practice to use a multitude of terms interchangeably when we talk about energy that is perceived as unharmful to the climate, the environment and life on this planet including ourselves. But what do we mean when we talk about low carbon energy sources? The literature is quite clear concerning which technologies are to be called low carbon. This includes renewable energy technologies, nuclear power and CCS technologies (Committee on Climate Change, 2017; Department for Business, Energy and Industrial Strategy, 2017). However, this list contains a set of very different technologies and fuel sources: even renewables contains a heterogeneous set of technologies and energy sources with different technological and operational characteristics, from variable solar and wind to more baseload biomass, geothermal and hydro, each with its own subset of related technologies (Boyle, 2004). The key point here is that whatever term is used implies that they produce little in the way of climate-damaging greenhouse gas (GHG) emissions, and definitely they must emit significantly less emissions than fossil fuels. Curiously, there is no legal definition of low carbon. Following on from

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408   Handbook of energy politics the above implicit meaning, the UK Government provided a rare non-legal definition: ‘Low carbon technologies have low life cycle carbon emissions (6.5

Average annual growth rate(*)

The geopolitics of climate action after the Paris Agreement  ­447 Foreign policy priorities China Índice ponderado (*)

42

Support Chinese business interests

51

44

33

29

Fight climate change

Fight international terrorism

Improve China’s image abroad

Increase Chinese influence in the world

(*) Index = (First *1) + (Second * 0,66) + (Third * 0,33)

Source:  Real Instituto Elcano (2017: 111).9

Figure 18.2  Foreign policy priorities for Chinese citizens engagement in international climate negotiations and commitments made, especially from 2009 onwards, attests to China’s desire to take a more prominent role as a global actor with soft power skills. That being said, China’s engagement in climate action is not new. It dates back to the Rio Earth Summit in Brazil in 1992. However, China’s developing country status, its perennial focus on economic development, and perhaps also the relatively low(er) ranking of climate change as a foreign policy priority by Chinese citizens compared to other countries (see Figure 18.2) limited its role as a central player as regards international climate commitments until COP 15 in Copenhagen. After COP 15, international and domestic factors led to China’s commitment of a 40 per cent to 45 per cent reduction in carbon intensity by 2020 compared with its 2005 levels. China also pledged to increase its forest cover by 40 million hectares and its forest stock by 1.3 billion m3 by 2020 from 2005 levels (NRDC, 2010). China’s 2014 joint announcement with the US regarding mitigation goals and cooperation on climate action would later be reflected in China’s NDC submitted ahead of COP 21 in which it pledges to reach a peak in CO2 emissions by 2030, although aiming to peak earlier. This peak in Chinese emissions may well happen ahead of schedule due to China’s embracing a ‘new normal’ economic model that is less energy and emissions intensive (Green and Stern, 2016). China’s NDC also pledges to reduce its carbon intensity (CO2 per unit of GDP) by 60 per cent to 65 per cent by 2030 compared to 2005 levels, and to sourcing 20 per cent of its primary energy consumption from non-fossil fuels sources. Finally, China has committed to increase its forest stock by 4.5 billion m3 by 2030 compared with 2005 levels. Given that China’s old energy intensive model is undergoing a profound

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448   Handbook of energy politics restructuring that has not lead to reductions in economic growth (Green and Stern, 2015) and given citizen support for implementing policies to curb air pollution, it could be argued that China’s development and climate goals are aligned. Ceteris paribus, China can be expected to take a more prominent role in the global low carbon transition, which will help its international leadership status, contribute to its government retaining political legitimacy domestically (Lázaro and Esteban, 2016) and ensure it spearheads the resource efficiency and sustainability innovation wave (Wilneius and Kurki, 2012). When assessing China’s climate change commitments, it is important to acknowledge that they have been considered ambitious by some scholars (Zhang, 2015; Grubb et al. 2015). Chinese climate pledges are likely to be met (or even exceeded) but, as is the case for the US and the EU, they are still insufficient to ensure humans have a likely chance of limiting global mean temperature increase to well below 2ºC, should other countries engage in global mitigation efforts similar to those of China (Climate Action Tracker, 2015). Some of the barriers China is encountering to move towards a low carbon model include its highly fossil fuel dependent economy and the diminishing potential for emission reductions in industrial sectors. Additionally, local authorities that receive substantial revenues from coal power plants and other emission intensive sectors might resist an energy transition that may bring loss of revenue. 3.2  The United States a)  Context and drivers The US is the world’s second largest GHG emitter, contributing 14.4 per cent to worldwide GHG emissions (Friedrich et al., 2015). The global economic crisis in 2008 and the shale gas and shale oil revolution have helped reduce American emissions (EPA, 2015). Climate laws, plans and regulations in the US such as the Clean Air Act as amended in 2011, have also fostered GHG emission reductions. However, the complex political landscape, with democrats and republicans at odds as regards climate change, combined with an institutional setting that can be influenced by economic interests, has resulted in the absence of a federal climate policy (European Parliament, 2015). The limitation in federal climate action is expected to be perpetuated given the Trump administration’s desire to rollback ‘unnecessary’ environmental policy. In particular, this means discarding President Obama’s Climate Action Plan and Clean Power Plan (White House, 2017a) as well as Trump’s recent announcement of America’s withdrawal from the Paris Agreement (White House, 2017b). In order to understand US climate action, Bang et al. (2015) and

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The geopolitics of climate action after the Paris Agreement  ­449 Averchenkova et al. (2016), among others, underline the importance of various factors. The first one is America’s resource endowment, which in tandem with technological innovation brought about by hydraulic fracturing ensure cheap and abundant fossil fuel resources to fuel economic development.10 The US was the third largest crude oil producer in 2015 with approximately 9,415,000 barrels per day, the largest natural gas producer with 766,200,000,000 m3 in 2015 (CIA, 2017a, b) and the second largest coal producer with 922 million tons in 2013 (Worldatlas, 2017). Concern for low energy prices coupled with energy security concerns would be additional economic factors weighing in on American climate policy. The Energy Information Administration (EIA) explains that the US is one of the world’s largest energy consumers (18 per cent globally), importing 11 per cent of its energy from other countries (EIA, 2016). Despite the US’ lower energy dependence compared to the EU (over 50 per cent) and China (with oil dependency reaching 57 per cent in 2014 according to EIA, 2015), President Trump is pursuing full energy independence making use of all domestic energy sources. As regards US climate politics, a deeply polarised debate around climate change among democrats (largely in favour of climate action) and republicans (largely against climate policies), has limited federal legislative action on climate change and has led to an extensive use of executive powers to regulate climate action (Averchenkova et al., 2016). The limits in federal climate legislation have de facto resulted in delegating much of America’s ambitious climate policies to the state or city level. Michael Bloomberg leads the latest example of non-state actor engagement in climate action. He intends to lead a group of mayors, governors, university chancellors and companies to negotiate the acceptance of their commitment pledges under the UNFCCC, along with those of other parties (Tabuchi and Fountain, 2017). Currently, non-state actor pledges are held under the ‘Non-State Actor Zone for Climate Action (NAZCA)’ platform and in the ‘2050 pathways platform’, among others (Biniaz, 2017). Exploring the possibility of including non-state actor commitments along with parties’ commitments would be a significant departure from current institutional framing of climate negotiations. Such a move would arguably better reflect the shift from government to governance but would further increase negotiation complexity and would require rethinking the legal status of non-state actors in international climate law. On the other hand, if the initiative finally entails a transparency and monitoring framework for non-state initiatives within the NAZCA platform (rather than registering non-state commitments alongside state ones), this might increase accountability and trust within the international process, a move that would likely be welcome by all parties.

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450   Handbook of energy politics Even though historically, democrats and republicans have agreed on a number of environmental issues (Dunlap and McCright, 2008), it can be argued that since the 1980s and Reagan’s framing of government as ‘the problem, not the solution’ the divide between both parties on environmental issues in general, and climate change in particular, has increased. The highly polarised debate around climate change, with dissent across party lines on issues such as the existence of climate change, its anthropogenic component and the need to act upon it, have led to US federal gridlock on climate action. As regards the demand for action by non-state actors, the US economy’s dependence on energy-intensive industries and the weight of said industries in the political process have also slowed decisive climate action at the federal level (Averchenkova et al., 2016). In addition to this is the fact that US citizens are less concerned about climate change as a threat than the Islamic militant group in Iraq and Syria (ISIS), Iran’s nuclear programme, global economic instability, cyberattacks or tensions between Russia and its neighbours. In contrast, for other regions climate change is one of the top concerns as can be seen in Table 18.3. That being said, US citizens see climate change as one of the country’s top foreign policy priorities, a powerful reason for the current administration to consider climate diplomacy as an asset in order to capture votes should Trump decide to abandon his neo-Jacksonian climate stance (Mead, 1999). In a recent survey conducted by Real Instituto Elcano (2017), American respondents ranked the fight against climate change as the second foreign policy priority (tied with furthering national business interests) and after fighting international terrorism. b)  Domestic initiatives Political gridlock on climate action has led to judicial rulings on climate change occupying the traditional legislative space that can be observed in many other countries. Given the above, existing laws such as the Clean Air Act of 1970 and its amendments have provided the institutional framework for regulating GHG emissions (Averchenkova et al., 2016). National policy initiatives undertaken by the Obama administration include the Climate Action Plan (2013) as the overarching framework to address climate change both at home and abroad. The Climate Action Plan (CAP) had three objectives: reducing GHG emissions, adapting to climate change and leading international climate action. As regards mitigation, the CAP sought to reduce GHG emissions from power plants, double renewable power generation by 2020, increase energy efficiency in appliances, increase energy efficiency in buildings by 20 per cent, increase fuel efficiency standards for vehicles, reduce methane and hydrofluorocarbon emissions and increase forests’ capacity as CO2 sinks. In August

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451

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U.S. Canada France Germany Italy Poland Spain UK Russia Ukraine Turkey Jordan Lebanon Palest, ter.

ISIS ISIS ISIS ISIS ISIS Russia ISIS ISIS Economic instability Russia Climate change ISIS ISIS ISIS

Top concern

Very concerned about. . .

Table 18.3  Top threats by region

51 32 49 26 48 26 63 32 43 35 33 39 39 32

%

% 42 45 48 34 45 14 59 38 22 20 35 36 44 33

Global economic instability

Global climate change

% 62 43 43 39 44 26 52 41 15 11 22 29 30 17

68 58 71 70 69 29 77 66 18 9 33 62 84 54

Iran’s nuclear program

%

ISIS

59 39 47 39 25 22 35 34 14 4 22 26 17 24

%

43 35 41 40 27 44 39 41 – 62 19 18 18 12

%

30 19 16 17 17 11 20 16 8 4 14 16 16 10

%

Territorial Tensions Cyber disputes between attacks between on gov’ts, Russia and its neighbors* China and its banks or neighbors** corps.

452

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Israel Australia China India Indonesia Japan Malaysia Pakistan Philippines South Korea Vietnam Argentina Brazil Chile Mexico

Iran ISIS Climate change Climate change ISIS ISIS Climate/Ec Climate change Climate change ISIS China Climate change Climate change Climate change Climate change

Top concern

Very concerned about. . .

Table 18.3  (continued)

28 32 16 49 41 30 37 6 52 31 37 49 60 39 46

%

% 14 37 19 73 42 42 37 25 72 40 58 57 75 62 54

Global economic instability

Global climate change

44 69 9 41 65 72 21 14 49 75 30 34 46 31 23

%

ISIS

% 18 37 12 45 22 39 20 14 49 55 32 28 47 22 30

53 38 8 28 29 39 11 9 47 41 22 31 49 31 28

6 31 9 30 15 32 9 7 38 24 19 22 33 15 16

%

3 17 38 11 52 12 18 56 31 60 18 28 15 14

%

Territorial Tensions Cyber disputes between attacks between on gov’ts, Russia and its neighbors* China and its banks or neighbors** corps.

%

Iran’s nuclear program

453

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Climate change Climate/Ec Climate change Climate change Climate change Climate change Climate change Economic instability Climate change Economic instability Climate change

75 60 79 59 71 58 65 51 47 49 74 58 60 50 50 67 44 48 59 33 56 62

35 28 41 38 46 35 36 35 26 51 39

42 35 28 23 34 29 24 33 25 37 33

35 38 25 28 42 35 29 37 28 46 30

26 22 17 20 30 19 25 20 18 30 24

Source:  Stokes et al. (2015).

Note:  Bolded figures note the top concern in each country. Underlined figures note the second highest concern in each country.

* Not asked In Russia. ** Not asked in China.

Peru Venezuela Burkina Faso Ethiopia Ghana Kenya Nigeria Senegal South Africa Tanzania Uganda

27 24 15 20 29 20 24 16 22 26 23

454   Handbook of energy politics Foreign policy priorities in the US weighted index (*)

56 36

Support US business interests

36

Fight climate change

Fight international terrorism

27

24

21

Invest in development aid

Improve US image abroad

Increase US influence in the world

(*) Index = (First *1) + (Second * 0,66) + (Third * 0,33)

Source:  Real Instituto Elcano (2017: 107).11

Figure 18.3  Foreign policy priorities for US citizens 2015 President Obama’s administration announced its Clean Power Plan (CPP). Based on the fact that around a third of American GHG emissions are generated by the power sector, the goal of the CPP was to reduce emissions from the power sector by 32 per cent in 2030 compared to 2005 levels. On adaptation, the CAP sought to direct investments to climate resilient projects, increase capacity building by creating a group of climate leaders and analyse extreme weather events (EWE). Since Trump’s swearing-in ceremony, his administration unveiled its America First Energy Plan (White House, 2017a) where it is stated that Obama’s Climate Action Plan would be discarded as an unnecessary policy. The current administration also supports a revival of the coal industry and President Trump recently signed two presidential memoranda facilitating the construction of pipelines blocked under President Obama. A memorandum to complete the Dakota Access Pipeline and one to build the transnational Keystone XL Pipeline, two symbols of the shift towards an ‘all-of-the-above’ energy strategy embraced by the current administration. The methane rule that limited emissions from oil and gas exploration on federal land was also repealed since President Trump was sworn into office. At the time of writing the repeal has been rejected by the Senate, the EPA has put a stay on the rule and environmental NGOs are threatening with legal action. Despite the above shift in energy policy, the economics of renewables in the US are making their installation increasingly attractive across republican and democrat voting states (Brownstein, 2016). Investment Tax Credits and Production Tax Credits for renewables have been extended, with no indication at present that the Trump administration will eliminate these support mechanisms (Isbell, 2017). Additionally, American states

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The geopolitics of climate action after the Paris Agreement  ­455 and cities have far-reaching powers to enact climate legislation. After the election of Donald Trump as America’s 45th president a significant number of states reaffirmed their intention to implement the Clean Power Plan (CPP) despite the stay by the Supreme Court. Furthermore, 25 cities have pledged to source 100 per cent of their energy from renewable sources (Climate Action, 2017). c)  International engagement President Obama’s desire to lead international climate negotiations was also reflected in his Climate Action Plan (CAP). This desire led him to help draft the Copenhagen Accord, engage with China in 2014 in a joint announcement on climate action and coordinate the ratification of the Paris Agreement with the world’s largest emitter, China. Within the Copenhagen Accord the US pledged it would reduce its GHG emissions by 17 per cent in 2020 compared with 2005 levels (equivalent to reducing emissions by 4 per cent compared to 1990 levels). This commitment was reiterated in March 2015 when the US submitted its Intended Nationally Determined Contribution (INDC) that was to be the US’ first NDC after ratification. In line with the commitments presented by the Obama administration when jointly announcing US–China climate action (White House, 2014), the American INDC pledged to reduce US GHG emissions by 26 per cent to 28 per cent by 2025 compared with 2005 levels, a reduction equivalent to a 14 per cent to 16 per cent drop in 2025 compared with 1990 emission levels, significantly lower that the European commitment. The Trump presidency was expected to reverse, to a greater or lesser degree, Obama’s international climate efforts, in addition to federal climate policies. In fact, on 1 June 2017 Trump announced America’s withdrawal from the Paris Agreement and told the world he would stop payments to international climate programs. The formal withdrawal process will take about four years to materialise according to article 28 of the Paris Agreement, three years from the date the agreement entered into force and one year after depositing the notice of withdrawal (UNFCCC, 2015). The reasons given by Donald Trump for pulling out of the Paris Agreement were primarily threefold: implementing the Paris Agreement will be costly for the US economy, the agreement does little to reign in anthropogenic climate change, and President Trump wants to avoid losing America’s sovereign power, despite the Paris Agreement being designed to suit American circumstances12 (Kemp, 2017). The economic reasons were largely structured around monetary costs of implementation and job losses (White House, 2017b). In economic terms, the EPA estimates that globally concerted action on

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456   Handbook of energy politics climate change would save the US at least U$230 billions by 2050 (EPA, 2015). However, potential benefits from avoided emissions were not taken into account in the National Economic Research Associates (NERA) study Trump quoted to back his decision to withdraw from the Paris Agreement. Acknowledging this shortcoming and underlying that the study was not a cost-benefit analysis exercise, the NERA study authors claim that implementing American NDC would cost US$ 250 billion by 2025, or 1.1 per cent of US GDP compared with a situation without climate policy (NERA, 2017). A more holistic analysis including costs and benefits of climate action would seem the prudent way to define US policy, but ignoring co-impacts of climate action seems to be the norm in climate policy decisions (ÜrgeVorsatz et al., 2014). Additionally, the impacts of the NERA study are estimated based on current technology costs. Given past cost reductions in renewable energy and future expected cost reductions (IRENA, 2014, 2016), some reflection of expected future technology costs could arguably be closer to reality. In his withdrawal speech Trump also argued that 440,000 manufacturing jobs would be lost by 2025 if the US commitments under the Paris Agreement were implemented. According to the NERA study cited, this figure represents job-equivalent data (total labour income change divided by average annual income per job) not total jobs lost. The authors of the study acknowledge that losses in labour income could come from lowering wages rather than from job losses. There is no acknowledgement in the study however of other analyses that contend that implementing policies such as the Clean Power Plan could have net positive employment effects by 2020 and 2030. Bivens (2015) for example contends that implementing the Clean Power Plan would entail 360,000 net jobs created by 2020, and net employment gains of 15,000 in 2030. The NERA study’s shortcomings that President Trump used to support his withdrawal speech are arguably insufficient to produce a balanced policy outcome. The above notwithstanding, analysing the labour market consequences of a low carbon transition and ensuring a just transition for workers is a relevant and underexplored issue (Doorey, forthcoming). Designing measures in national climate laws, that are in the making, to ensure that workers affected by a transition to a low carbon economy (as well as to other labour market disruptors such as automation) can adapt to more stringent climate policies, might increase citizen buy-in of climate policies (Lázaro, 2017b). The second reason Trump gave for withdrawing from the Paris Agreement was that full implementation of the NDCs would only reduce temperatures by 0.2ºC. Even though it is true that current commitments

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The geopolitics of climate action after the Paris Agreement  ­457 fall short of avoiding dangerous interference with the climate system, the MIT study Trump referred to expects mean surface air temperature (SAT) reductions (brought about by the full implementation of the Paris Agreement) between 3 and 5.5 times higher than that claimed by Trump – that is, full implementation of current commitment would reduce SAT between 0.6ºC and 1.1ºC by 2100 compared with a no-policies scenario (Sokolov et al., 2016). The current administration’s decisive steps to reverse international climate commitments and federal climate action add uncertainty to the speed and depth of America’s low carbon transition and potentially encourages other climate laggards to withdraw from the Paris Agreement or reduce their ambition (Tagliaprieta and Zachmann, 2017). The leadership and resolve of China and the EU, among others, in pushing the low carbon agenda is hence a welcome development in the aftermath of America’s second climate default (the first being its failure to ratify the Kyoto Protocol). The urgency of action according to scientists, the evolution of the economics of renewable energy deployment, the fact that previous climate regulations in place have not damaged economic growth, the plethora of climate actions at a sub-national level and citizen demand for action might temper Trump’s full-fledged climate policy reversal. 3.3  The European Union a)  Context and drivers The EU is the third largest GHG emitter accounting for 10 per cent of global emissions (Friedrich et al., 2015). Europe has historically seen itself as a leader by example as regards climate action, with ambitious targets internationally, a wealth of European Directives and national legislation that will allow Europe to meet its 2020 climate and energy commitments (European Commission, 2017). European burden sharing is however far from straightforward. This is so as there are significant asymmetries across Europe’s member states in terms of economic development, emissions, natural resource endowment and citizen demand for climate action. These asymmetries give rise to diverging negotiating positions and marked differences in member states’ will to engage in a transition to a low carbon development model. Asymmetries and diverging interests and negotiating positions have resulted in the EU being considered a ‘lab’ for the rest of the world (Jordan et al., 2010) in terms of international climate negotiations. Despite asymmetries, it can be argued that several factors have led the EU to engage in ambitious climate action. These include: EU’s energy dependence, concern for energy prices, an existing institutional setting conducive to ambitious climate action, a good track record of meeting

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458   Handbook of energy politics climate pledges while increasing economic growth and overall strong citizen demand for climate action at home and abroad. According to the European Commission, the EU imports over 50 per cent of it energy, 90 per cent of the oil it consumes and two thirds of its natural gas, footing a bill for energy imports of over €1 billion every day (European Commission, 2014). Its main suppliers are not widely diversified on the whole, with the exception of countries like Spain (Escribano, 2014). For instance, according to Eurostat (2017), over 70 per cent of solid fuels were imported by the EU from three countries with Russia accounting for 21 per cent of imports, Colombia amounting to 21.2 per cent and imports from the US topping 20.5 per cent. More than 50 per cent of the EU’s crude oil imports also originated from three countries: Russia (30.4 per cent), Norway (13.1 per cent) and Nigeria (9.1 per cent). Finally, over 80 per cent of EU’s natural gas imports were imported from three countries, Russia (37.5 per cent), Norway (31.6 per cent) and Algeria (12.3 per cent). Energy dependence from a handful of countries (especially Russia) and energy security concerns carry significant weight on the EU’s push for a diversified energy mix that increasingly includes renewable energy sources (Averchenkova et al., 2016), aligning energy and climate interests in the EU. An additional element supporting Europe’s climate policies is the decoupling of GHG emissions from economic growth, with EU’s GDP 45 per cent higher and GHG emissions 19 per cent lower in 2013 than in 1990 according to Debelke and Vis (2016). Institutionally, the European Commission – with a stable and largely pro-climate action bureaucracy – the European Parliament and progressive member states have enabled ambitious climate commitments in the past. Within member states it is known that northern and western member states such as Germany, with limited domestic fossil fuel resources and a developed renewable energy sector, have traditionally been more supportive of stringent climate action. Eastern member states with large reserves of fossil fuels such as Poland, for instance, have traditionally dragged their feet as regards climate ambition (Averchenkova et al., 2016) and are known for blocking progress to a certain extent (Nelsen, 2017). This blockage, and potentially lower ambition, are more likely after the UK vote to leave the EU (Brexit). The UK’s decision to leave the EU implies Europe loses one of its most skilful climate negotiators both domestically and internationally. Domestically, the UK has been a leader in passing and implementing climate legislation. In fact, since 2008 it has implemented the Climate Change Act (CCA) that sets the goal of reducing GHG emissions by at least 80 per cent by 2050 compared to 1990. One of the key features of the CCA is that it establishes legally binding carbon budgets that limit GHGs

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The geopolitics of climate action after the Paris Agreement  ­459 over five year periods, being the first country in the world to use carbon budgeting (Department of Business, Energy and Industrial Strategy, 2016). Internationally, the UK has also pushed for ambitious mitigation commitments. For instance, the UK was instrumental in the adoption of the EU’s 2030 target to reduce GHG emissions by 40 per cent compared with 1990 levels, a target now enshrined in the EU’s NDC. The UK was also instrumental in the development of the European Emission Trading System (EU ETS), to date the largest carbon market in the world and one of the key instruments used by the EU to reign in emissions from high GHG emitting industries. The UK, the second largest GHG emitter in the EU after Germany, accounted for 12.6 per cent of European GHG emissions in 2014 according to Eurostat (2017). Additionally, 9 per cent of European installations regulated under the EU ETS are in the UK. The weight and ambition of the UK as regards climate commitments has, not surprisingly, had a bearing in past and current climate ambition in the EU. Climate and energy decisions in the EU are generally taken by qualified majority,13 which currently implies obtaining favourable votes from 16 out of 28 member states. Losing the UK, one of the (generally) progressive member states in voting procedures, could reduce Europe’s climate ambition or entail more trade-offs within Europe. As climate and energy issues will be negotiated as part of the larger EU–UK divorce package, it is, at the time of writing, too early to fully evaluate the consequences of Brexit on EU’s climate ambition. The fact that EU and UK legislation have co-evolved in the past, that the UK passed its fifth carbon budget shortly after the vote to leave the EU, and that Europe has repeatedly stated its resolve to push ahead with its low carbon transition should however offer some reassurance of climate action commitment by both the EU and the UK. The EU could even capitalise on the leadership vacuum left by the US to liaise with China (Crisp, 2017), and perhaps to triangulate with Latin America and the Caribbean to lead international climate negotiations in the future. Moving on to the analysis of demand for climate action it is relevant to take into account that EU citizens’ concern about climate change is high, although Europeans are more concerned about poverty, hunger and lack of drinking water, international terrorism and the economic situation. In the last available survey conducted by the European Commission 69 per cent of Europeans thought climate change was a very serious problem, 93 per cent advocated for globally concerted climate action, over 90 per cent supported national policies to boost energy efficiency and to increase the use of renewables, with over 80 per cent stating that climate action and energy efficiency increases economic growth and jobs (European

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460   Handbook of energy politics Foreign policy priorities in France weighted index (*)

65 40

34

Support French business interests

22

Fight climate change

Fight international terrorism

Invest in development aid

20

19

Improve Increase France’s France's influence in the image abroad world

(*) Index = (first *1) + (Second * 0,66) + (Third * 0,33)

Source:  Real Instituto Elcano (2017: 106).14

Figure 18.4  Foreign policy priorities for French citizens Commission, 2015). Aggregated figures, however, mask stark differences among countries, reinforcing the asymmetric nature of climate engagement across member mtates. As regards foreign policy priorities, in countries such as France, Germany or Spain (as is the case in the US), citizens state that fighting climate change is their second foreign policy priority after fighting international terrorism (Real Instituto Elcano, 2017). Interestingly, and once again emphasising the above asymmetric picture of the EU, countries such as Portugal or Italy rank climate change lower in their foreign policy priorities preferences. Not surprisingly, the UK, with a complex foreign policy agenda ahead after Brexit, ranks climate change lower as a foreign policy priority compared to France, Germany or Spain. b)  European initiatives The EU has drafted the road map to a low carbon development model by mid-century. Ahead of 2050, Europe has climate and energy commitments in 2020 and 2030. Europe’s 2020 commitments, as reported in ‘Europe’s climate change opportunity’ (European Commission, 2008), included binding targets to reduce GHGs by 20 per cent and ensuring 20 per cent of European energy comes from renewable sources. It also included a nonbinding target to improve energy efficiency by 20 per cent. Given Europe’s decoupling of economic growth and GHG emissions plus its growth in renewable energy, it is expected that Europe will meet its 2020 energy and climate change goals (EEA, 2016). EU’s 2020 targets are expected to be met despite unequal progress across member states. Map 18.1 represents progress of member states towards 2020 climate and energy targets in 2014.

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The geopolitics of climate action after the Paris Agreement  ­461 Foreign policy priorities in Germany weighted index (*)

64 46 27

Support Fight climate German business change interests

Fight international terrorism

23

24

Invest in development aid

Improve Germany's image abroad

15 Increase Germany’s influence in the world

(*) Index = (first *1) + (Second * 0,66) + (Third * 0,33)

Source:  Real Instituto Elcano (2017: 105).15

Figure 18.5  Foreign policy priorities for German citizens Fight jihadist terrorism

6.4

Fight climate change

6.1

Support Spanish business interests abroad

5.8

Invest in development aid

5.7

Fight the self-denominated Islamic State

5.3

Fight drug trafficking

5.1

Ensure supply of gas, oil and electricity

4.4

Avoid illegal immigration

4.2

Increase Spain’s influence in the world

3.6

Increase influence of Spanish language and culture

3.5

Source:  Real Instituto Elcano (2017: 18).16

Figure 18.6  Foreign policy priorities for Spanish citizens

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462   Handbook of energy politics Foreign policy priorities for Italian citizens Weighted index (*)

44

35

Support Italian business interests

56

23

Fight climate change

Fight international terrorism

Invest in development aid

21

19

Improve Italy's image abroad

Increase Italy’s influence abroad

(*) Índice = (Primer lugar *1) + (Segundo lugar * 0,66) + (Tercer lugar * 0,33)

Source:  Real Instituto Elcano (2017: 107).17

Figure 18.7  Foreign policy priorities for Italian citizens Foreign policy priorities for UK citizens weighted index (*)

49

42

33

26

Support UK business interests

Fight climate change

Fight international terrorism

Invest in development aid

21

Improve UK image abroad

29

Increase UK influence in the world

(*) Index = (First *1) + (Second * 0,66) + (Third * 0,33)

Source:  Real Instituto Elcano (2017: 105).18

Figure 18.8  Foreign policy priorities for UK citizens The outlook towards the EU’s 2030 targets and 2050 targets is however bleaker. As regards the ‘2030 framework for climate change and energy policies’ (European Council, 2014), current efforts are not enough to reduce GHG by 40 per cent compared to 1990 levels. A better outlook is provided for renewable energy and energy efficiency targets within the 2030 framework. As regards the former, current efforts, if maintained, would be enough to ensure 27 per cent of Europe’s final energy consumption would come from renewables, but reducing policy uncertainty by implementing  stable policies is required to ensure investment at scale (Campiglio, 2014). Lastly, the European Environment Agency estimates that it is feasible to achieve an improvement in energy efficiency by 27 per cent by 2030 (EEA, 2016).

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The geopolitics of climate action after the Paris Agreement  ­463 Foreign policy priorities for Portuguese citizens Weighted index (*)

49

45

24

Support Fight climate Portuguese change business interests

26

Fight international terrorism

Invest in development aid

27

28

Improve Portugal's image

Increase Portuguese influence abroad

Source:  Real Instituto Elcano (2016).19

Figure 18.9  Foreign policy priorities for Portuguese citizens Europe’s ‘Roadmap for moving towards a low carbon economy by 2050’ (European Commission, 2011) states the goal of reducing GHG emissions by 80 per cent by mid-century compared with 1990 levels. It additionally states that mid-term objectives of reducing EU’s emissions by 40 per cent in 2030 and by 60 per cent in 2040 compared with 1990 levels would be cost-effective. The effort required to meet the different GHG reduction goals would be ramped up to take advantage of cost reductions brought about by technology development. Figure 18.10 illustrates how the EU envisages the transition to a low carbon economy. While reductions are significant across all sectors, the European power sector is expected to be virtually carbon free by 2050. Residential and tertiary sectors are also expected to substantially cut GHG emissions. Electricity is additionally expected to partially displace fossil fuels in transport, heating and cooling. Implementation of climate change policies within the EU is enabled by directives, regulations and implementation decisions (Averchenkova et  al., 2016).20 In order to meet EU’s climate commitments, one of the cornerstones of European climate policy, the EU ETS, limits emissions from industrial activities including fuel combustion, oil, coke and steel production, cement, paper and pulp and so on. See Annex I of Directive 2003/87/EC for a full list of sectors included in the EU ETS.21 The Emissions Trading System currently covers around 11,000 installations in the EU and about 45 per cent of GHG emissions. The goal of Directive 2003/87/EC, the Linking Directive (2004/101/EC) and Directive 2009/29/ EC, as part of the climate and energy package to meet EU’s 2020 goals, was to reduce GHGs from emission-intensive sectors in a cost-efficient way and to spur innovation, benefiting from static and dynamic efficiency

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464   Handbook of energy politics

Note: The shading indicates whether countries are considered on track or not towards their 2020 climate and energy targets. For greenhouse gases, dark grey means that 2014 emissions covered by the Effort Sharing Decision (ESD) were above the 2014 national ESD target. White/no shading means that projected ESD emissions in the ‘with existing measures’ scenario for 2020 are above the 2020 national ESD target.

Source:  EEA (2016: 10).

Map 18.1 Progress of member states towards 2020 climate and energy targets in 2014

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The geopolitics of climate action after the Paris Agreement  ­465 % 100

80

60

% 100

Power Sector Current policy Residential & Tertiary

80

60

Industry 40

40 Transport

20

20 Non CO2 Agriculture

Non CO2 Other Sectors 0 1990 2000 2010

2020

2030

2040

0 2050

Source:  European Commission (2011: 5)

Figure 18.10 European GHG emissions by sector in 2050 (100 per cent = 1990) ­ roperties of economic instruments. The oversupply of permits in the p first phases of the EU ETS has however limited the carbon price. Hence the ETS is currently being revised to try to reduce the aforementioned oversupply of permits and to provide a long-term price signal. In order to do this the EU has decided to ‘backload’ permits (that is, withhold 900 million allowances until 2019–20, thereby reducing oversupply and limiting price volatility). For the long term, the EU is setting up a Market Stability Reserve (MSR) that will detract permits when there is oversupply and inject them back into the EU ETS when there is a shortage of permits. Additionally, the number of permits (the ‘cap’ in the EU ETS) will be gradually reduced, by a factor of 1.74 per cent annually up to 2020 and by 2.2 per cent from 2021 to 2030 if the European Commission proposal is implemented (EC, 2017). As for diffuse sectors (transport, buildings, agriculture and waste), goals are regulated between 2013 and 2020 by the Effort Sharing Decision 23/04/2009 (ESD) according to which each Member State (MS) is required to reduce its emissions by a certain percentage by 2020 compared to 2005 according to its relative wealth measured in terms of GDP. All countries agreed on the final emission reduction goals. By 2020 diffuse sectors across

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466   Handbook of energy politics the EU will reduce their emissions by 10 per cent compared to 2005 levels. In order to meet the 2030 goals, diffuse sectors will have to ramp up their efforts post 2020. Following on the footsteps of the ESD, the Effort Sharing Regulation (ESR) is currently being negotiated (see the Commission’s proposal 20/07/2016 – COM/2016/482) to ensure diffuse sectors across Europe reduce GHG emissions by 30 per cent by 2030 compared to 2005 levels. The burden sharing arrangement for the ESR will also be based on GDP per capita, but targets will be adjusted to ensure cost effectiveness. As was the case in the ESD, the ESR allows flexibility (banking, borrowing, buying, selling) in addition to two new elements of flexibility: a one-off possibility to access to the EU ETS and the possibility to access credits from the land-use sector. Energy security concerns, among others, sparked by Europe’s dependence on Russia’s fossil fuels, fostered the development of Europe’s Energy Union in 2015. This energy strategy is based on five pillars: diversifying energy sources, integration of Europe’s internal energy market, increasing energy efficiency, a transition to a low carbon economy – based on international commitments, actions under the EU ETS, the ESD and ESR, low-emissions transport system and strong renewable energy policy – in addition to increasing support for low carbon innovation and technology. Beyond ensuring energy security, it has been argued that, if handled appropriately, the Energy Union could drive the transition to a low carbon Europe. For that, it must garner continued support at a time when the European project has been called into question on economic, humanitarian, social and integration fronts. c)  International engagement The European Union has been a directional leader in crafting the international climate architecture (Jordan et al., 2010). Although the US and Japan could be seen as having finally won the institutional battle in terms of the Paris Agreement – as they have historically argued for a pledge and review system rather than the preferred targets and timetables approach traditionally advocated by the EU – it can be argued that the EU pushed international negotiations at critical junctures. During the Earth Summit in Rio de Janeiro in 1992, the EU increased the ambition enshrined in the United Nations Framework Convention on Climate Change. As regards the Kyoto Protocol’s first commitment period (2008–2012), the EU committed to an 8 per cent reduction in GHG compared with 1990 levels, arguably the most ambitious target within Annex I countries. When the US failed to ratify the Kyoto Protocol in 2001, the EU pushed the negotiation process forward and supported

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The geopolitics of climate action after the Paris Agreement  ­467 Russia’s accession to the World Trade Organization (WTO) in exchange for its ratification of the Kyoto Protocol, which in turn enabled the entry into force of the Kyoto Protocol on the 16 February 2005. After the Copenhagen diplomatic debacle in 2009, where the EU was sidelined from the Copenhagen Accord,22 the EU demonstrated continued and reliable commitment with the international climate negotiation process. In Durban, the EU, along with Small Island Developing States and Less Developed Countries, fast tracked the development of what would later become the Paris Agreement. In exchange for this, the EU accepted the Kyoto Protocol’s second commitment period and pledged to reduce GHGs by 20 per cent by 2020 (Bodansky, 2012). This occurred despite the fact that disagreements with Poland over allocation of carbon credits have so far prevented the EU from formally ratifying the Doha Amendment for extending the Kyoto Protocol into a second commitment period (Climate Home, 2017). From Copenhagen (COP 15) to Paris (COP 21) the European Union has continuously been involved in the development of the building blocks leading to the Paris Agreement. Perhaps the best known European diplomatic efforts include the EU’s alliance with the High Ambition Coalition,23 and the diplomatic masterclass in climate negotiations offered by French diplomacy, resulting in the adoption of the Paris Agreement. It should also be noted that, along with American and Chinese ratifications, Europe’s ratification was instrumental in the entering into force of the Paris Agreement. However, as regards Europe’s climate ambition level, the EU’s Nationally Determined Contribution states it will reduce GHG emissions by 40 per cent by 2030 compared with 1990 levels. Analysis by Climate Action Tracker claims that this amounts to a medium level of ambition that would not take us towards the ‘well below 2ºC’ if other parties undertook efforts similar to those of the EU. In fact, at present, only Costa Rica, Ethiopia, Morocco, Bhutan and The Gambia, which together contribute less than 1 per cent to global emissions, have climate commitments estimated to be sufficient to limit global average temperature increases to below 2ºC, should other countries undertake similar efforts (Climate Action Tracker, 2017).

4. A CRITICAL ANALYSIS OF THE PARIS AGREEMENT On 12 December 2015 the Paris Agreement was adopted after six years of negotiations post Copenhagen. It is a hybrid agreement that relies on topdown rule development and oversight in addition to bottom-up country

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468   Handbook of energy politics engagement by which parties decide on their NDCs according to their national interests, capabilities and circumstances. In stark contrast to the Kyoto Protocol, the Paris Agreement does not dictate mandatory emission reductions, it does not impose penalties for non-compliance, there are no commitment periods that require recurrent negotiations à la ‘Doha Amendment’, and it encourages all countries, developed and developing, to undertake climate action. The Paris Agreement is argued to better reflect the realpolitik of climate action, largely responding to the historical demands for a pledge and review system advocated for by the US and Japan for over 25 years (Bang et al., 2015). The agreement is legally binding on procedural issues such as the requirement to present commitments (NDCs) every five years that would ideally be increasingly ambitious. It is up to countries however to ratchet up ambition. This flexibility in the Paris Agreement could provide Trump with the possibility of reducing current ambition, and hence claim he has brokered a good deal for the US, while remaining a party to the Paris Agreement. In turn, this could reduce the possibility of defection by other parties (Diringer, 2017). The Paris Agreement is also legally binding on reporting emissions and progress towards meeting NDCs. However, ­actually achieving the commitments is not legally binding. As Bodansky (2016: 1) puts it ‘the Paris Agreement is a treaty within the definition of the Vienna Convention on the Law of Treaties, but not every provision of the agreement creates a legal obligation’. This careful climate architecture is said to have enabled US ratification as an executive agreement falling under the US president’s foreign affairs prerogative (Bodansky and Spiro, 2016). The key elements within the agreement reflect much of the prior commitments already included in the Copenhagen Accord. Hence, the Paris Agreement will strive to limit temperature increases to well below 2ºC (aspiring to limit temperature increases to 1.5ºC). The climate finance goal enshrined in the Copenhagen Accord is also reflected in Decision 1/CP.21 accompanying the Paris Agreement by which developed countries are strongly urged to disburse US$ 100 billion annually by 2020 to developing countries for mitigation and adaptation. Furthermore, the US$ 100 billion mark is set to represent an annual climate finance floor from 2025 onwards. The debates regarding whether the climate finance goal will be met and whether this figure is adequate are not expected to be settled in the short term. The BASIC group, for example, has historically argued that finance from developing countries should be accounted for in a transparent manner and under robust accounting rules that avoid double counting, repeatedly expressing concerns about de facto climate finance disbursements.

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The geopolitics of climate action after the Paris Agreement  ­469 Table 18.4 Key elements of the Paris Agreement and the accompanying decision Commitment GHG emission reductions (%)(1900)   baseline Renewable energy (%) Energy efficiency (%)

2020

2030

2050

20

40

80

20 20

≥27 ≥27

55 32%–41%

Source:  Lázaro (2016b: 60).

Other key elements in the Paris Agreement include: retaining the principle of common but differentiated responsibilities and respective capabilities (CDR-RC); inclusion of the goal to reach a global peak in emissions as soon as possible; striving for a balance between emissions and absorption capacity by sinks by the second half of the century; and, the common transparency framework and regular stocktake that, it is hoped, will provide incentives for implementation and increasing ambition. Table  18.4 depicts the key elements of the Paris Agreement and the accompanying decision to the Paris Agreement. Despite being legally binding on procedural matters, having no penalties and being voluntary on substantial issues such as countries commitments, perhaps the core achievements of the Paris Agreement are the unequivocal signal it sends that the world will travel (at greater or lesser speed) towards a low carbon future and that governments are committing to sustainable development. Recent events such as President Trump’s withdrawal from the agreement, the potential domino effect the US withdrawal could have on less willing parties, the sluggish economic recovery after the 2008 crisis and the reshaping of the European project after Brexit are the headwinds against which the Paris Agreement will have to contend. However, there are reasons to believe that climate action is indeed irreversible. Scientific consensus on the urgency of action, the economics of renewable deployment, existing institutional frameworks, the political capital invested in negotiations, the increasing demand for climate action by citizens and business alike are strong tailwinds that push climate action forward. Nevertheless, the question of whether action planned will be enough to avoid the worst consequences of climate change remains unanswered at this stage. The scale of the challenge is unprecedented. Three elements can be seen as crucial for success: effectively implementing ­increasingly ­ambitious climate commitments (Averchenkova and Bassi, 2016), strengthening the economic case for action and scaling up climate finance (Espinosa, 2017; Campiglio, 2014).

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470   Handbook of energy politics Whether countries commitments can be seen as credible, that is, their climate commitments having a likely chance of being implemented, has been recently analysed by Averchenkova and Bassi (2016). Credibility is argued to be a crucial element of the success of the Paris Agreement, as the absence of penalties requires the use of non-coercive instruments to deter free-riders and foster increasing ambition. Credibility of party commitment is expected to help build trust among parties and encourage increasingly ambitious climate engagement. According to the above authors, countries that exhibit several characteristics are more likely to implement climate commitments; that is, they are more credible. Countries with a complete and coherent (integrated) set of climate policies, with transparent and inclusive decision-making procedures, supportive public and private institutions, a history of international climate engagement and delivery of climate commitments, with high citizen awareness of climate change and no policy reversal, are expected to be more credible in the implementation of their climate commitments. The analysis across G20 countries, overall, shows positive results. Within the EU, France, Germany, Italy and the UK are broadly assessed as credible partners as regards their climate commitments. Australia, Brazil, Japan, Mexico, Russia, Turkey, South Africa and the United States are evaluated as moderately credible, although it must be noted that the analysis was undertaken before President Trump announced US withdrawal from the Paris Agreement. Argentina, Canada, China, India, Indonesia and Saudi Arabia were evaluated as having significant scope for improving their credibility (Averchenkova and Bassi, 2016). India and China have however expressed steadfast commitment to the Paris Agreement since President Trump was elected and have announced additional clean energy commitments since the above analysis was published in 2016. As regards the institutional response to strengthen the case for climate action and scale up climate finance, there is agreement among economists that pricing carbon should be one of the top priorities. As economic instruments do not ensure environmental effectiveness, other policies will, in all likelihood, be required. Additionally, including climate policy considerations across sectors (also known as mainstreaming or Climate Policy Integration) and fostering the alignment of economic policies (fiscal, monetary and macro prudential policies) with climate policies, are all required for a smooth transition to a low carbon economy (Campiglio, 2014). Institutionally, it should be noted that beyond the increasing use of economic instruments, integration and institutional alignment, there is increasing work done regarding the need to disclose climate exposure and management plans to tackle the systemic risk climate change can entail

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The geopolitics of climate action after the Paris Agreement  ­471 for the global economy (Carney, 2015). An underlying trend in favour of disclosure of exposure to climate risk and increasing risk of litigation (UNEP, 2017) may accelerate the uptake of climate action by governments and non-state stakeholders.

5.  CONCLUSIONS The shift from government management of environmental problems to the governance of these issues has crystallised in the realm of climate action. Being an externality of planetary proportions as well as a ubiquitous problem, climate change requires the involvement of actors across society as well as the involvement of all levels of government. In this sense, climate change has become one of the defining governance challenges of this century. Whether climate change will be reined in to ensure we abide by the 2ºC guardrail depends on a host of issues. These include, among others: increasing certainty regarding the effects of climate change, establishing direct links between extreme weather events and a changing climate, the short- and medium-term economic consequences of action and inaction, awareness of climate change by society, demand for domestic and international climate engagement and the effectiveness of climate diplomacy in navigating the choppy waters of rule book development after the entry into force of the Paris Agreement. The past two years have given climate analysts both encouraging signs and, at least, two reasons for concern. As regards the former, the adoption and unexpectedly fast entry into force of the Paris Agreement have signalled the global political will to engage in a low carbon energy transition. The reasons behind this political push have been both internal as well as international. Internally, concerns about the co-impacts of climate ­inaction – especially as regards health effects – the exhaustion of ‘old’ energy and emission-intensive economic models in China, concerns about energy security and independence, demand for low energy prices, reductions in the cost of renewables and the desire to lead the low carbon transition are key elements driving climate action. Internationally, the desire to gain or maintain leadership positions in the international climate regime and to reinforce parties’ position as credible partners on global matters can help explain ambitious commitments. Climate change has become a socio-economic and political concern, as well as an environmental one. This fact alone could potentially lead us to a turning point in climate action. Headwinds against climate action are however significant. Free-rider incentives abound in the management of global public goods such as

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472   Handbook of energy politics the provision of a stable climate. American withdrawal from the Paris Agreement, when it materialises, will provide less willing partners incentives to defect. Europe, a self-proclaimed directional leader in climate action since the 80s has problems of its own. The European project is in dire need of reformulation. This is due to the unsatisfactory handling of economic crisis in addition to the slow and uneven recovery, the unresolved issue of migration and the loss of one of its most active climate negotiators after Brexit. In the midst of these troubled international waters, China, a renewed EU and perhaps Latin America may help maintain the spirit of the Paris Agreement long enough to reach the tipping point in the low carbon transition. Implementation, litigation, the economic case for climate action and the availability of sufficient climate finance are the main indicators of the future success of the Paris Agreement.

NOTES   1. Given that climate change entails different types of market failure (imperfect information, the existence of a public good, negative externalities . . .) there is also a need to use a wide array of coordinated and mutually supportive climate policy instruments (Fankhauser et al., 2011), which according to Jordan et al. (2005) is also indicative of a shift in policy from government (command and control and rules-based initiatives) to governance (with the increasing uptake of economic instruments and voluntary based initiatives). Although references will be made to these instruments, the scope of this chapter is largely limited to the analysis of different actors and institutions.   2. Note that some scholars such as Chris Hope and David Newberry (2006) warn that there is a ‘catch’ as regards the headline numbers behind the Stern Review. Aligned with Mark Carney’s 2015 speech on the ‘Tragedy of the Horizon’ (Carney, 2015), Hope and Newberry claim that while the costs of climate action are borne in the short run and are paid for by identified parties, the benefits of climate action materialise in the future and the beneficiaries are diffuse. Additionally, Hope and Newberry explain that the costs of climate inaction reported in the Stern Review were higher than those reported in previous analyses due to three reasons: the Stern Review included updated scientific evidence published after the IPCC’s Third Assessment Report, and it included a wider array of impacts compared to previous work (including, among other, the risk of system discontinuities and extreme weather events) and it used discount rates that were lower than those used by other scholars.   3. RCP is the acronym for Representative Concentration Pathways used in the IPCC’s Fifth Assessment Report (AR5) to represent different concentrations of greenhouse gases which ‘result from different combinations of economic, technological, demographic, policy, and institutional futures’ (http://sedac.ipcc-data.org/ddc/ar5_scenario_ process/RCPs.html).   4. Despite the calls for pricing carbon and the many carbon-pricing mechanisms in place (or planned) around the world (World Bank, 2016), command and control (CAC) that lacks static and dynamic efficiency properties, continues to be profusely used. The reasons for this include the fact that introducing CAC measures might be more politically feasible vis-à-vis introducing economic instruments; they may be easier to lobby, they do not require businesses paying for all emissions and they can be aligned with the moral sense of right and wrong, for example, this is bad and hence it is prohibited. They can also be

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The geopolitics of climate action after the Paris Agreement  ­473 considered a superior policy option to their economic instrument counterparts in cases where damage functions are very steep and marginal abatement cost (MAC) functions are relatively flat. There are also significant caveats to be noted regarding the uncritical support for carbon pricing mechanisms. As Spash (2014) contends, pricing mechanisms such as emission trading schemes may entail large amounts of free allocations to big GHG emitters, leading to a delay in climate action. Taxes, if properly designed, can result in government revenue reductions. Finally, getting taxes right is no small feat in the absence of complete information on MAC curves for firms, so environmental effectiveness should not be taken for granted when taxing GHG emissions.   5. Institutions are understood throughout the chapter as ‘the prescriptions that humans use to organize all forms of repetitive and structured interactions including those within families, neighborhoods, markets, firms, sports leagues, churches, private associations and governments at all scales’ (Ostrom, 2005: 3).   6. The Kaya identity is an algebraic expression of anthropogenic factors that result in CO2 emissions. These include: population multiplied by population per capita multiplied by energy intensity multiplied by carbon intensity per unit of energy produced.   CO2 Emissions = Population 3 (GDP/Population) 3 (Energy/GDP) 3 (CO2/Energy) Even though the Kaya identity is often used to illustrate the main driving forces of anthropogenic emissions, it should be noted that some of the criticisms voiced against the use of this formula include the fact that there may be other factors driving emissions and that the variables in the right-hand side of the equation may not be independent from one another. See: http://www.ipcc.ch/ipccreports/sres/emission/index.php?idp=50.   7. China’s energy demand is expected to increase by 48 per cent in 2035 while increase in production is expected to increase by 40 per cent. By 2035 China is expected to become the largest energy importer in the world, with domestic energy production covering 80 per cent of domestic energy consumption. Energy dependence in 2035 is expected to increase. Oil import dependence will reach 76 per cent and gas import dependence 40 per cent (BP, 2017).   8. China is expected to account for 25 per cent of energy consumption and 20 per cent of energy production worldwide by 2035 (BP, 2016). Hence, Chinese energy mix and climate policies are key to understand the potential GHG emission reductions. According to BP China’s fossil fuel-based energy mix in 2035 will be composed of coal (47 per cent), natural gas (11 per cent) and oil (19 per cent).   9. Note that the survey was coordinated by Qíndice and was conducted via Internet to a panel of respondents. The fieldwork took place between 21 February and 14 May 2017. The sample amounted to 4,468 respondents (between 400 and 443 respondents per country). Quota sampling was based on age, gender and geographical location. The error margins vary from +/-5 per cent for countries with 400 interviews to +/- 4.8 per cent for the country (Turkey) where 443 surveys were completed, for a 95 per cent confidence level and the most unfavourable case (p = q = 0.5). The age of respondents ranged from 18 to 70. For further details on the survey see Elcano Royal Institute (2017). 10. It has been argued that hydraulic fracturing (fracking) has, to a certain extent, displaced coal use that has higher warming potential per unit of energy, but perhaps it has slowed down the use of renewable energy sources (Krupnick et al., 2013). 11. Note that the survey was coordinated by Qíndice and was conducted via Internet to a panel of respondents. The fieldwork took place between 21 February and 14 may 2017. The sample amounted to 4,468 respondents (between 400 and 443 respondents per country). Quota sampling was based on age, gender and geographical location. The error margins vary from +/-5 per cent for countries with 400 interviews to +/- 4.8 per cent for the country (Turkey) where 443 surveys were completed, for a 95 per cent confidence level and the most unfavourable case (p = q = 0.5). The age of respondents ranged from 18 to 70. For further details on the survey see Real Instituto Elcano (2017). 12. That is, the Paris Agreement was designed to circumvent the US political standstill on climate change and being legally binding mainly on procedural issues.

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474   Handbook of energy politics 13. Fiscal matters however are decided by unanimity and procedural issues by simple majority. 14. Note that the survey was coordinated by Qíndice and was conducted via Internet to a panel of respondents. The fieldwork took place between 21 February and 14 may 2017. The sample amounted to 4,468 respondents (between 400 and 443 respondents per country). Quota sampling was based on age, gender and geographical location. The error margins vary from +/-5 per cent for countries with 400 interviews to +/- 4.8 per cent for the country (Turkey) where 443 surveys were completed, for a 95 per cent confidence level and the most unfavourable case (p = q = 0.5). The age of respondents ranged from 18 to 70. For further details on the survey see Real Instituto Elcano (2017). 15. Note that the survey was coordinated by Qíndice and was conducted via Internet to a panel of respondents. The fieldwork took place between 21 February and 14 may 2017. The sample amounted to 4,468 respondents (between 400 and 443 respondents per country). Quota sampling was based on age, gender and geographical location. The error margins vary from +/-5 per cent for countries with 400 interviews to +/- 4.8 per cent for the country (Turkey) where 443 surveys were completed, for a 95 per cent confidence level and the most unfavourable case (p = q = 0.5). The age of respondents ranged from 18 to 70. For further details on the survey see Real Instituto Elcano (2017). 16. Note that the survey was coordinated by Qíndice and was conducted via telephone interviews to a panel of respondents. The fieldwork took place between 17 October and 28 October 2016. The sample size (N) was 1,002. Quota sampling was used for age and gender to represent the region’s (Autonomous Communities) population. The error margin is +/-3.2 per cent for a 95.5 per cent confidence level under the assumption of simple random sampling. The age of respondents is ≥ 18. For further details on the survey see Real Instituto Elcano (2016). 17. Note that the survey was coordinated by Qíndice and was conducted via Internet to a panel of respondents. The fieldwork took place between 21 February and 14 may 2017. The sample amounted to 4,468 respondents (between 400 and 443 respondents per country). Quota sampling was based on age, gender and geographical location. The error margins vary from +/-5 per cent for countries with 400 interviews to +/- 4.8 per cent for the country (Turkey) where 443 surveys were completed, for a 95 per cent confidence level and the most unfavourable case (p = q = 0.5). The age of respondents ranged from 18 to 70. For further details on the survey see Real Instituto Elcano (2017). 18. Note that the survey was coordinated by Qíndice and was conducted via Internet to a panel of respondents. The fieldwork took place between 21 February and 14 may 2017. The sample amounted to 4,468 respondents (between 400 and 443 respondents per country). Quota sampling was based on age, gender and geographical location. The error margins vary from +/-5 per cent for countries with 400 interviews to +/- 4.8 per cent for the country (Turkey) where 443 surveys were completed, for a 95 per cent confidence level and the most unfavourable case (p = q = 0.5). The age of respondents ranged from 18 to 70. For further details on the survey see Real Instituto Elcano (2017). 19. Note that the survey was coordinated by Qíndice and was conducted via Internet to a panel of respondents. The fieldwork took place between 21 February and 14 may 2017. The sample amounted to 4,468 respondents (between 400 and 443 respondents per country). Quota sampling was based on age, gender and geographical location. The error margins vary from +/-5 per cent for countries with 400 interviews to +/- 4.8 per cent for the country (Turkey) where 443 surveys were completed, for a 95 per cent confidence level and the most unfavourable case (p = q = 0.5). The age of respondents ranged from 18 to 70. For further details on the survey see Real Instituto Elcano (2017). 20. Space constraints limit the number of directives, regulations and decisions explored. Other key directives and packages in the EU include: the Renewable Energy Directive (Directive 2009/28/EC), the Energy Efficiency Directive (Directive 2012/27/EU), the Directive on Energy Performance in Buildings (Directive 2010/31/EU), the Directive establishing a framework for the setting of eco design requirements for energy-related products (Directive 2009/125/EC), the Directive 2010/30/EU on ‘the indication by

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The geopolitics of climate action after the Paris Agreement  ­475 labelling and standard product information of the consumption of energy and other resources by energy-related products’ and the circular economy package proposed by the European Commission in December 2015 which would, if approved, become the Circular Economy Directive (amending the following directives: Directive 2008/98/EC on waste, Directive 1999/31/EC on the landfill of waste, Directive 94/62/EC on packaging and packaging waste, Directives 2000/53/EC on end-of-life vehicles, 2006/66/EC on batteries and accumulators and waste batteries and accumulators and 2012/19/EU on waste electrical and electronic equipment). 21. Directive 2003/87/EC of the European Parliament and of the Council of 13 October 2003 establishing a scheme for greenhouse gas emission allowance trading w96/61/ EC. 22. Which was to be the genesis of the much-celebrated Paris Agreement. 23. Led by Foreign Minister of the Marshall Islands Tony de Brum.

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480   Handbook of energy politics Mead, W.R. (1999), ‘The Jacksonian tradition and American foreign policy’. The National Interest. 58, 5–29. Ministerio de Medio Ambiente, Medio Rural y Marino (2009), ‘Guía para periodistas sobre cambio climático y negociación internacional’. Available at: http://www.efeverde.com/ wp-content/uploads/2009/11/Gu%C3%ADa_periodistas_sobre_CC_tcm_arturo-Larena. pdf (last accessed 18 May 2017). Mitchell, R.B. (2003), ‘International environmental agreements: A survey of their features, formation, and effects’. Annual Review of Environmental Resources. 28, 429–61. Natural Resources Defense Council (NRDC) (2010), ‘China records its climate actions by Copenhagen Accord deadline’. Available online at: https://www.nrdc.org/experts/barbarafinamore/china-records-its-climate-actions-copenhagen-accord-deadline (last accessed 18 May 2017). Nelsen, A. (2017), ‘EU climate laws undermined by Polish and Czech revolt, documents reveal’. Climate Home. 29 May 2017. Available online at: http://www.climatechangenews. com/2017/05/29/eu-climate-targets-undermined-polish-czech-revolt-documents-reveal/ (last accessed 30 May 2017). NERA (2017), ‘Impacts of greenhouse gas regulations on the industrial sector’. American Council for Capital Formation Center for Policy Research. Available online at: http:// www.nera.com/content/dam/nera/publications/2017/170316-NERA-ACCF-Full-Report. pdf (last accessed 2 June 2017). Nordhaus, W. (2007), ‘Review of the Stern Review on the economics of climate change’. Journal of Economic Literature. XLV, 686–702. Nordhaus, W. (2012), ‘Economic policy in the face of severe tail events’. Journal of Public Economic Theory. 14 (2), 197–219. Ostrom, E. (2005), Understanding Institutional Diversity. Princeton: Princeton University Press. Real Instituto Elcano (2016), ‘Barómetro de la imagen de España. 6ª oleada. Resultados de mayo-junio de 2016’. Available online at: http://www.realinstitutoelcano.org/wps/wcm/ connect/14199752-8e00-4077-aeb0-68a3e7caaadc/6BIE_Informe_julio2016.pdf?MOD =AJPERES&CACHEID=14199752-8e00-4077-aeb0-68a3e7caaadc (last accessed 22 May 2017). Real Instituto Elcano (2017), ‘Barómetro de la Imagen de España Resultados febreromarzo de 2017, 7ª oleada’. Available online at: http://www.realinstitutoelcano0b7c0d7d66 72/7BIE_Informe_mayo2017.pdf?MOD=AJPERES&CACHEID=7cb3a69f1f934dd3b0d d0b7c0d7d6672. (last accessed 17 May 2017). Saura Estapá, J. (2003), El cumplimiento del Protocolo de Kioto sobre cambio climático. Barcelona: Publicacions Universitat. Sokolov, A., S. Paltsev, H. Chen and E. Monier (2016), ‘Climate impacts of the Paris Agreement’. Geophysical Research Abstracts. 18. Spash, C. (2014), ‘Better growth, helping the Paris COP-out? Fallacies and omissions of the new climate economy report’. SRE-Discussion 2014/04. Institute for the Environment and Regional Development. Vienna University for Economics and Business. Available online at: http://epub.wu.ac.at/4325/1/sre-disc-2014_04.pdf (last accessed 18 May 2017). Stern, N. (2007), The Economics of Climate Change: The Stern Review. Cambridge: Cambridge University Press. Stern, N. (2013), ‘The structure of economic modelling of the potential impacts of climate change: Grafting gross underestimation of risk onto already narrow science models’. Journal of Economic Literature. 51 (3), 838–59. Stokes, B., Wike, R. and Carle, J. (2015), ‘Global concern about climate change: broad support for limiting emissions’. World Resources Institute. Available online at: http://www. pewglchangebroadsupportforlimitingemissions/. (last accessed 7 January 2017). Tabuchi, H. and H. Fountain (2017), ‘Bucking Trump, these cities, states and companies commit to Paris Accord’. The New York Times. 1 June. Available online at: https://www. nytimes.com/2017/06/01/climate/american-cities-climate-standards.html (last accessed 15 June 2017).

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The geopolitics of climate action after the Paris Agreement  ­481 Tagliaprieta, S. and Zachmann, G. (2017), ‘Adieu Paris: what’s next for climate policy if Trump ditches the Paris Agreement?’ Blog Post. Bruegel. Available online at: http:// bruegel.org/2 trumpditchestheparisagreement/ (last accessed 7 January 2018). Taschini, L. (2016), Pers. comm. 11 May. UN (1992), ‘United Nations framework convention on climate change’. Available online at: http://unfccc.int/files/essential_background/background_publications_htmlpdf/applicat​ ion/pdf/conveng.pdf (last accessed 4 April 2017). Underdal, A. (2000), ‘Conceptual framework: modelling supply of and demand for ­environmental regulation’ in A. Underdal and K. Hanf. (eds), International Environmental Agreements and Domestic Politics: the case of Acid Rain. Aldershot, UK: Ashgate, pp. 49–86. UNDP (2016), ‘13th Five-Year Plan: what to expect from China’. Issue Brief. Domestic Policies. UNEP (2016a). ‘The emissions gap report 2016. United Nations Environment Programme (UNEP), Nairobi’. A digital copy of this report along with supporting appendices are available at http://uneplive.unep.org/theme/index/13#egr (last accessed 14 May 2017). UNEP (2016b). ‘The adaptation finance gap report 2016. United Nations Environment Programme (UNEP), Nairobi, Kenya’. Available online at: http://www.unep.org/climate​ change/adaptation/gapreport2016/ (last accessed 14 May 2017). UNEP (2017), ‘The status of climate change litigation – A global review’. United Nations Environment Programme in cooperation with Columbia Law School. Available online at: http://columbiaclimatelaw.com/files/2017/05/Burger-Gundlach-2017-05-UN-Envt-CCLitigation.pdf (last accessed 17 June 2017). UNFCCC (2012), ‘Report of the conference of the parties on its seventeenth session, held in Durban from 28 November to 11 December 2011. Addendum’. Available online at: https:// unfccc.int/resource/docs/2011/cop17/eng/09a01.pdf (last accessed 10 May 2017). UNFCCC (2015), ‘Paris Agreement’. Available online at: https://unfccc.int/files/meetings/ paris_nov_2015/application/pdf/paris_agreement_english_.pdf (last accessed 14 May 2017). Ürge-Vorsatz, D., S. Tirado Herrero, N.K. Dubash and F. Lecocq (2014), ‘Measuring the co-benefits of climate change mitigation’. Annual Review of Environmental Resources. 39, 549–82. Van Rensburg, W. and B.W. Head (2017), ‘Climate change sceptical frames: The case of seven Australian sceptics’. Australian Journal of Politics and History. 1–17. Available online at: http://onlinelibrary.wiley.com/store/10.1111/ajph.12318/asset/ajph12318.pdf?v=1&t=j13cy rsx&s=986ec3d29b63ccba4ce19421825ad0e77b53d54a (last accessed 4 April 2017). Van Rensburg, W. (2015), Climate Change Scepticism. A Conceptual Re-evaluation. SAGE Open. April–June, 1–13. Available online at: http://journals.sagepub.com/doi/ pdf/10.1177/2158244015579723 (last accessed 4 April 2017). Victor, D.G. (2006), ‘Toward effective international cooperation on climate change: ­numbers, interests and institutions’. Global Environmental Politics. 6 (3), pp. 90–103. Weitzman, M. (2007), ‘A review of the Stern Review on the economics of climate change’. Journal of Economic Literature. XLV, 703–24. White House (2014), ‘U.S.–China joint announcement on climate change’. Available online at: https://obamawhitehouse.archives.gov/the-press-office/2014/11/11/us-china-joint-announc​ ement-climate-change (last accessed 18 May 2017). White House (2017a), ‘An America first energy plan’. Available online at: https://www. whitehouse.gov/america-first-energy (last accessed 15 May 2017). White House (2017b), ‘Statement by President Trump on the Paris Climate Accord’. Available online at: https://www.whitehouse.gov/the-press-office/2017/06/01/statementpresident-trump-paris-climate-accord (last accessed 1 June 2017). Wilneius, M. and S. Kurki (2012), ‘Surfing the sixth wave. Exploring the next 40 years of global change’. Finland’s Future Research Centre. FFRC ebook 10/12. Available online at: https://www.utu.fi/fi/yksikot/ffrc/julkaisut/e-tutu/Documents/eBook_2012-10.pdf (last accessed 11 May 2017).

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482   Handbook of energy politics Worldatlas (2017), ‘The top 10 coal producers worldwide’. Available at: http://www.­worldat​ las.com/articles/the-top-10-coal-producers-worldwide.html (last accessed 20 May 2017). World Bank (2016), ‘State and trends of carbon pricing’. Washington: World Bank Group. Climate Change. Available online at: https://openknowledge.worldbank.org/bitstream/ handle/10986/25160/9781464810015.pdf?sequence=7&isAllowed=y (last accessed 18 May 2017). Zenghelis, D. (2016), Pers. comm. 11 May. Zhang, Z. (2015), ‘Climate mitigation policy in China’. Climate Policy. 15 (1), S1–S6.

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Index 2ºC target 435–6, 443, 448, 467–72, 471 9/11 262 Abazi, A. 297 Aboriginal peoples 3, 21–30, 33, 36–7, 39–40 see also Indigenous peoples Abu Dhabi 252, 347 Acemoglu, D. 103 advanced metering infrastructure (AMI) 353–4, 372–3 African Natural Resource Center (ANRC) 217 agriculture 20, 89, 184, 193, 216, 238, 240, 255–6, 264, 266, 331, 465 Alaska 103–4, 106, 116 Albania 274 Alekperov, Vagit 69 Algeria 115–16, 145, 272, 280, 283, 458 Ali Al-Naimi, H.E. 338 Allcott, Hunt 386 Allot, K. 420 Altai 137, 144–5, 149–50 alternative energy 161–3 see also renewable energy American call option 294–5 American Sustainable Business Council 315 Andrews-Speed, Philip 76 Anglo-Persian Oil Company 258 Angola 60–61, 65, 68, 72, 272 Ant Financial 318 APR 57, 59–60 Arab Light 333, 336–9 Arab Spring 267 Aramco 116 Argentina 128–30, 272, 283, 452, 470 Argus Media 332, 344, 346 Argus Sour Crude Index (ASCI) 344 Arizona Public Service (APS) 377 Arrow, K.J. 105 Asia premium debate 335–9 Asian Development Bank 190

Asian financial crisis 1998 52, 154, 169, 188, 190, 192 As-Is Agreement 258 Assad 284 Association for the Study of Peak Oil and Gas (ASPO) 270 austerity 312, 406, 412 Australia 74, 145–6, 169, 269, 274, 280, 282, 344, 452, 470 Austria 274, 281 Averchenkova, A. 448–9, 470 aviation 257, 352 Aviva 319 Ayres, Ian 386 Azerbaijan 272 Bahrain 245, 274 Bali Action Plan 442 Ban Ki-moon 317 Banerjee, A. 103 Bang, G. 448–9 Bank of America 314 barriers to entry 227, 229, 341–2 barter 311, 313 Bashneft 70–72 Bassi, S. 470 Beijing Enterprises Group 134 Beijing Gas Group (BGG) 136–7 Beijing Gas Group Company Limited 64 Belarus 50–51 Belgium 267, 281 Bharat PetroResources 72–3 Bhutan 467 bin Laden, Osama 262 biofuels 282 biomass 162–3, 242, 276, 309, 407, 409–10, 429, 439 Bivens, J. 456 blackouts 174, 185, 195, 359, 369–70, 375, 392 BlackRock 314 Blonz, Joshua A. 384–5

483

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484   Handbook of energy politics Blood, David 319 Bloomberg, Michael 310, 314, 449 Bloomberg New Energy Finance 282 BMI Research 57 Bodansky, D. 468 Bogdanchikov, Sergey 52–3, 55–6 Bolis, Mara 314 Bolivia 68, 274 Bollinger, Bryan 384 Borenstein, Severin 380–81, 383 BP 51, 72, 77, 95, 116, 146, 237, 239, 258, 277, 326, 330, 340, 347, 473 see also TNK-BP Brazil 68, 128–30, 148, 154, 274, 316, 440, 452, 470 Brent crude 335–6, 338–9, 343–4, 346–8 Brexit 407, 427–30, 458–60, 469, 472 Brightness Programme 193 British Columbia Environmental Assessment Office (BC EAO) 3–6, 12, 16, 18–20, 24–6, 28, 30, 32–5 British Columbia Ministry of Aboriginal Relations and Reconciliation (BC MARR) 20, 32–4 British Columbia Ministry of Environment (BC MOE) 19, 35 British Columbia Ministry of Natural Gas Development (BC MNGD) 34–5 British Columbia, natural gas development in 3–40 British Columbia Oil and Gas Commission (BC OGC) 5 British Columbia Treaty Commission 24 British Empire 264, 277 British Petroleum see BP Brunei 274 Bulgaria 270 Burger, Scott P. 363 Burke, T. 411 Burkina Faso 453 Bush, George W. 284 Cameroon 274 Canada 3, 16–19, 22, 24–5, 37, 116, 148, 154, 157, 192, 195, 249, 272, 280, 282–3, 329–30, 369, 451, 470

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Canadian Environmental Assessment Agency (CEA Agency) 3–6, 21, 26, 30 Cancun Agreements 440 capitalism 109, 258 Carbon Capture and Storage (CCS) 405, 407–9, 411, 417, 419–20, 422–3, 429–30 Carbon Disclosure Project (CDP) 315 Carbon Disclosure Standards Board (CDSB) 317 carbon emissions 83–4, 88, 140, 148, 162, 175, 198, 310, 357, 408, 411–12, 420, 445, 447, 473 see also greenhouse gas emissions; lowcarbon energy carbon pricing mechanisms 139 Carbon Tracker 314, 318 carbon trading 424 Carbon Trust 315, 317 caribou 13, 16, 18–20, 33, 35, 38–9 Carney, Mark 310, 316, 472 Ceres 315 Certificate of Public Convenience and Necessity (CPCN) 4–5, 7–8, 11, 20, 30–31, 39 Chad 274 Charness, G. 108 Chávez, Hugo 119, 285 Chernobyl 257 Chevron 237, 258 Chile 274, 374, 452 China 108, 126, 130, 154, 168–71, 173, 175, 215, 224–6, 229, 236, 238, 244, 265, 272, 281, 283, 316–19, 325–8, 330, 336, 339, 344–6, 416, 426, 440, 444, 449, 451–3, 455, 457, 459, 470–72 climate action 444–8, 473 energy development and natural gas development 81–101 evolving energy policy 179–208 low-carbon and green energy 81–91 RIC energy relations 49–77 Sino-Russian gas cooperation 133–50, 168–9, 171 China Development Bank 56, 68–9, 137, 148–9 China Energy Research Society (CERS) 138

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Index  ­485 China Exim Bank 137, 148–9, 225 China Light and Power 185 China National Chemical Corporation (ChemChina) 66, 134 China National Coal Corporation (CNNC) 184 China National Offshore Oil Corporation (CNOOC) 99, 145–7, 184 China National Petroleum and Gas Corporation (CNPC) 53, 55–7, 62–5, 67–70, 72–3, 99, 134–9, 141–5, 148–9, 184 China Petrochemical Corporation see Sinopec China Petroleum Pipeline Bureau (CPP) 148 China Petroleum Planning and Engineering Institute 88, 91, 141–3 China Power Investment Corporation 189–90 Chinese downstream 54, 65–6, 73 Chinese Meteorological Administration 445 Chiu, C. 337 Christianity 260 Churchill, Winston 258, 277 Clean Development Mechanism 200–201 Climate Action 315 Climate Action Tracker 467 Climate Bonds Initiative 316 climate change 84, 87, 138, 145, 175, 255, 267, 276, 310, 314–15, 352, 355, 357, 359, 366–7, 406–7, 412–13, 415–17, 419, 421, 430, 435–7, 447–54, 456, 459–63, 469–73 see also geopolitics of climate action coal 64, 81–2, 85–9, 92–3, 96–7, 101, 138–40, 143–4, 148, 150, 154–7, 160, 173, 183, 185–7, 189, 191, 193–4, 196–7, 202, 206–7, 242, 257–8, 266, 277, 280–22, 286, 309, 332, 355, 376, 411, 416–17, 445–6, 454, 473 coal-bed methane 92–3, 97, 142 Coase, R. 104 Cold War 236, 257, 278

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Colombia 130, 269, 272, 283, 317, 458 colonialism 103, 214 Columbia Center on Sustainable Investment 228 combined cooling, heat and power (CCHP) 89 combined heat and power (CHP) 89 Committee on Climate Change 409, 411 Committee on the Status of Endangered Wildlife in Canada (COSEWIC) 20–21 Commons, J.R. 103 communism 108, 184, 205, 241, 256 Compagnie Française des Petroles 116 Concentrated Solar Power (CSP) 438–9 Constitution Act (1982) 21, 23 Contracts for Difference Feed-in Tariff (CfD Fit) 411, 418–19, 421–2, 424–8 COP 1–7 441 COP 8–14 441 COP 15 436, 440, 442, 447, 467 COP 16 440, 442 COP 17 440, 442 COP 18 440, 442 COP 19 440, 442 COP 20 440, 443 COP 21 440, 443, 467 COP 22–26 443 Copenhagen Accord 16, 438, 440, 442, 455, 467–8 corruption 172, 174, 191, 221, 223, 228, 298, 303 Cosmo Oil 334 cost benefit analysis 364–5 Costa Rica 317, 467 Cox-Rubinstein Model 292 Critical Peak Pricing (CPP) 381 Croatia 274 crude oil 49–62, 66, 68, 70, 72, 74, 76, 116, 170, 238, 240–41, 286, 295–9, 304, 324–5, 329–40, 342–6, 348, 350, 449, 458 see also hydrocarbons Cultural Revolution 183 cybersecurity 357, 366, 380, 388–90, 450 Czech Republic 281

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486   Handbook of energy politics Dalian Commodities Exchange 345 dams 183, 185, 191, 198 Dapena, J. 292 Datang 189–90 Davey, Edward 422 de Castro, L. 375 Debelke, J. 458 decolonization 236 Demand Response (DR) 361–2, 380–82, 388 demand-side management 179, 186, 193–4, 204–6, 373 Deng Xiaoping 184, 188 Denmark 251–2, 274, 406, 415–17, 424, 426, 429 depletion profiles 250–54, 269 depopulation 50 Deterding, Henri 258 Diamond, J. 103 Discount Strategy 114–17, 119–21 Discounted Cash Flow (DCF) 291–2 distributed energy resources (DERs) 351, 354–5, 357–8, 361–2, 365, 367–9, 373–4, 376, 378, 380, 387, 389–90 distributed generation (DG) 356, 361–2, 368, 372, 374, 378–80, 388–9 Doha Agreement 440, 442, 467–8 DPRK see North Korea Drake, Edwin 235 Dubai 136, 333–6, 338–9, 343, 345–9 Dubai Mercantile Exchange (DME) 343 Durban Platform for Enhanced Action 440, 442 Dutch disease 289 Dutra, J. 375 Dvorkovich, Arkady 63 Early Man 255 East Siberia 50, 53, 55, 62, 64, 134–8, 168, 344 East Siberian Oil and Gas Company 134 East Siberia–Pacific Ocean (ESPO) pipeline 50, 54–7, 64, 67–9, 72, 133, 344–5 economic benefit agreements 37–8

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economic growth 36, 49, 84, 87, 91, 101, 103, 126, 153, 179, 184, 186, 188, 190, 194–5, 199, 204, 213, 218–19, 223, 236, 238, 263, 288, 313, 318, 326, 328, 423, 437, 444–5, 447, 457–60 economic institutional systems 108–9 Economics and Technology Research Institute (ETRI) 138–9, 141–4 Ecuador 68, 269, 272 Egypt 272, 276 electric distribution systems (EDS) 354 electric transmission systems (ETS) 354 electric vehicles 243–5, 279, 282, 318–19, 353–4, 356–8, 367, 370, 372, 377 electricity 82–3, 88–9, 144, 155–6, 162, 170, 175, 222, 228, 243, 245, 257, 268, 281, 310, 318–20, 351, 405, 418, 420–21, 423–4, 426–7, 463 see also smart grid in China 179–208 how smart grid is changing the electricity delivery system 369–73 Electricity Market Reform (EMR) 424, 427–8 emission trading scheme (ETS) 445, 473 endangered species 13, 16, 18–21, 33, 35, 38–9 energy diplomacy 172–3 energy efficiency 89, 186, 367, 416–17, 469 Energy Information Administration (EIA) 51, 60–61, 328, 449 Energy Research Institute (ERI) 87, 90, 92–3 energy scandal 174–5 energy security 51, 75, 85, 276, 278, 331, 406, 411, 419, 449, 458, 471 definition of 165–7 Energy Union 466 ENI 237 entrepreneurs 180, 214–15, 218, 222–3, 225, 227, 229, 261, 309, 320 Environment and Climate Change Canada (ECCC) 18 Environmental Assessment Certificates (EACs) 4–10, 12, 20, 28–31, 39

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Index  ­487 Environmental Assessment Decision Statement (EADS) 4–5, 8–11, 20, 30–31, 39 environmental assessments (EAs) 3–13, 16, 18, 21, 25–31, 33, 36, 38 environmental issues 11–21, 100, 105–6, 139, 156–7, 164–5, 175, 179, 187, 205–6, 267, 310–11, 315, 351, 355, 364, 366–7, 376–9, 382, 407, 413–14, 416, 429, 444, 446, 448, 450, 471, 473 see also carbon emissions; climate change; greenhouse gas emissions; pollution in China 81–3, 88 environmental management plans (EMPs) 31, 39 Environmental Protection Agency 187 Envision Solar 319 Equator Principles 315 Equatorial Guinea 145 Ernsberger, Dave 337 Esco-Interamerica Company 117 Essar Oil Limited (EOL) 73–4 Ethical Markets 315–16, 319–20 Ethiopia 215, 453, 467 Euratom Treaty 428 Europe 49–50, 52, 55, 57, 59–60, 74–5, 96, 126, 133, 265, 269, 273, 283, 285, 313, 315, 324–5, 329, 336–7, 340, 429, 457, 472 see also individual countries European Commission 340, 437, 458–9, 465 European Environment Agency 462 European Parliament 458 European Union (EU) 50, 60, 74–5, 82–3, 150, 203, 267, 298, 317, 341, 343, 406–8, 415–16, 418, 420–22, 425, 427–9, 440, 444, 448–9, 457, 470, 472 see also Brexit climate action 457–67 EU ETS 427, 459, 463, 465–6 Eurostat 408, 458–9 Exchange of Futures for Swaps (EFS) 336, 338–9 exploration 248–51 Export-Import Bank of China see China Exim Bank

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extreme weather events 352, 357, 359, 436, 454, 471–2 see also climate change Exxon 258 ExxonMobil 66, 237–8, 347 see also Mobil Far East Petrochemical Company (FEPCO) 134 Faruqui, A. 382, 384 Federal Energy Regulatory Commission (FERC) 380 Federal Trade Commission (FTC) 340 Felicitas Foundation 319 female emancipation 256–7 financial crises 472 2008 66–8, 125, 194–5, 202, 267, 315, 406, 412, 448, 469 Asian 1998 52, 154, 169, 188, 190, 192 Finland 157, 281, 317 Finser, Mark 319 FINTECH 311–12, 317 First Nations people 21–4, 28–30, 36–7, 40 fisheries 27, 31 Florida Power and Light 310 flue-gas desulphurization (FGD) equipment 193–4, 204–5 foreign direct investment 190, 213, 215, 218 foreign policy 284, 447, 450, 454, 460–63 forestry 19, 32, 267, 447 Forum for the Future 315 fossil fuels 3, 82–3, 87, 148, 154, 198, 235, 257, 279, 309, 311, 313–14, 318, 324, 347, 367, 405, 407–10, 413, 415, 435, 438, 448–9, 458, 463, 466, 473 see also individual fuels Fowlie, M. 385–6 fracking 249, 253, 266, 270, 282–3, 314, 449, 473 Fradkov, Mikhail 55–6 France 98, 115, 154, 192, 199, 257, 261, 274, 277–8, 280–81, 283, 451, 460, 464, 470 free trade agreements 170–71 Frei, Christoph 406

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488   Handbook of energy politics Frey, B.S. 107 Friedman, M. 112 Fukushima disaster 167, 171, 174–5, 199, 257, 405 Future 500 315 G20 316, 318, 340, 470 Gabon 274 Gambia 467 gas price mechanism 95–9, 101 Gates, Bill 313 Gazprom 50, 62, 64, 135–8, 145, 149–50, 169, 285 Gazprombank 149 GDP 82–3, 91, 111–12, 138, 188, 215–18, 223–4, 238, 282, 311, 315–16, 318, 325–6, 355, 437, 445–7, 456, 458, 465–6 General Motors 243 geopolitics of climate action 435–72 geopolitics of the future 276–87 geothermal power 163, 268, 309, 407, 439 Germany 98, 154, 157, 168, 203, 260–61, 264–5, 274, 278, 280–81, 283, 286, 317–18, 357, 406, 415, 424, 426, 451, 460–61, 464, 470 Ghana 68, 453 Ghatak, M. 103 Gleaser, E. 103 Global Impact Investing Network (GIIN) 315 global warming 248, 405 see also climate change globalization 292, 315, 338 Gogerty, Nick 320 Golden Sun Demonstration Programme 203 Goldman Sachs 314, 331 Gore, Al 319 Governor in Council (GIC) 5 Grant, Lindsey 267 Great Depression 258, 265 Great Leap Forward 183 Greece 267, 281 Green Digital Finance Alliance 318 green finance 309–20 Green Transition Scoreboard (GTS) 310 greenfield oil exploration 105, 110

M4475-CONSIDINE_9781784712297_t.indd 488

greenhouse gas (GHG) emissions 6, 13–18, 31, 33–4, 38, 81, 83–4, 86–7, 157, 161, 175, 267, 279–80, 352, 355, 359, 361, 363, 365, 376, 407–12, 422–3, 436, 444–5, 448, 450, 454–5, 457–60, 462–3, 465–7, 469, 473 see also carbon emissions; low-carbon energy Greenstein, Gus 382 grizzly bear 13, 16, 20–21, 35, 38–9 Gulf Cooperation Council (GCC) 245 Gulf Wars 262 Guodian Coporations 189–90 Hallock, J.L. 120 Hansen, M.W. 213 harbour porpoise 13, 16, 21, 38 Hartmann, Wesley 384 Helfand, J. 107–8 HELIO International 315 Helm, Dieter 408–9, 419 Henderson, Hazel 313, 315–16 Henderson, James 49, 133, 317–19 Hestanov, Sergei 60 Hezbollah 284 Hirschleifer, D. 107 Hitler, Adolf 236 Hledik, Ryan 382 Holland, Stephen 380 Hong Kong 185 Hope, Chris 472 Howlett, M. 181 Huadian 145, 189–90 Huaneng 189–90 Huawei 226 Hungary 62, 274, 281 hybrid cars 243–5 hydraulic fracturing see fracking hydrocarbons 49, 51–2, 62, 69, 76, 88, 117, 218–19, 227, 237 see also crude oil; petroleum hydropower 83, 139, 144, 160, 163, 173, 183, 185–6, 191–2, 198, 202, 205, 276, 309, 311, 407, 409, 439 IHS 237 impact investing 313 Independent System Operator of New England (ISO-NE) 370

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Index  ­489 India 126, 136–8, 154, 168, 224, 238, 265, 272, 316, 325–8, 330, 440, 452, 470 RIC energy relations 49, 51, 53–4, 62, 71–5, 77 Indian Oil 72–3 Indigenous peoples 3–6, 12–13, 21–34, 36–40 RIC energy relations 52 Indonesia 74, 145–6, 164, 272, 282, 316, 325, 452, 470 Industrial Revolution 277, 435–6 industrialization 183–4, 187, 213–14, 228–9 Institute of Energy Economics, Japan (IEEJ) 336 institutions and oil supply 103–21 Intended Nationally Determined Contributions (INDCs) 311 Inter State Gas System (ISGS) 148 Intercontinental Exchange (ICE) 343, 346 Intergovernmental Panel on Climate Change (IPCC) 411, 436, 441, 472 internal combustion engine 255 International Energy Agency (IEA) 87, 94–5, 280, 282, 340, 374, 408 International Energy Exchange (INE) 343, 345 International Energy Forum (IEF) 340 International Monetary Fund (IMF) 161, 289 international oil companies (IOCs) 51, 109–10, 114–15, 117, 119–20, 214, 228 see also individual companies utility difference between IOCs and NOCs 111–14 International Organization of Securities Commissions (IOSCO) 340, 342–3 Internet 257, 311 Inuit 21–2 Iran 60–61, 115–16, 124, 127, 236, 252, 258, 260–63, 272, 277–9, 284–5, 331, 342, 347, 450–53 Iraq 61, 116, 127, 235–7, 252, 261, 263, 272, 277, 331, 450 Iraq Petroleum Company 116 Ireland 267 IRENA 438

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ISIS 127, 450–53 Islam 260, 262, 450 Israel 262–3, 278, 284, 452 Italy 195, 267, 274, 278, 281, 406, 415, 451, 460, 462, 470 Ito, Koichiro 386–7 Jackson, M.O. 108 Jaffe, A.M. 336–7 Japan 49, 51, 71, 76, 82–3, 126, 139, 154, 157, 164, 168–71, 173, 175, 236, 257, 278, 280–82, 325, 330, 336, 339, 344, 452, 466, 468, 470 see also Fukushima disaster Jaquier, Julia Balandina 319 Jessoe, Katrina 384 Johnson, S. 103 Jordan 451 Jordan, A. 472 Joskow, P.L. 375, 381 Judaism 260 Kahneman, D. 112–13 Kasyanov, Mikhail 53 Kaya identity 473 Kazakhstan 51, 57, 65, 68, 70, 76, 144, 169, 272 KazMunaiGaz 70 KazTransOil 70 Kenya 215, 226, 311, 453 Khodorkovskiy, Mikhail 53 Khristenko, Victor 56 Kidney, Sean 316 Kind, Peter 352 Kleinman, Seth 60 Kleissner, Charly and Lisa 319 Kogan, N. 107 Kogtev, Yuri 69 Korea Hydro and Nuclear Power (KHNP) 174 Korean Gas Corporation (Kogas) 164 Kot, Evgeny 149 K-Power 164 Krosinsky, Cary 314 Krutikhim, Mikhail 60, 75 Kulatilaka, N. 291 Kuwait 115–16, 235, 237, 245, 252–3, 261–3, 272, 279, 284, 331, 342, 347 Kyoto Protocol 435, 440–42, 457, 466–8

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490   Handbook of energy politics Laherrère, Jean 269 Latin America 65, 103, 127–30, 214, 269, 273, 325, 329–30, 335, 344, 346, 348, 459, 472 see also individual countries Lebanon 276, 284, 451 Lee Myung-bak 172 Leijten, Fenna R.M. 387 Leonard, R. 267 Levelised Cost of Electricity (LCOE) 438–9 Levin, Josh 320 Li Peng 185, 189–91 Libor scandal 339–40 Libya 115–16, 235, 262, 272, 283 Lima-Paris Action Agenda 440 Lindblom, C.E. 180, 207 liquified natural gas (LNG) 101, 157, 164–5, 173, 280, 285, 332 in British Columbia 3–8, 10–11, 16–18, 21, 26–31, 33, 36–9 in China 93, 95, 97, 99–100, 135, 138, 140, 143, 145–50 living standards 50 loans-for-gas 138, 145–50 loans-for-oil 51, 68–9, 76, 145–50 local content policies (LCP) 213, 219–20, 223–5, 227–9 low-carbon energy 81–91, 95, 101, 309, 405–30, 435–6, 438, 448, 456–7, 460, 463, 466, 469–72 see also geopolitics of climate action; renewable energy Luke, Mark 363 Luxembourg 317 Main, M.A. 112 Makarkin, Alexei 76 Makower, Joel 318 Malaysia 145–6, 272, 280, 325, 344, 452 manufacturing 84, 200–202, 214–16, 218–19, 221–5, 227–9, 236, 256, 264–5, 328, 365, 426, 428, 456 Mao Zedong 183–4 Marakech Accords 441 March, J.G. 107 Marcus, A. 291 Market Stability Reserve (MSR) 465 Markowitz, H. 105, 111, 113 Martenson, Chris 265

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Maslov, Alexei 75–6 Medvedev, Dmitry 67, 79 Métis 21–3 Mexico 125, 128–30, 157, 258, 272, 278, 317, 332, 452, 470 micro firms 220–22, 228 microgrids 351, 354, 358, 389 Middle East 61, 65, 71, 164–5, 168, 172, 245, 258–65, 267, 273, 278, 280, 284–6 see also individual countries and pricing nexus 324–47 Middle Income Trap 81 Mikhelson, Leonid 149 Miller, Alexey 169 Milov, Vladimir 64, 76 Mitchell, C. 418 Mitrova, Tatiana 133 Mobil 116, 258 see also ExxonMobil money 52–5, 66–71, 263–6 Mongolia 169 Moniz, Ernest 276 Montreal Action Plan 442 moral hazard see resource curse Morocco 283, 317, 467 Morse, Ed 334 multinational companies 213, 218–19, 223–4, 226–9, 298 Myanmar 144, 169 Naryshkin, Sergei 56 NASDAQ 119 Nash, Jack 316 National Association of Regulatory Utility Commissioner (NARUC) 368–9 National Development and Reform Commission (NDRC) 87, 90, 92–3, 96, 200, 202, 206, 346, 445 National Energy Administration 99, 197, 203 National Energy Board (NEB) 3–9, 11, 18–20, 24, 26, 28, 30, 35 national oil companies (NOCs) 51, 55, 62, 68, 71, 76, 104, 109, 114, 119, 135, 140, 184, 324, 332, 334–5, 342 see also individual companies project financing 109–10 utility difference between IOCs and NOCs 111–14

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Index  ­491 National Welfare Fund (NWF) 149 nationalization 115–17, 258, 278 Nationally Determined Contributions (NDCs) 440, 443–4, 447, 455–6, 459, 467–8 natural gas 49, 104, 120, 139, 160–61, 164, 168–71, 173, 175, 219, 241, 250, 279–82, 285–6, 449, 458, 473 see also shale gas in British Columbia 3–40 in China 86–98, 133–50, 197 gas price mechanism 95–9, 101 safe supply of 100–101 natural gas liquids (NGLs) 4–8, 38 natural resource-led development 213–29, 457 Nemet, G.F. 365 Nesterov, Valeriy 61 Net Present Value (NPV) 291, 294 Netherlands 274, 279, 281, 317 New Deal 265 New York Independent System Operator (NYISO) 370 Newberry, David 472 Newendorp, P.D. 106 Nigeria 145, 272, 285, 453, 458 Nisga’a Final Agreement 24 Nixon, Richard 264, 278, 284 Non-Conventional Energy Resources (NCER) 356, 358 see also renewable energy Non-Fossil Fuel Obligation (NFFO) 418, 421, 423–4, 426–8, 430 non-governmental organizations (NGOs) 181, 206, 289, 309, 312, 315, 413, 454 Non-State Actor Zone for Climate Action (NACZA platform) 440 Non-State Actor Zone for Climate Action (NAZCA platform) 449 Nordic-American Oil Company 269–70 North, D.C. 103 North Korea 168–72 Norway 145, 251–2, 269–70, 272, 280, 317, 458 Novak, Alexander 60 Novatek 138

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nuclear power 74, 83, 88, 139, 144, 156, 160, 167–8, 170–71, 173–5, 183, 185–6, 191–2, 198–9, 203, 205, 207, 241, 257, 279–82, 286, 309, 311, 405, 407–9, 411, 413, 417–20, 422–3, 426–30, 446 see also Fukushima disaster Nuclear Safety and Security Commission 174 nuclear weapons 236, 262, 284, 450 NYMEX 294, 346 Obama, Barack 355, 376, 416, 440, 448, 450, 454–5 OFGEM 419 Oil Age 248–70 Oil India 72–3 oil price shocks 115–17, 119, 123–30, 261–2, 278–9 oil supply and institutions 103–21 Oklahoma Gas & Electric 373 Oman 61, 145, 164–5, 237, 245, 272, 333–4, 338–9, 345, 347–9 Oman Futures contact 343, 349 ONGC Videsh 52, 62, 71–3, 77–8 OPEC 114–16, 119, 124–5, 127, 164, 252, 261, 279, 330, 332, 337–8, 340, 347 OpenInvest 319–20 Opower 386 Opulent Strategy 114–17, 119–21 Organisation for Economic Cooperation and Development (OECD) 49, 157, 298, 317, 328, 330, 346, 355, 408, 438–9 Organization of Petroleum Exporting Countries see OPEC O’Sullivan, Stephen 139 Otto, Nikolaus 255 Ottoman Empire 260–61, 277 Page, J. 214 Pakistan 148, 274, 452 Palmer, J. 384 Papua New Guinea 145, 269, 274 Paris Agreement 87, 309, 318, 363, 366, 376, 405, 408, 412, 417, 430, 435, 437, 440, 443–4, 448, 455–7, 466–73 Park Geun-hye 153, 172

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492   Handbook of energy politics peak demand 353, 371–3, 380 peak oil 257, 331, 346 People’s Bank of China 316 People’s Republic of China see China Persia see Iran Peru 274, 453 Petrobras 129 PetroChina 66, 99 Petroleos de Venezuela (PDVSA) 117, 119, 129 petroleum 49–52, 54, 60, 65–6, 71–2, 74–7, 109, 115, 130, 134, 189, 219, 238, 248, 254, 267, 277–9, 285–6, 288, 290, 292, 328, 332 see also hydrocarbons phasor measurement unit (PMI) 369–70, 380 Philippines 74, 150, 317, 452 photovoltaic (PV) 162–3, 193, 202–4, 276, 355–7, 363, 365–6, 368, 372, 377–80, 387, 409, 415–16, 424, 426, 438–9 Pippenger, M.K. 119 Platts 332–5, 337, 339–40, 344, 346, 348 Pleven, L. 337 Poland 60, 281, 283, 285, 317, 451, 458, 464, 467 policy risk 405–30 pollution 81–2, 84, 87–8, 101, 140, 156, 183, 186–7, 191, 193–8, 204–6, 208, 310–11, 320, 420, 423, 444–6, 448 Pope, Carl 314 Popp, D. 365 population growth 224, 228, 266, 268, 444 Portugal 267–8, 460, 463 POSCO 164 post-oil era 235–46 poverty alleviation 179, 185–6, 188, 203, 222, 288, 444, 459 Power of Siberia (POS) 1 133, 135–8, 145, 149–50 Power of Siberia (POS) 2 137, 144–5, 149–50 power plants 88, 90, 96–7, 148, 168, 170, 174–5, 183, 185, 187, 191–3, 197–9, 202, 205, 207–8, 257, 279–81, 351, 355, 367, 374–6, 418, 427, 445

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power purchase agreements (PPAs) 319, 379 pressurized heavy water reactor (PHWR) 185 pressurized water reactor (PWR) 184–5 Price Defense Strategy 124, 127 price reporting agencies (PRAs) 324, 332, 339–43, 346 Price Stabilization Mechanism (PSM) 425 Primakov, Yevgeny 49 principal–agent problem 105, 107–8, 182, 297–302 privacy 353, 356, 358, 382, 388–90 profit sharing agreements (PSA) 110, 114, 116, 118–19 Promleasing 62 property rights 103–4 purchasing power 312 Purdom, Sophie 314 Putin, Vladimir 50, 54–6, 62–4, 66–9, 71, 74, 134–5, 169, 243 Qatar 116, 145–6, 164–5, 237, 245, 272, 280, 345, 347 quantitative easing (QE) 312–13 Ramesh, M. 181 Ramsey, J.B. 106 rank-order tournaments 298–302 Rapson, David 384 Reagan, Ronald 450 Real Instituto Elcano 450 Real Time Prices (RTP) 361, 381 REN21 310, 313 renewable energy 87, 90, 139, 144, 156, 160–63, 167, 173, 179, 192–3, 195, 200–203, 207, 235, 242–3, 276, 279–82, 286, 309–11, 314, 317–18, 352, 354–7, 361, 364–8, 374–6, 379, 405–30, 438, 454–5, 458–60, 466, 469, 471, 473 see also hydropower; low-carbon energy; solar power; wind power Renewable Portfolio Standards (RPS) 162, 365–6, 375 Renewables Obligation (RO) 411, 416, 418, 421, 423–8 Republic of Korea see South Korea resource curse 288–303

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Index  ­493 retail net metering (RNM) 379 Reynolds, D.B. 108, 119–20 RIC energy relations 49–77 risk 104–7, 110, 112–14, 117, 119–20 Risky Shift Hypothesis 107–8 RMB Global Markets 218 Robins, Nick 316 Rogers, Todd 386 Romania 258, 274 Rooftop Subsidy Programme 203 Roosevelt, Franklin D. 278 Rosneft 50–74, 76–7, 134–5, 137, 169, 344–5 Royal Dutch Shell 116, 237, 340 see also Shell Rubin, Jeff 265 Rudd, Amber 413 Rushkoff, Douglas 312 Russell, David 416 Russia 98, 116, 127, 144–5, 154, 165, 168–72, 192, 238, 241, 243, 257–8, 260–61, 263, 272, 277, 279–83, 285, 330, 343–4, 346, 348, 426, 450–53, 458, 466–7, 470 see also East Siberia RIC energy relations 49–77 Sino-Russian gas cooperation 133–50, 168–9, 171 Russian upstream 54, 61–5, 72, 149 Rutledge, I. 417 Saddam Hussein 262, 279 Sakhalin projects 52–3, 61, 71, 73 sanctions 51–2, 60, 62, 64, 70, 72, 74–6, 127, 150, 182, 238, 262, 331, 341, 418 Sanmenxia Dam 183 Saudi Arabia 60–61, 116, 124–5, 127, 148, 236–9, 242, 245, 252–3, 260–63, 272, 278, 284, 331–4, 336–9, 342–4, 348, 470 Saudi Aramco 60, 238–9, 334, 337, 344 Savage, L. 112 Sberbank 149 Schneider Electric 314 Schultz, P. Wesley 385–6 Schuyler, J.R. 106 Scotland 267, 414, 420–22, 426–8 see also United Kingdom

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Sechin, Igor 54, 56, 59–60, 66–8, 70, 136, 169 Sen, Amrita 61 Senegal 453 shale gas 3, 91–3, 95, 97, 129–30, 158, 161, 164–5, 168, 171, 250, 276, 280, 282–3, 285–6, 314, 346, 417, 428–9, 448 shale oil 120, 128–30, 237, 250, 276, 282–3, 286, 314, 330, 346, 448 Shandong Kerui Petroleum Equipment 134 Shanghai Futures Exchange (SHFE) 345 Shapira, Z. 107 Sharon, Ariel 284 Shell 66, 105–6, 237, 258–9, 270 see also Royal Dutch Shell Shleifer, A. 103 Shuvalov, Igor 63 Silicon Valley 311 Silk Road Fund 149 Singapore 170, 344 Sinopec 61–2, 64–6, 69, 73, 99, 134–5, 147, 184 Sino-Russian gas cooperation 133–50, 168–9, 171 Sintov, Nicole D. 385 Skyland Petroleum 136 Slavneft 79 Slovakia 281 small and medium-sized firms 213, 222–9 small modular reactors (SMRs) 282 smart grid 156, 351–4 additional challenges 388–90 benefits 358 costs, allocations and investments 362–6 how smart grid is changing the electricity delivery system 369–73 markets and policy 373 understanding 354–5 unlocking technological potential of 378–87 utilities of the future 366–9 Smart Grid Investment Grant (SGIG) 363, 370–71, 373

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494   Handbook of energy politics smart meters 268, 353, 358, 368, 372–4, 381, 383, 385 Social Investment Forum 310, 315 socially responsible investing (SRI) 314 soil erosion 83, 255, 267 solar power 90, 163, 186, 192–3, 200, 202–5, 243, 268, 279–81, 309–10, 317, 319–20, 352, 354–7, 363, 365–6, 368, 374, 377–80, 387, 409, 415–16, 424, 426, 438–9, 446 see also photovoltaic (PV) SolarCoin 320 Soligo, R. 336–7 Sonen Capital 319 sour crude 335, 343–6 South Africa 316, 440, 453, 470 South China Sea boundary dispute 138, 145, 150, 236 South Korea 51, 76, 139, 325, 330, 336, 339, 344, 452 energy security conundrum 153–76 Southern China Power Grid Company 190 Soviet Union 71, 172, 183, 236, 258, 330 see also Russia Spain 267, 406, 415–17, 424, 429, 451, 458, 460–61 Spash, C. 473 Species at Risk Act (SARA) 19, 21, 32 staged development 288–303 Standard Oil 116, 258, 277 State Bank of China 69 State Grid Corporation 190 State Power Corporation of China (SPCC) 189–90 Statistics Canada 21–2 Statoil 237, 340 Steiner, Rudolf 319 Stern Review 436–7, 472 Stimul 79 Stone Age Man 255 Stoner, J.A.F. 107–8 Sub-Saharan Africa 213–29, 325 Sudan 65, 272 Suh, Y. 107 sulphur dioxide emissions 179, 183, 187, 193–4, 204–7, 446 Suntech 202–3 Supreme Court of Canada (SCC) 23–5 Surgutneftegaz 344

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sustainable development 77, 82, 95, 166, 188, 192–3, 469 Sustainable Development Goals 309, 311, 315–18 Sustainable Investment Forum 315 Sustainable Stock Exchanges 315 Sykes-Picot Agreement 277 Syria 150, 261–3, 274, 284, 450 Taas-Yuryakh Neftegazdobycha 62, 72–3, 136–8 Taiwan 236 Tajikistan 144 Tanzania 453 Task Force on Climate-related Financial Disclosure (TCFD) 310 telecommunication 257, 352 terrorism 166, 440, 450–54, 459–63 Tesla 243–4 Tett, G. 341 Texas 103–4, 109, 115, 258–9, 270, 277 Texas Railroad Commission (TRC) 109, 259 Thailand 274 Thatcher, Margaret 258 thermal power 89, 163, 183, 185–7, 191–3, 197–9, 202–5, 207–8, 268, 309, 311, 363, 407, 439 Three Gorges Dam 191 tight oil and gas see shale gas; shale oil Time-of-Use pricing 381 Tirole, J. 375 TNK-BP 50, 62, 68, 70, 169 Tokarev, Nikolai 56, 69–70 Total 149, 237 Township Electrification Programme 193 Toyota 244, 319 Transition Town Movement 267 transmission and distribution (T&D) system 353, 360, 370, 373 Transneft 53, 55–7, 67–70 transparency 13, 54, 94, 99, 170, 286, 342, 350, 353, 358, 362, 364–5, 374, 389, 414, 420, 429–30, 443, 449, 468–70 Treaty 8 24, 28, 36–7 treaty rights 22–5, 28, 39 Trigeorgis, L. 291 Trinidad and Tobago 145, 269, 274

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Index  ­495 Trump, Donald 317–18, 363, 376, 406, 416, 448–50, 454–7, 468–70 Tunisia 274, 283 Turkey 260–61, 269, 274, 281, 451, 470 Turkmenistan 68, 144, 169, 274 Tversky, A. 112–13 Tyumenneftegaz 64 Udmurtneft 62 Uganda 274, 453 Ukraine 238, 274, 280, 283, 285, 389, 451 unemployment 126, 267 United Arab Emirates 116, 165, 237, 245, 263, 272, 334 United Kingdom 103, 116, 148, 157, 195, 251–2, 257–8, 261, 264, 267, 270, 272, 277–8, 283, 331, 406–9, 411, 413–30, 451, 458–60, 462, 464, 470 see also Brexit United Nations 188, 318 see also COP 15, COP 16, etc. Environment Programme (UNEP) 315–18, 320, 416 Framework Convention on Climate Change (UNFCCC) 435, 440, 442, 449, 466 Global Compact 315, 320 Principles of Responsible Investing 315, 320 Sustainable Development Goals 309, 311, 315–18 United Nations Economic Commission for Africa (UNECA) 216 United States 50–51, 55, 60, 64, 71, 82–3, 91, 98, 103, 108–9, 116, 119–20, 126–7, 148, 154, 157, 164–5, 170–71, 175, 192, 195, 203, 235–8, 244, 253, 258–9, 261–5, 267, 269–70, 277–80, 282–6, 310–11, 313, 315, 317, 329–31, 335–7, 339, 341, 343–4, 346–7, 355, 359–60, 366, 368–70, 372–3, 375, 379, 382, 385, 406–7, 415–17, 429, 441, 444, 448, 451, 458–60, 466, 468–70, 472 see also Alaska; Texas climate action 448–51, 454–7 universal basic income (UBI) 312–13

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uranium 257, 277, 281–2, 411 urbanization 88–9, 214, 223–4, 238 US 150 Uzbekistan 144, 274 Vainstock, Semyon 55 valued components (VCs) 11–16, 21, 26, 32, 36, 38–9 Vankorneft 63–4, 71–3 Venezuela 65, 68, 116–9, 120, 125, 128–9, 253, 258, 261, 272, 285, 453 Verkhnechonskneftegaz 64, 134 Vienna Convention on the Law of Treaties 468 Vietnam 74, 274, 452 Vis, P. 458 voltage reduction (VR) 371 Vostock Energy 62 VSNK 64 Wallach, M.A. 107 Wallin, Tom 337 Wan Ilin 65 Wan Tsishan 66 warfare 235–6, 257, 262–3, 277, 324, 331 Warsaw International Mechanism for Loss and Damage 440, 442 Warshaw, C. 109 Wen Jiabao 66 West Texas Intermediate (WTI) 115, 118, 304, 339, 344, 346–7 West-to-East Gas Pipeline (WEP) 140 wildcatting 105–6 Williamson, O.E. 103 Willrich, M. 165, 167 Wilson, Woodrow 264 wind power 90, 162–3, 185–6, 192–3, 200–203, 205, 268, 276, 279–81, 309–10, 317–18, 352, 354–6, 365, 407, 415–16, 422, 424, 426–7, 438–9, 446 Wolfram, Catherine D. 381 Woodman, B. 418 World Bank 188, 190–91, 193, 220, 288–9, 303, 325 World Business Council on Sustainable Development 315 World Energy Council (WEC) 405–6, 411

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496   Handbook of energy politics World Investment Forum 315 World Trade Organization (WTO) 188, 194, 203, 467 World War I 257, 261, 265, 277 World War II 236, 257, 264–5, 267, 278, 284

Yemen 145, 164–5, 274 Yergin, Daniel 324 Yermakov, Vitaly 72 YPF 130 Yuganksneftegaz 54–5, 61, 79 YUKOS 50, 53–4, 67–8, 70

Xi Jinping 66, 68–9, 134, 195, 318

Zadek, Simon 316 Zhongtian 145 Zhou Enlai 183–4 Zhu Rongji 188–9, 192 Zubov, Valeriy 76

Yakunin, Valdimir 56 Yanchang Petroleum 140

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