The Geopolitics of Global Energy: The New Cost of Plenty 9781626376496

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The Geopolitics of Global Energy

Advances in International Political Economy Series Editors

Alan W. Cafruny and Herman M. Schwartz

International Advisory Board

Mark Beeson University of Western Australia

Heiki Patomaki University of Helsinki

Claire Cutler University of Victoria

David Rapkin University of Nebraska

Jacqui Best University of Ottawa

Bob Denemark University of Delaware Robert Jessop Lancaster University Chris May Lancaster University Jim Mittelman American University

Johnna Montgomerie University of Manchester

Henk Overbeek Free University of Amsterdam

Nicola Phillips University of Sheffield

Magnus Ryner Kings College, University of London Leonard Seabrooke Copenhagen Business School

Leila Simona Talani Kings College, University of London Diana Tussie Facultad Latinoamericana de Ciencias Sociales, Buenos Aires Linda Weiss University of Sydney

The Geopolitics of Global Energy The New Cost of Plenty

edited by

Timothy C. Lehmann

b o u l d e r l o n d o n

Published in the United States of America in 2017 by Lynne Rienner Publishers, Inc. 1800 30th Street, Boulder, Colorado 80301 www.rienner.com

and in the United Kingdom by Lynne Rienner Publishers, Inc. 3 Henrietta Street, Covent Garden, London WC2E 8LU

© 2017 by Lynne Rienner Publishers, Inc. All rights reserved

Library of Congress Cataloging-in-Publication Data Names: Lehmann, Timothy C., editor. Title: The geopolitics of global energy : the new cost of plenty / [edited by] Timothy C. Lehmann. Description: Boulder, Colorado : Lynne Rienner Publishers, [2017] | Includes bibliographical references and index. Identifiers: LCCN 2016051699 | ISBN 9781626374331 (hardcover : alk. paper) Subjects: LCSH: Energy development—Political aspects. | Energy Security—Political aspects. | Energy industries—Political aspects. | Geopolitics. Classification: LCC HD9502.A2 G4654 2017 | DDC 333.79—dc23 LC record available at https://lccn.loc.gov/2016051699

British Cataloguing in Publication Data A Cataloguing in Publication record for this book is available from the British Library.

Printed and bound in the United States of America

The paper used in this publication meets the requirements of the American National Standard for Permanence of Paper for Printed Library Materials Z39.48-1992.

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Contents List of Tables and Figures

1 The Geopolitics of Global Energy Timothy C. Lehmann

vii 1

2 The Changing Geopolitics of Oil and Gas Michael T. Klare

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4 Oil Elites and Transnational Alliances Naná de Graaff

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3 Oil’s New Reality Philippe Le Billon and Gavin Bridge

5 The Scramble for Arctic Oil and Natural Gas Dag Harald Claes

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6 The US Energy Complex: The Price of Independence Timothy C. Lehmann

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8 Germany’s Transition to Renewable Energy Volkmar Lauber

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7 China’s Resource Drive into the South China Sea Andrew S. Erickson and Austin M. Strange

9 Energy Transitions in Japan Andrew DeWit

10 The New Cost of Plenty Timothy C. Lehmann

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205 231 269 271 283

References The Contributors Index About the Book

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Tables and Figures

Tables

1.1 World Total Primary Energy Consumption by Energy Type, 1925–2015 2.1 Proven Oil and Gas Reserves of Selected Countries and Regions in 2015 2.2 Oil Consumption and Imports in Selected Countries and Regions, 2012 and 2040 4.1 Distribution Corporate Interlocks, OECD and Non-OECD Directors 5.1 The Arctic Share of World Conventional Oil and Gas Resources 5.2 Arctic Petroleum Activity by Country 7.1 Percentage Share of Natural Gas in Aggregate Energy Consumption, Selected Countries in 2015 8.1 Gross Electricity Generation by Energy Source, 1990–2015 8.2 2010 Ownership Share in German Renewable Power Generation by Investor Type 8.3 Evolution of German Feed-in Tariffs for Photovoltaics, 2004–2013 9.1 Changes in Japan’s Primary Energy Supply Share, 1948–2014 9.2 Nuclear Fission RD&D Expenditures by IEA Countries, 1975–2014 9.3 Energy RD&D Expenditures by IEA Countries, 1975–2014 10.1 Worldwide Renewable Energy and Upstream Oil and Natural Gas Annual Investment Estimates, 2004–2015 Figures

3.1 Primary Energy and Oil Consumption, 1965–2014 4.1 Proven Oil and Gas Reserves, 1980 and 2014

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24

26

75

88 94

137 162

166

168 186

188 199

213

48 69

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Tables and Figures

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Partnership Types of Five Top Non-OECD NOCs, 1997–2007 Main Arctic Oil and Gas Reserve Basins Alaskan Oil Production, 1973–2015 US Oil Trends, 1918–2014 The Oil Triangle Middle East Crude Oil Exports by Destination, 1955–2014 Gross Electricity Generation in Germany by Sources, 1990–2014 Renewable Power Generation by Energy Source, 1990–2014 Quarterly Average Baseload Power at EPEX Spot, per Quarter, 2000–2015

5.1 5.2 6.1 6.2 6.3 8.1

8.2 8.3

73 90 96 108 112 113

160 160

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1 The Geopolitics of Global Energy Timothy C. Lehmann

This volume explores the contemporary economics and power politics of global energy. Among the many topics related to this central aspect of economic and military power, resource scarcity, depletion, and rivalry have been long-standing concerns for scholars of energy, political economy, and strategic studies. For example, Thomas Malthus worried that population growth would outstrip agricultural production, causing calamitous human behaviors, and William Jevons found that increased coal consumption and resource depletion resulted from Great Britain’s improved efficiency in coal use. Greater efficiency in production and applied end uses did not reduce total consumption in the case of coal—quite the contrary— yet it did stave off Malthus’s most dire predictions in agriculture. The questions that drove these concerns frame much of this volume’s apolitical inquiry: exactly what are the conventional and unconventional energy resources available for stable economic development? Key Questions Animating the Volume

To evaluate this seemingly innocuous question of mere scientific measurement, the authors in this volume are of necessity addressing themselves in whole or in part to four interlocking questions. • What are the world’s known energy reserves, and how do domestic and international politics affect these assessments?

• How do contests over energy resources and the wealth they generate shape political relations and economic structures within and among states?

• What have been the social, environmental, and political consequences of the conventional energy system? 1

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• Is there an energy transition afoot in the world, and if so, what are its key characteristics and likely consequences?

Attempting to answer these questions with any degree of accuracy invokes the many state and corporate actors whose strategic assessments and investments determine the world’s collective energy fate. The more directly political aspects of this volume center precisely upon the agendas and decisions of the world’s leading commercial and military-related actors. Regardless of whether one investigates commercial market power or sovereign military power, energy is the necessary and irreplaceable common element. Energy is fundamental to every aspect of social, economic, and military life, and its use characteristics separate humans at both the individual level and in the many stratifications and contests within the international arena. What is also true about energy’s ubiquitous role in social and hierarchical relationships is that nearly any energy resource can be developed. Given sufficient capital investment, end use infrastructure development, and governmental commitment, most energy resources are convertible into usable products. Because this domain is so important, it has always been the special provenance of the most important commercial and state actors, and they are all highly attentive to the competitive maneuvers of their peers. Yet their choices and the resulting energy outcomes are variable, even within their own times. For example, in the 1920s and 1930s, despite the cartelized and highly functional global oil market and the obvious operational performance and strategic benefits attending the use of refined fuels from crude petroleum resource inputs, Germany converted its readily available coal resources into refined fuels such as gasoline. Using very capital-intensive and chemically sophisticated processes, Germany did this for strategic, autonomyenhancing reasons, and these stimuli accelerated from 1933 forward under Adolf Hitler’s chancellorship (Hayes 1987; Birkenfeld 1964). During the same period, the major Western international oil companies included IG Farben (the leading German actor in the synthetic oil from coal effort) and a few other key actors in a global petrochemical cartel. In this volume, the oil majors refer primarily to: Standard Oil of New Jersey (Exxon), Standard Oil of New York (Mobil), Standard Oil of California (Chevron), The Texas Company (Texaco), Royal Dutch Shell, and British Petroleum (BP) (hereafter the oil majors). The broader cartel among energy and chemicals concerns effectively locked down the patented technology to develop liquid fuels from coal outside of Germany, setting up the world’s first transnational petrochemical cartel with clear vested interests. Beyond forming an industrial and political truce among key US, Dutch, and British actors, the cartel’s most direct objects were to control the world’s non-Soviet oil resource territories and the myriad refined products markets. These now

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encompassed all manner of petrochemical by-products, such as Rayon, the first patented commercial product of the cartel (Blair 1976; Sampson 1975; US Federal Trade Commission 1952). The oil majors, the leading chemicals concerns, and their Anglo-American-Dutch home governments shaped much of the development of the oil age as it grew from its inception in the early pre–World War I era, to its full flowering in the years leading into World War II. The Oil Age

The oil age was led by the United States and its oil majors. Despite oil production not outpacing coal as the top energy resource across all energy types until 1965, oil was the dominant energy type after World War I (see (see Table 1.1; Darmstadter 1971: 224, 652). It remains so today. Aside from Sasol in South Africa, coal as a liquid fuels source is not something the world dwells on much anymore. This remains true despite the fact that nonliquid unconventional energy resources such as oil sands and natural gas plant liquids are becoming increasingly important to the “oil” game. Since January 2010, oil sands and even coal have received US regulatory support to qualify as proven oil reserves on the books of energy companies (US Securities and Exchange Commission 2009: 2163). With regulatory innovation such as this, one can look backward into the present and see how striking it remains that on the basis of a suboptimal energy resource for transportation fuel end uses (i.e., coal), Germany was able to go so far in its military and industrial challenge against the three leading oil powers—the United States, Britain, and the Soviet Union. Germany built impressive military capabilities and led in rocket fuels development because of this devel-

Table 1.1 World Total Primary Energy Consumption by Energy Type, 1925–2015 Energy Type and Share of World Energy Supply Coal Oil Natural gas Other

1925 82.9 13.3 3.2 0.6

1945 66 23 10 1

1955 54.1 32.5 11.6 2.8

1965 41.8 39.4 16.7 2.1

1975

29 46.3 18 6.7

1985 30 37 20 13

1995 27.1 39.7 23.2 10

2005 27.8 36.3 23.6 12.3

2015

29.4 33 23.8 13.8

Sources: British Petroleum, Statistical Review of World Energy (various years); Clark (1991); Darmstadter (1971). Notes: “Other” includes hydroelectric, nuclear, and all renewable energy sources. Renewables were omitted in British Petroleum data until 1995 (renewables were only 2.78 percent of the total in 2015, up from 1.4 percent in 2010, but nuclear and hydroelectric together were still over four times greater than renewables in 2015).

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opment track, and this fact is testament to just how malleable hydrocarbon formations are as energy resources (Stokes 1985). Given sufficient capital, technology, and political will, nearly any hydrocarbon can be converted into usable fuels for vital end uses, including the two most important: electrical generation and transportation. While the interwar German example demonstrates that energy resources can be adapted to most end uses, the fact that the three leading oil powers defeated the “have-not” powers of Japan and Germany illustrates a deeper truth about energy geopolitics (Chapman 1984). Those that have the most energy resources under their sovereign authority are usually capable of developing them more fully and securing their lines of communication with military force. Thus, they are more likely to win the systemic wars that affect global energy and related alliance patterns for decades to come. Political order itself is determined by and visible in these energy and alliance patterns, revealing global politics, in effect, as a mutually constitutive system conditioned primarily by energy and war. Thus, the geopolitics of energy are inseparable from state grand strategy and war, and it becomes clearer that any change in an existing political order would have to have a corollary change in the energy system. In the oil era this is obvious. Oil is the indispensable fuel for conquering distance through power projection and mobility, while oil remains essential to military firepower as well, providing the toluene in TNT, for example, among other vital explosive components. The struggle for autonomy and influence always attends the geopolitics of energy, and war and the threat of war are ever-present aspects of ordering relations among key political actors, whether these are states or firms. After World War II, the United States helped pull the world forward into the modern oil-based industrial era, raising oil’s share in total world energy use from 23 percent in 1945 to 46.3 percent by 1975. In 1945, on US territory alone, US firms produced 66 percent of the world’s crude oil while helping make oil 30.5 percent of total US energy use. The United States used its dominant position over world energy and trade to convert postwar allies to oil-fired economies (Hein 1990; Stokes 1994). The Soviet Union simply followed suit on the basis of its own unconquered oil resources in the Caucasus and elsewhere. The early decades after World War II were an era of cheap and abundant oil and other energy resources for global economic development and war, whether in Korea, Vietnam, or the more indirect proxy wars from the Horn of Africa to Central America. After depleting much of its easily accessible reserves in winning the war and securing a postwar sphere of influence, the United States adjusted its policies, which had been based on North American energy supremacy, to ones based on dominance over oil supplies from the Middle East (Painter 2012; Citino 2010). The Soviet Union, the second

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most powerful oil actor in the world, built a similar system with its allies and satrapies based in the oils under their control from the Eastern bloc (Painter 2014). The world became a more interconnected and petroleumbased place as world trade and travel grew exponentially through the first oil shocks of the 1970s. Then, as now, US dominance of the Middle East remains essential to US hegemony. Contrary to leading academics’ many decades old admonitions for the United States to leave the Middle East because it is not strategically vital, the United States remains diplomatically and militarily anchored in the Middle East (Mearsheimer and Walt 2016: 82–83; Glaser and Kelanic 2016: 233–235; Posen 2013: 112; Layne 2006: 188–189). US policymakers, such as Zbigniew Brzezinski, have not blanched at this reality, which will continue until the world’s energy system changes (Mann 2013: 162–168; Brzezinski 2003/2004). Different Era, Same Actors, Same Game

Today the world’s leading business concerns are the oil firms, and their long-term investments and patterns of cartelized cooperation still determine much of the world’s energy development and end use patterns. Whether one considers various fleeting moments in resource development since the 1970s oil shocks, including the late 1970s move back to synthetic oil from coal or the modern euphoria over a “golden age of gas,” the major petrochemical firms and their home governments are the ones that created these energy infrastructures (IEA [International Energy Agency] 2012b). This is unsurprising when reflecting on the fact that Standard Oil of New Jersey was once a major coal firm, too, and the key labor strife in Colorado in 1913–1914 concentrated on Standard’s coal and steel combine, the Colorado Fuel and Iron Company. Coal is not a primary focus of this volume, nor is it for the majors at present, except as an object for their plans to displace coal with natural gas in electrical generation. But, coal’s fate moving from transport fuel of choice after the era of wind and sail to its current role of nearly exclusive use in electrical generation is instructive nonetheless (King 1953). In fact, the geopolitics of energy as a field of study really begins with the analysis of the role of coal in relative national power and imperial rivalry. As Peter Shulman has ably demonstrated, coal was once king for a reason. Rising US power in what is commonly thought of as Britain’s dominance of the coal era complicated relations between the two English-speaking titans, just as the world was to transition to oil (Shulman 2015). The share of coal in global energy consumption has not fallen in forty years, and in the past twenty years it has edged up to 29.4 percent because of coal-based electrical generation in key countries.

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The current emphasis on natural gas is directed in the main by the planning and operations of three oil majors—ExxonMobil, Royal Dutch Shell, and ChevronTexaco. ExxonMobil is the largest natural gas producer in the largest gas-producing country, the United States, while it also wields influence over the liquefied natural gas (LNG) exports it developed in Qatar, the largest LNG exporter in the world with roughly one-third of the world’s total LNG trade (Kamrava 2013: 44; Allsopp and Stern 2012: 24–25). If one adds Chevron’s operations in Australia and elsewhere to the direct partnership between ExxonMobil and Royal Dutch Shell in the oil and natural gas of the British North Sea, the Groningen field in the Netherlands and myriad other locations (including in Iraq), the global trend toward natural gas becomes less conspicuously about competitive markets evolving toward cleaner alternatives to oil than another planned energy market expansion by the oil majors. The same holds for what Harold Hamm of Continental Resources calls a “renaissance” in hydrofracked shale rock formations (Carroll and Olson 2014). After Continental, ExxonMobil is the number two acreage leaseholder in the Bakken formation in North Dakota, which is still producing close to 1 million barrels of oil a day (mbd), while ExxonMobil and the other oil majors also produce a great deal of the heavy oil product coming out of the Albertan oil sands development (Oilsands Review 2014; Philips 2014). The relative power that ExxonMobil and Houston firms more broadly hold over global energy is as difficult to overstate as it is to fully assess. One recent indicator of the relative advantage held by these firms is the readmission of ExxonMobil and the other majors back into Mexican oil, which was nationalized in March 1938 and operated since then by one of the leading national oil companies (NOCs) (Williams and Carroll 2014). As of this writing, ExxonMobil and other Houston energy services firms are desired partners for the Mexican government and state-owned oil company Pemex. They alone can bundle exploration and production expertise with refining and distribution systems, helping Mexico enhance its oil recovery from declining fields and tap the ultra-deep offshore reserves in the Gulf of Mexico and its own shale formations. Simply put, these Houston-based oil majors hold the cards in the energy world. They have learned how to play their hand to perfection, waiting out recalcitrant NOCs and states, while dangling their technological edge in energy resource development to improve individual fields, whole reservoirs, and other performance characteristics, affecting economic growth and well-being. These petrochemical majors are indeed “energy” firms, as they are wont to state in public, particularly when contrasting themselves with coal, but they are less than forthcoming about the extent and purpose of their strategies. They are even more taciturn when it comes to clarifying their estima-

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tions of possible, probable, and proved energy resources and reserves. These financial and legal concepts have seen some Sartorian stretching over time and outright fraud in the case of Royal Dutch Shell in 2003 (Critchlow 2004; Gerth and Labaton 2004). While Royal Dutch Shell’s 23 percent overstatement of proven oil reserves under corporate management was motivated by financial politics on its own behalf as well as Organization of the Petroleum Exporting Countries (OPEC) member states (including Oman and Nigeria), Libya’s understatement at the same time was also seemingly political but of a decidedly state strategic variety. Libya’s “proved” oil reserves jumped up 22 percent in late 2003, taking it from having Africa’s third-largest oil reserves to the single largest cache of proved African oil reserves (Oil and Gas Journal 2003: 46–47). Was it newly discovered geological properties or technological advances that led to this large upward revision at precisely the same time Colonel Qaddafi reached out yet again to the Anglo-American powers (Pargeter 2012: 189; St John 2004)? Did British prime minister Tony Blair visit Qaddafi in March 2004 with Royal Dutch Shell in tow to bury the hatchet out of altruism, or was it to help Royal Dutch Shell consummate deals that would assist with its reserves accounting dilemmas, or was it rather, as ever, a mixture of both? The Extent of Conventional and Unconventional Energy Resources

Reserves estimates are as fickle as the value of foreign exchange, and they are assuredly political. It is a function of politics as much as it is technology and investment when a possible, recoverable hydrocarbon resource becomes accepted as a proved reserve, despite the desire of many in industry and government to focus only on the latter factors. There really are no cardinal values in energy reserves assessments. They remain estimates bounded by the politics and strategies of the actors who map, extract, and govern them. More pointedly, as the Royal Dutch Shell case from 2003 highlighted, there are mixed motives and incentives at play when estimates are generated, field by field, hydrocarbon reservoir by hydrocarbon reservoir. Furthermore, the reliance of seemingly authoritative bodies such as the International Energy Agency on petrochemical-related actors such as IHS for the original data used in analytical reports brings into question the ability of any non–industry related source to generate objective analyses of reserves, production, and depletion rates (Sorrell et al. 2012; Macalister 2009; Financial Times 2009). All of these are further complicated by changes in technology and the degree of investment commitment. For example, enhanced oil recovery technologies can help raise recovery rates in reservoirs above the historical norm of

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30–40 percent and therefore allow for an increase in proved reserves from old reservoirs. Similarly, improved drilling technologies that unlock previously unreachable resource reservoirs, such as shale rock formations, change the proved reserves profiles of firms and states and the production possibility frontiers of whole energy enterprises, whether state-owned or private. This is evidenced by a recent oil reserves ranking from Rystad Energy in Norway, which puts the United States in first place ahead of Russia and Saudi Arabia (Rystad Energy 2016). Adam Sieminski, late of Deutsche Bank and the US Department of Energy’s Energy Information Agency, captured prevailing industry and government sentiment regarding the extent of oil resources and their possible exhaustion. In 2014, he said: “Peak oil supply was based on three critical assumptions. The first one is that you know what the resource base is, and then the second and third are that prices don’t matter and technology doesn’t matter. I was a firm believer that prices do matter, technology does matter, and that the resource base is dependent on prices and technology” (Moore 2014). This is a neat formulation and, of course, not inaccurate. Oil sands and coal have been reclassified and are indeed now “oil” reserves. The technology and investment have been applied in sufficiently large amounts to liquefact the sandy hydrocarbons, and some of the fruits of this endeavor rolled down North American train tracks at nearly 800,000 barrels a day in 2014, vastly more than the mere trickle of seven years ago (Natter 2014; Penty and Catts 2014). Because of the extra developmental expense compared with the “easy oil” of the classical petroleum era, government intervention has usually been the key dimension in altering relative prices and developing unconventional resources as well as their obvious reclassification as proved reserves. This has certainly been the case for the unconventional energy resources in Canada and elsewhere. The rule change allowing proven reserves to cover oil sands, shale rock, and coal was a landmark support for the oil majors who are heavily invested in the Canadian oil sands project. Investments and rule changes such as these support the heady optimism of industry leaders and their chief trumpeters such as Daniel Yergin (Yergin 2015; IHS 2012). For example, in 2014, Chevron’s chairman and chief executive John Watson confidently noted: “we’re going to be in the fossil fuels business for a long time,” while his lieutenant Robert Ryan once remarked that “we should celebrate the fact that we have enough oil and gas to carry us forward until a new energy technology can take their place” (Carroll 2014; Krauss 2010). These modern Standard Oil of California officers are in good company with long-standing partner Saudi Arabia, whose former oil minister, Sheik Ali Al-Naimi, said in December 2014: “Fossil fuel will remain the main source of energy for decades to come” (Carey and Syeed 2014). There

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is no doubt that large increases in unconventional energy resource investments have produced more fossil fuel–based energy, but the opportunity cost of that investment and the externalities of these new resources have yet to be measured fully. Leaving aside for a moment the social, environmental, and political considerations of the unconventional “renaissance,” the basic infrastructure to harness these resources and distribute them to refiners and end users is already under great strain in North America, the leader in this incipient unconventional era. Reliance on rail transport for the Bakken crudes alone has periodically jammed up a great deal of the US rail system, stranding much of the Western states’ coal for electrical power generation elsewhere in the country. The domestic coal constraint due to the spike in Rockefeller-era oil-by-train shipments caused US imports of coal to surge by 37 percent in 2014, as coastal electrical utilities used imported coal over harder to rely on Mountain West coal (Parker 2014). This trade-off is an indelible example of the “new” energy era and hardly a sign of an energy renaissance. The same holds when one looks at natural gas in southern Iraq or North Dakota. The nearly one-third of the associated natural gas of North Dakota’s shale boom and over one-half of southern Iraq’s natural gas that is simply flared off, instead of captured for its energy utility, is nothing but an abominable misuse of energy resources (Sontag 2014; Lando and van Heuvelen 2011). These micro examples of resource squandering and the elemental trade-offs among coal, oil, and natural gas inherent in the interdependent energy system highlight just how difficult it really is to either favor or disconnect from any one existing energy resource let alone integrate an entirely new one. Entrenched energy interests and infrastructure abound across the global energy system, and they do so because of their key positions within leading countries. Differential Dependencies in Energy End Use

The lay public is led to believe that energy resources are fungible across applied end uses, having heard repeatedly, for example, that drilling for natural gas in North America will lead to energy independence and free the United States from dependence on the Middle East. Somewhere lost in the coverage is the fact that natural gas is not a substitute for oil in transportation end uses, at least not yet, nor without massive investments in infrastructure. Raw energy resources are inextricably linked through their refined energy products to whatever applied system uses their combustible power. This link is often tightly coupled, even inseparable, and thus the locus of political contests over autonomy and dependence. For example,

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today no crude oil goes directly into a transportation craft’s fuel tank, but in the past, some crudes were so light and nonsulfuric that they could be used directly in naval ship boilers. Tarakan crude in Dutch-controlled Borneo was such a crude, and its seductive quality proved too enticing to Japanese naval planners in the 1920s and 1930s. They devised war plans around seizure of this and other valuable Dutch East Indies crude oil resources, instead of a more valuable technological partnership with Germany in synthetic fuels from coal or even more extensive oil prospecting on their own in Manchuria, which could have led to the Daqing fields. Oil does not have many substitutes in transportation fuels because the engines that power vehicles and other crafts have been built to use refined crude oil products as both fuel and lubrication. Although it remains basically valid that any energy resource type can be configured to any end use, the practical fact is that coal for liquid transportation fuels, for example, is not making a comeback, despite adherents in some quarters (Bartis, Camm, and Ortiz 2008). This is not atypical of the confidence game that plays out in most countries’ domestic political systems, particularly in the United States. Although few people are pushing “clean coal” and fewer still the possibilities of coal to liquids for transport end uses, the current euphoria over natural gas for liquid fuels and possible transportation end uses captures an outsized share of public attention (Cardwell and Krauss 2013). More broadly, natural gas is extolled as the bridge fuel to the future, but its widespread applicability to transportation is only vaguely described, while natural gas–powered buses in some cities are touted as harbingers of a not so distant future. The truth is natural gas is not a fungible substitute for oil in the critical end use of transportation. From fuels refining for transportation to engine and vehicle configuration and production, the requisite natural gas infrastructure either does not yet exist or is simply too narrow to make a dent in oil’s globally vital role any time soon. As a share of global energy supply across all end uses, natural gas has increased only marginally in the past several decades, from 20 percent in 1985, to 23.8 percent in 2015. In transportation, natural gas still powers at the most only 1 percent of road transportation vehicles, and no more than 1.4 percent of natural gas consumed globally is for the transportation fuel end use (IEA 2013a: 13, 2010: 7). Natural gas plays almost no role in other modes of transportation, such as ships, planes, and trains, and one is left to marvel at the public and elite perception that natural gas might easily substitute for oil in transport (Arnsdorf 2014). Oil majors such as Royal Dutch Shell have recognized the oversupply problem in natural gas and shelved projects such as the planned $20 billion gas-to-liquids plant in Louisiana and some operations in Australia (Reed 2014; Elvidge et al. 2009: 619; World Bank 2004: 14). Simply put,

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natural gas may have an increasing role in displacing coal in electrical generation, but it is many decades away from a vital role in transportation. As the world’s largest industrial economy and energy consumer, China’s energy resource use epitomizes the quandary of energy resource– end use path dependence. China’s electrical grid is powered predominantly by coal, while its car and light truck market has been the world’s largest on an annual basis since 2009. China’s road transportation is fired almost entirely on oil, and its electricity consumption is fueled nearly exclusively by coal. Of the roughly 37 million cars and light trucks sold in China in 2011 and 2012, only 20,000 were all electric or hybrid electric vehicles (Green Car Congress 2013), and in March 2013, China reported only 39,800 electric vehicles on its roads. In 2014, 72 percent of China’s electricity consumption was fed by coal (IEA 2016h). If natural gas is to displace coal for electricity in China, it has a long way to go, and while nonpetroleum-based vehicle sales in this the world’s largest market are growing, they still hover around 1 percent of annual sales. China is not yet consuming gasoline at the prodigious US rate, but its growth is remarkable, from approximately 250,000 barrels a day in 2003, to nearly 2.25 million barrels a day in 2013 (Collins and Erickson 2014; Zaretskaya 2014). Paradoxically, the contemporary hope that rare earth element– based electric vehicles will alter the interlocking reality of oil for transport hinges on China too, as it is the largest producer of these elements mined from inner Mongolian pits. Although it seems that some of the world’s leading transportation manufacturers are moving toward electromobility, the pace is still glacial just when the world’s actual glaciers are melting faster than ever before. Even if transport moved toward electrification, the electrical grid’s ungainly reliance on coal dooms the conversion’s utility for environment and climate change mitigation purposes. In 2014, coal was 41 percent of the global electrical grid’s primary energy supply, slightly above its 38.3 percent share in 1973. The primary shift over this period has been away from oil and toward nuclear, natural gas, and some renewables for electrical generation, none of which have displaced coal’s central role in electrical generation (IEA 2016i: 24). The power and prerogatives of incumbency in global energy are stark, whether one focuses on coal for electricity or oil for transport. The fossil fuel sector has reaped unseemly subsidies—$325 billion in 2015—and they command attentive and responsive government that is simply lacking for newer, renewable energy sources (IEA 2016e: 97). Relative to renewables, the energy incumbents capture the largest share of both governmental largesse and investment capital (Morales 2014a). Renewables face a long uphill climb. At only about 3 percent of total energy supply across all end uses globally, they are not likely to significantly alter the pat-

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terns of energy consumption nor the power of the actors who have delivered these patterns onto humanity (IEA 2014a: 6). Political Autonomy, National Variation, and Resource Geopolitics

While global energy resource development and end use patterns are fossilized, there is variation at the national level. This is where the crucible of politically motivated innovation clashes with the power of the oil majors’ transnational complexes of vested interests. The structure of global energy is largely one of “alliance capitalism,” wherein the transitory moments of price competition and rivalry usually give way to managed outcomes among the largest actors, whether state or private, usually both simultaneously (Dunning 1997; US Federal Trade Commission 1952: 21–36). Alliance capitalism has been the norm at least since Britain’s pre–World War I effort to ensnare German elite factions in Iraqi oil through an ownership stake to Deutsche Bank. Today nearly every important development in global energy involves Houston-based firms. Proponents of the Western oil majors usually excuse the oligopolistic and cartelized nature of energy markets as necessary because of the scale of investment capital required or the sophistication of the technology involved, which combine to make virtue out of the necessity of collaborative market practices, not competitive ones (Yergin 2011b: 87–105). This is a nice theoretical argument, but the reality is that since late 1927, the petrochemical sector has seen mostly cartelized cooperation punctuated only by fits of competitive truculence, such as when OPEC first successfully exercised its power over “access” to exports from its oil-producing territories in the 1970s, or when the Saudis unleashed their effort at global market share retention in late 1985, amid North Sea competition from the oil majors. When the European Union fined the narrow oil products cartel in waxes in 2008, one could still see one of the more outlandish extant vestiges of the petrochemical cartel that has dominated global energy since the 1920s (Carvajal and Castle 2008). The Western oil majors are not in rivalry with OPEC so much as they are in a complex form of partnership based in a decades-old cartelized commercial truce. On occasion these relations may tear over high political matters, but only rarely do they rupture permanently. Mexico’s return to the fold eight decades after nationalization is testament to the fact that the longterm leaders of the energy system generally prevail. Despite a general pattern of stability in energy relations, there is an elemental evolution under way in global energy geopolitics. While the United States shifted away from oil for electricity generation with the oil shocks of the 1970s, initially

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replacing it with natural gas and coal, the Japanese are just beginning this process in earnest. In 2012, Japan relied on very expensive imported oil supplies to power 19.6 percent of its electrical grid, and renewables still had only a de minimis share. By way of comparison, in the United States, coal was 50 percent of electrical generation in 2002 and natural gas only 18 percent. But, by 2015, coal and natural gas each supplied 33 percent of US generation (US Department of Energy 2016a). In the well-known German case, determined government policy made renewables 29 percent of electrical generation in 2015. Nonetheless, Germany maintained its reliance on coal, keeping coal’s share of electrical generation at 42.3 percent in 2015. Germany leads in renewable energy but lags in electromobility, while Japan leads in this area with world-beating electric and hybrid vehicles despite its electrical grid being more fossil fuel–fired than most. These seemingly inconsistent trends are a product of the tense interplay of the national quest for autonomy amid ongoing geopolitical rivalry and dependence. In Germany, the desire to supplant imported Russian natural gas is as much an impetus as the interest in greening and denuclearizing the grid. For its part, Japan’s near obeisance to US oil majors in the postwar era is finally giving way to a vigorous debate about the best path toward Japanese energy autonomy, both for the electrical grid and in electrified transport. Here again, choices about energy use and infrastructure are not merely about one sector of the economy, they underpin all the others, from industrial output to most military spending. For example, China and Russia’s record $400 billion, thirty-year deal in natural gas can be seen as autonomy-enhancing for each. Russia needs Eastern outlets for its energy amid its geopolitical rivalry with the West, while China seeks natural gas supplies over land that limit Western influence over imported LNG (Paik 2015). Sino-Russian energy deals thus serve many geopolitical objects and illustrate the limits of the oil majors and their home governments with respect to the great powers still unbowed before the United States. Russia’s ability to use its “blue gold” to cement the Sino-Russian partnership exemplifies the truism in Vladimir Putin’s 2003 Energy Strategy. It stated: “The role of the country in the global energy markets largely determines its geopolitical influence” (Poussenkova 2010). The objects of state autonomy and geopolitical influence have led many other states to choose shorter-term energy solutions that are worsening the well-known social and environmental consequences of fossil fuel reliance. Whether US efforts at unconventional energy from oil sands or fracked shale rock, or German and Japanese reliance on coal and oil as bridge fuels to a more autonomous and green future, many leading states are now choosing paths that have palpably negative consequences. Coal, oil, and natural gas use and greenhouse gas emissions are the primary drivers of climate

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change, and the sociopolitical corollaries of these resources are clearly negative (Le Billon 2013; Ross 2012). Nonetheless, collectively, the world returns to these resources again and again, as well as to the unconventional ones developed by the same actors. This raises a simple question: can the world afford more of the same from the leading energy actors as they structure state transitions to ever-more costly hydrocarbon resources? Geopolitics and the Resource Debate in International Relations

The geopolitics of energy is a seemingly well-established subject area, stretching back many decades. But with few exceptions, it remains a rather poorly detailed area of inquiry by both the scholarly and policy communities (Dyer and Trombetta 2013; Kalicki and Goldwyn 2013; Moran and Russell 2009). Obfuscation regarding power, interests, and intentions among key political actors remains the norm, while studied evasion of evaluating (let alone assigning purpose to) the actors within politically dominated energy markets remains a leading narrative motif (Keohane 1984: 204). For example, far too many scholars who accept a role for oil in war find the Iraq wars to have had oil as a mere “necessary precondition” to a contest about freeflowing access to world oil markets, as opposed to an obvious object of the war (Lehmann 2017; Black 2015: 227–228; Colgan 2013: 149; Duffield 2011: 162; Gholz and Press 2010). These scholars therefore forgo proper analysis of the “control” of Iraq’s oil and natural gas fields, while the explanation of political actions in the language of the market is pat. Actors such as ExxonMobil chairman Rex Tillerson do this too. Tillerson labeled the 2014 Saudi production-maximization decision against higher-cost, unconventional oils from outside OPEC a mere “price discovery exercise,” even though the obvious political objects in Saudi Arabia’s decision included: piquing the United States for its behavioral transgressions in the Middle East; destroying rival supplies from unconventional US shale resources; and limiting demand for more efficient oil-consuming vehicles around the world. Presumably these all would have served Saudi Arabia’s intent to remain the oil world’s central banker as well as the core US ally in the region. One can always reduce politically motivated power maneuvers to dissembling statements about prices or market conditions invoked by states who cloak their interests and actions against others. For example, in early 1941, the United States, Great Britain, and the Netherlands told the Japanese that market conditions had caused the drying up of their prior oil trade with the Dutch East Indies due to oil company tanker removal to the Atlantic theater (Anderson 1975: 159–167). In fact, these governments recalled the

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tankers for political reasons to undercut Japan’s contractual rights to a great deal of East Indies oil, and they made the oil majors play a dissembling intermediary role in so doing. In effect, they made the reality of a contractual right to “access” oil supplies a paper fiction, while they bought more time to eat into Japan’s oil stockpiles for the coming war. These examples underscore that geopolitical analysis of energy requires assessing the inherent rivalry among states and firms over the wealth and power that flow from controlling the motive energy for economic activity and military power projection (Stopford and Strange 1991; Gilpin 1975: 241–244). An energy geopolitics lens looks first, therefore, at the positional rivalry over natural resource geographies that provide the fuel for motive energy (Gilpin 1981). This approach necessarily accepts that technology, industry, and trade condition this rivalry and can alter the seemingly straitened geographic realities of actors, as illustrated by the German synthetic oil from coal example. The energy resource potential of a particular geography is always vital, but political actors will not necessarily contest each other for it using violent means. The Arctic and South China Sea resource geographies are good instances where one can observe the variability and limits of assuming geopolitics ends in conflict. Many great scholars have disputed this “pseudo-scientific” notion of geopolitics since it first appeared at the turn of the last century (Morgenthau 1963: 158–159; Weigert and Stefansson 1944: xx–xxi). In this volume, geopolitics means only that there exists positional rivalry among powerful state and private actors over the energy determinants of national economic and military power. The most powerful of these actors contest each other for autonomy and influence, and it does not strain credulity to ponder whether ExxonMobil operates its own autonomous policy relative to the most powerful states, even the United States and Russia. International relations theory in this area of inquiry is simple and underdeveloped, and it revolves around two questions. First, how effectively do the powerful transnational oil majors work their will upon national polities? Second, must resource-based geopolitical rivalry end in zero-sum nationalist political conflict, instead of cartelized cooperation bridging political rivalry? For international relations realists, structural Marxists, neo-Malthusians, and many environmental scientists, conventional hydrocarbon energy resources are finite, growing scarcer and provoking international competition and conflict. Energy has always been synonymous with relative power and wealth, and thus there is much less likelihood of resource politics taking on a globally cooperative hue in the long run. Whether state or private interests are more served in resource conflicts separates realists from Marxists, but both see conflict as likely. In contrast to these resource pessimists, others contend that cooperation among states and firms and shared technological innovations render energy resource use more efficient, leading to the discovery of

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new resource frontiers and cooperative political relations. Many scholars argue that conventional energy resource depletion does not imply an actual exhaustion of global resources and a pending spike in conflict. Instead, they see developments in technology and firm strategies bringing newer and often more expensive resources into development, prolonging our existing resource-consuming infrastructures, while providing more opportunities for political collaboration in developing these more expensive resources. For example, with increased capital investment, we might extend natural resources such as oil for decades into the future. Daniel Yergin has always spoken for this school, arguing that “the resource endowment of the planet is sufficient to keep up with demand for decades to come” (Yergin 2009: 95). Yergin and other resource optimists presume that firms and governments will develop key resource geographies and technologies for their many end uses with little concern for relative power, while the “resource endowment of the planet” allows one to see oil sands as mere substitutes for oil without adverse social and environmental consequences. In this volume, analyses of both broad interdisciplinary schools are challenged. The more complex trade-offs among resource availability, technological constraints, and geopolitical rivalry are examined in several areas. In the early twenty-first century, the central focus of resource political economy lies on the future of the carbon-based political and economic order. Collectively, coal, oil, and natural gas still make up just over 80 percent of all energy consumption, much as they did in 1985. Alternative energy types such as nuclear, wind, solar, and geothermal supply small amounts of energy for power generation, but not for transport. Although vast electric rail transport exists in Asia and Europe, it was killed off in the main long ago in the United States by the National City Lines cabal (Snell 1995). Chevron, a key conspirator in that episode of entrenching the oil majors’ preferred transportation system, also played a large role in ensuring Japan’s dependence on US-controlled Middle East oil supplies. After China was reintegrated into the Western system and Daqing oil became a real alternative for those few Japanese refineries not run by the majors, the oil majors intervened to manage the flow of Chinese oil to Japan (Lehmann 2013: 137–138; Lee 1984; Harrison 1977). The oil majors have been successful in eliminating whole alternative infrastructures (as with electric light rail in the United States) and in limiting elementary supply diversification efforts by key allies such as Japan in the 1970s. In so doing, they have always ensured ready end use markets for their energy wares with few meaningful alternatives. Today may be little different. Tremendous investment in the Canadian oil sands of Alberta and ultra-deep oceanic regions are all led by the oil majors. For example, total investment in the Canadian oil sands dwarfs

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investment in electric batteries for transportation, which have seen approximately $5 billion in total investment in the United States and the bankruptcy of many once-heralded firms such as A123 Systems, A Better Place, and Fisker Automotive. The resurgence of oil and natural gas production in North America via hydraulic fracturing in “tight” shale reservoirs has driven down the price of natural gas and increased the attractiveness of Houston exploration and production (E&P) firms. Firms and states in Latin America, Europe, and other parts of the world are busily exploring this method of extracting oil and gas deposits with Houston partners. All of these developments reflect little more than path-dependent fealty to the existing petrochemical-based system and its leaders. Is confidence in continuously expanded development and demand for more expensive and less accessible oil and gas warranted? Which leading economies are using resources differently and challenging the fossilized future envisioned by the oil majors? While Japan and the United States appear wedded to fossil fuels, Germany leads in renewable energy for electricity while also committing itself to denuclearization. China, as in all spheres, is the 800-pound gorilla of global energy and resource politics. Will China stay with an oil-based future given its current dominance in rare earth elements production, the building blocks of any green power generation and electric mobility transportation future? Might Germany or Japan collaborate with China on transitioning away from coal and oil for electricity and transportation, and thereby nullify US dominance of the Middle East and rise of the unconventional North American petroleumbased order? Or, is China’s resource nationalism—vigorously on display with its rare earth export embargo on Japan in 2010 and recent military challenges in the East and South China Seas—foreshadowing more rivalry and conflict ahead? The academy is divided over these questions. Some, such as Amory Lovins (2011), argue that we are on the cusp of a total transformation away from fossil fuels, while others argue that alternative fuels and technologies are infeasible in the near term (Smil 2014). Maintaining the carbon-based economy requires development of previously inaccessible resources or the return to costly production of synthetic fuels from coal, oil sands, or oil shale feedstocks. Again, these were first perfected in interwar Germany when energy autarchy for war drove the country’s synthetic fuels program. This motivation for improved relative autonomy may apply to US and Canadian state and business decisions to promote Albertan oil sands, but the requirement to demonstrate this remains. For example, are these more costly oils desired for bargaining leverage vis-à-vis OPEC, or simply to help render North America fully autonomous (Jaffe and Morse 2013)? These motives are difficult to disentangle as all state and private actors

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have a stake in obfuscating how the world economy is driven by the development of energy resources. Coal, oil, and natural gas still determine the overall resource landscape, but their environmental consequences are all too apparent. Renewables might dethrone them if they can substitute in power generation and transportation. For example, a fully electric car could displace some oil, but it requires coal for electricity in many places and uses large amounts of rare earth elements mined in unsustainable ways, primarily in China. With any alternative resource, holistic assessment of “well to wheels” resource usage, carbon footprints, and environmental externalities is needed. This remains an elusive comparative analytic. What is certain is that the demand for energy and other resources did not abate with the global recession, and China’s growth ensures a constantly increasing need for resources of all types. Efficiencies and renewables might change conventional resource use, but this will only come to pass if the political power of the oil majors and their home governments are neutralized or converted to the cause. For example, existing hybrid cars only alter resource demand slightly and challenge Houston on the margins, as the United States and China have not embraced electromobility fully yet (a little less oil, much more rare earth elements for permanent magnet motors). Given Jevons’ paradox, transport electrification might not reduce overall resource consumption. China’s unrelenting growth in oil consumption since becoming the largest car and light truck market in 2009 is testament to this paradox.1 All electric vehicles would substitute rare earth–laden motors and lithium inputs for the oil-fired internal combustion engine. This would further oil-based mining operations and the depletion of many vital resources, while causing increased US and Chinese fossil-fueled electrical grid usage. Resource trade-offs such as these may appear optimal from some political or business vantage point, but the climate consequences and geostrategic ramifications of large-scale transition remain underexplored. Simply put, which resources and infrastructures will exist in the future are not products of an apolitical contest based on technical merit. Although it is true that oil defeated coal in transport due to its technical efficiency and military utility, it was even more important that the United States and Great Britain dominated oil’s early geography and the industrial base that produced the machines consuming the new fuels. Any serious transition to energy resources not under the control of the existing oil majors will be fraught with conflict, and frankly, must court it to have any chance of success. Whether the resource optimists or the pessimists will be proven more accurate is difficult to discern at the moment. It is not difficult, however, to see how energy politics will determine relative economic growth, geopolitical alignment, and the fate of the planet’s climate in the years to come.

The Geopolitics of Global Energy

Outline of the Book

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In the chapters that follow, the authors address conventional energy resources and related politics in a critical light, drawing on the vast store of scholarship on the processes of energy resource and industrial transitions. Which capital-intensive infrastructures are built determines which resources will be used in particular patterned ways for decades. In Chapters 2, 3, and 4, Michael Klare, Philippe Le Billon and Gavin Bridge, and Naná de Graaff introduce the broad themes of the volume and explore central questions appraising the state of political organization and rivalry in global energy resources. In these chapters the collective enterprise of the volume is summarized and long-standing global energy patterns and current trends are examined. In Chapter 2, Michael Klare offers a skeptical view on the carrying capacity of the planet and offers insights into the political consequences of fundamental resource scarcity, use, and depletion. Klare assesses whether geopolitical rivalry over energy is receding and finds little cause for hope that cooperation might replace rivalry in the energy world. In Chapter 3, Philippe Le Billon and Gavin Bridge address the enormous contribution of oil in global political economy, highlighting its essential role in all forms of commercial and military transportation. Le Billon and Bridge draw on their excellent book Oil (Bridge and Le Billon 2012) to explore the social and political dominance of oil and the difficulty in holding oil actors to account for the many social maladies that attend their enterprises. They illustrate how a new era of better oil might come to pass such that this energy order’s negative influences might be mitigated, eventually setting the stage for an energy transition to take root. In Chapter 4, Naná de Graaff employs her intriguing methodology for assessing transnational oil elites’ interlocking networks to probe the question of how international and national oil companies interact and whether there are new forms of corporate alliances afoot in the energy world. In Chapters 5 and 6, Dag Harald Claes and Timothy Lehmann evaluate the full range of issues surrounding what the continued dominance of “oil” means for resource politics, albeit for particular regions with broad, global implications. Respectively, they examine how the seemingly ceaseless push for oil and gas in the Arctic and the accelerating development of Albertan oil sands and fracked hydrocarbons in North America affect energy relations among the leading actors. These projects beguile many technological determinists who see the longevity of the conventional resource system proved in every barrel extracted from previously ignored undersea geographies and “heavy oils” in sand and “tight oil” shale deposits. Whether these unconventional resources presage enduring abundance is

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less clear, and the pitfalls of these projects are explored in light of the many past experiences of irrational exuberance in unconventional energy sources (e.g., the US Synthetic Fuels Corporation). Claes offers a reflective rejoinder to the resource pessimists of the world. He highlights the promise that the Arctic region may become one of cooperation among the leading energy actors of the world, instead of a zone of rivalry and conflict. In contrast, Lehmann spells out the interrelationship of North America and Middle Eastern oil resources in the global energy system and the ongoing saga of US hegemony. He finds little cause for optimism for a greener and more peaceful energy geopolitics. In Chapter 7, Andrew Erickson and Austin Strange explore the foregoing trends within a rising China keen on flexing its muscle in resource-rich near abroad regions. Erickson and Strange examine the all too broad subject of China, the largest natural resource–consuming and greenhouse gas–emitting nation on Earth, by detailing China’s push to control the offshore energy resources in the South China Sea. They examine the strategic consequences of China’s efforts to control the South China Sea militarily and assess whether the region’s oil and natural gas play a driving or ancillary role in the nation’s naval buildup in the region and more aggressive policy. China is planning to increase its use of natural gas, and its endeavors in the South China Sea affect the Asia Pacific region’s stability as much as its economy, which highlights whether the growth of natural gas becomes a force for integration and cooperation or its opposite. In Chapters 8 and 9, Volkmar Lauber and Andrew DeWit offer compelling studies of the world-leading developments in Germany and Japan. These nations highlight the difficulties of affecting the desired trend toward less conventional energy resources and more renewables. Each resourcepoor state grapples with external and internal pressures to use domestic energy transition to maintain relative economic position in regions where potentially rivalrous powers infringe upon them—Russia in the case of both Germany and Japan, and China in Japan’s case. Adding to the stresses in each country is the difficult political drama of denuclearization, particularly for Japan. Lauber explains how Germany’s impressive renewables development for electrical generation might not have come to pass had it not been for the benign neglect of leading German energy actors while citizens led a successful public power and renewables deployment campaign for nearly two decades. In contrast to Germany’s bottom-up approach, DeWit details how the Japanese state has had to cope with many shocks to its domestic energy system while trying to navigate its historically debilitating external energy dependency to even greater industrial and trade heights. In Chapter 10, Timothy Lehmann assesses the likely costs of the oil majors’ focus on spreading natural gas as a bridge fuel to some future with much less coal,

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but with only managed growth for renewables. The possibility of a renewables energy concert is evaluated against the entrenched power of the oil majors’ petrochemical concert. Notes

1. Jevons’ paradox concerned coal use in mid-1800s Britain and found that more efficient energy use only led to more energy use. Jevons noted: “It is wholly a confusion of ideas to suppose that the economical use of fuel is equivalent to a diminished consumption. The very contrary is the truth.” See also Galvin (2016: 1– 3, 11–13).

2 The Changing Geopolitics of Oil and Gas Michael T. Klare

Oil, the world’s most valuable and important source of energy, has long been intertwined with geopolitics, or the competition among states for political and economic advantage. As natural gas has come to supply a larger share of global energy supplies, it has also become enmeshed in global geopolitics. This association between hydrocarbons and geopolitics is a product of the critical role played by oil and gas in the functioning of modern economies and the fact that many consumers of these fuels lack adequate reserves of their own, making them highly dependent on supplies acquired from distant—and often turbulent—locations. To ensure uninterrupted access, the major consuming nations have established close ties with their major foreign providers and, in some cases, have employed military force to protect these countries and the supply lines that connect them to markets at home. Moreover, because the world’s most abundant sources of hydrocarbons are relatively few in number, energy-importing nations often find themselves in competition with each other for access to these supplies, producing a competitive struggle over oil and gas that plays a significant and often pivotal role in world affairs (Klare 2008; Painter 1986; Venn 1986; Stoff 1980). The struggle over oil and natural gas is driven by two fundamental considerations: a widely shared belief that energy constitutes a vital commodity whose acquisition is a matter of national security, and the geographic disconnect between the major sources of hydrocarbons and the major consuming nations. Oil is considered vital because it is the world’s leading source of energy—providing approximately 31 percent of total consumption in 2014 (IEA [International Energy Agency] 2016e: 550)—and because it is essential for transportation, industry, farming, and warfare. “Oil fuels more than automobiles and airplanes,” said Robert E. Ebel of the Center for Strategic and International Studies in a speech at the US Department of State, “oil fuels military power, national treasuries, and international politics” (Ebel 2002). Gas, accounting for approximately 21 percent of world 23

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energy (IEA 2016e: 550), is essential for electricity generation and many industrial processes. To the dismay of many oil- and gas-importing nations, however, many of the world’s largest oil and gas deposits are located in remote and often unstable areas—Libya, Kazakhstan, Russia, Venezuela, West Africa (notably Angola and Nigeria), and the Persian Gulf countries (Iran, Iraq, Kuwait, Qatar, Saudi Arabia, and the United Arab Emirates). As shown in Table 2.1, together these countries possess approximately 78 percent of the world’s proven oil reserves and 68 percent of natural gas reserves (BP [British Petroleum] 2016: 6, 20). The combined significance of these critical factors was particularly evident during the “oil shock” of 1973–1974, when the Organization of the Petroleum Exporting Countries (OPEC)—to which most of these countries belong—quadrupled oil prices and its Arab members imposed a ban on oil exports to the United States (in retaliation for US military aid to Israel), igniting a global economic meltdown. In response to these momentous events, the major oil-importing nations undertook an array of initiatives to reduce their vulnerability to disruptions in the global flow of oil, including creating strategic petroleum reserves, developing energy alternatives, and (in some cases) expanding military ties to the oil-producing countries (Yergin 1991: 588–632). Another outcome of the 1973–1974 oil crisis was a determined effort by the major oil-importing nations to develop alternative sources of supply

Table 2.1 Proven Oil and Gas Reserves of Selected Countries and Regions in 2015 Country and Region

Persian Gulf region Iran Iraq Kuwait Saudi Arabia United Arab Emirates Qatar Libya Venezuela Russia Kazakhstan West Africa region Total, all of above Canada Total, world

Proven Oil Reserves (billions of barrels, bbl) 803.5 157.8 143.1 101.5 266.6 97.8 25.7 48.4 300.9 102.4 30.0 54.5 1,339.7 172.2a 1,697.6

Oil Reserves as Percentage of World Total 47.3 9.3 8.4 6.0 15.7 5.8 1.5 2.8 17.7 6.0 1.8 3.2 78.0 10.1 100.0

Source: British Petroleum (2016: 6, 20). Note: a. Of which tar sands account for 166.2 billion barrels.

Gas Reserves as Percentage of World Total 42.8 18.2 2.0 1.0 4.5 3.3 13.4 0.8 3.0 17.3 0.5 3.3 67.7 1.1 100.0

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to balance their reliance on the Persian Gulf. Because such a large share of the world’s exportable oil originates in the gulf, the Arab embargo resulted in an immediate and severe contraction in the global energy supply. This, more than anything else, explains subsequent US efforts to bolster its ties with the leading Persian Gulf suppliers and protect the flow of oil to international markets. At the same time, the United States and other importing nations sought to protect themselves against future disruptions in the flow of Middle Eastern oil by increasing their reliance on other foreign sources of supply, including sub-Saharan Africa and the Caspian Sea basin. This provided some insurance against the risks of excessive dependence on the Middle East but did nothing to eliminate the disconnect between supply and demand. Not surprisingly, the increased reliance on alternative supply zones has led to greater outside involvement—diplomatic, economic, and military—in those regions (Klare 2004: 113–145). Concern over the safety of oil deliveries from foreign lands has contributed to increased reliance on natural gas as a source of energy, especially in Europe, which seeks to replace coal with gas in generating electricity (and thereby reduce its carbon emissions). For a while, the Western European nations were able to obtain substantial supplies of gas from deposits in the North Sea. With the recent decline in North Sea production, however, the Europeans have had to draw on supplies carried by pipeline from Russia (the world’s leading gas exporter) and in the form of liquefied natural gas (LNG) from a growing number of suppliers. Other countries, including China and India, also seek to increase their reliance on gas as a way of diminishing their vulnerability to disruptions in the flow of oil and reduce their carbon emissions (US EIA [Energy Information Administration] 2013c: 41–66). Increased reliance on natural gas provides a hedge against excessive dependence on oil because it may increase the potential pool of foreign suppliers. The use of advanced drilling technologies—notably horizontal drilling and hydraulic fracturing (“fracking”)—is also allowing for the exploitation of new sources of gas once thought inaccessible, such as the giant Marcellus shale formation in the United States and similar deposits in China, Poland, and Argentina (US EIA 2013c: 41–66). However, reliance on natural gas also raises many of the same geopolitical problems associated with dependence on petroleum. Heavy European dependence on Russian gas, for example, has sparked concern that Moscow will use its commanding position to influence regional politics—something it has already sought to do in Ukraine and other corners of the former Soviet space (Högselius 2013). Attempts by Europe to diminish its reliance on Russian gas by building pipelines to the Caspian Sea area have been met with resistance from Moscow (which fears the diminution of its market share) and competition

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from China (which wants the gas for its own use) (Bradshaw 2013: 74–79, 99–113; Paik 2012). Today, many oil- and gas-importing countries are attempting to reduce their vulnerability to disruptions in the global flow of hydrocarbons by increasing their reliance on alternative fuels, including nuclear power and renewable sources of energy. Although these efforts are likely to gain increased traction in the years ahead, they will not eliminate the world’s reliance on oil and gas. Countries such as China and India are undergoing rapid industrialization and therefore generating growing numbers of car-buying consumers and electrical-grid users. As a result, the global demand for oil is projected to grow by 34 percent between 2012 and 2040, rising from 90 to 121 million barrels a day, and consumption of natural gas is expected to grow by 70 percent. While other fuels, including renewables, are making inroads into oil’s global market share, petroleum will remain the dominant source of world energy for decades to come (US EIA 2016d: 25–31). Along with continued reliance on petroleum as a major source of energy, many nations will also face continued reliance on imported oil. As shown in Table 2.2, China, India, and the European countries are expected to face increased reliance on imports between now and 2040. Altogether the amount of imported oil required by the major oil-importing countries to satisfy anticipated national requirements will increase by 28

Table 2.2 Oil Consumption and Imports in Selected Countries and Regions, 2012 and 2040

Countries and Regions

OECD, total United States OECD Europe Japan Russia Middle East Non-OECD Asia China India Africa South and Central America Total for all import-reliant countries

2012 Actual 2040 Projected Imports Imports Consumption or (Exports) Consumption or (Exports) (mbd) (mbd) (mbd) (mbd) 45.5 18.5 14.1 4.7 3.4 7.7 21.5 10.2 3.6 3.6 6.7 67.0

23.0 7.4 10.3 4.7 (7.2) (20.2) 13.2 5.8 2.6 (6.3) (1.3) 36.2

46.1 19.3 14.0 3.4 3.6 13.2 38.6 16.4 8.3 6.9 9.6 84.7

Source: US EIA (2016d: Tables A5, G1). Notes: mbd = million barrels per day. OECD = Organisation for Economic Co-operation and Development.

17.2 3.4 11.2 3.4 (8.9) (27.6) 28.7 10.1 7.2 (4.1) (3.6) 45.9

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percent over this period, jumping from 36 to 46 million barrels a day (US EIA 2016d: 168, 223). In the case of natural gas, the growing use of fracking technology will allow some countries, including the United States, to become self-sufficient, but many gas consumers will become increasingly reliant on imports. For example, China is expected to see its natural gas imports jump from 29 billion cubic meters in 2011 to 212 billion cubic meters in 2035, an increase of over 600 percent (IEA 2013a: 103, 109). This growing reliance on imported oil and gas will ensure that energy geopolitics will continue to play a pivotal role in world affairs. The Origins of Oil and Gas Geopolitics

Until very recently, the geopolitics of oil and gas has largely been dominated by developments in the Persian Gulf area. This is hardly surprising, given that the major gulf producers—Iran, Iraq, Kuwait, Oman, Qatar, Saudi Arabia, and the United Arab Emirates (UAE)—jointly possess the world’s largest reserves of oil (see Table 2.1) and account for a very large share of the world’s exportable oil—the internationally traded supplies on which countries with an inadequate domestic supply of oil must depend (BP 2016: 6, 8–9, 18). The same is true for the international trade in LNG, of which Qatar and Saudi Arabia are major suppliers. In 2013, for example, an estimated 30 percent of the world’s seaborne oil commerce was carried by tankers from the gulf and through the Strait of Hormuz to global markets, and Qatar alone supplied nearly one-third of global LNG exports (BP 2016: 28; US EIA 2014e). With so much of the world’s exportable oil and gas originating in the gulf area, ensuring access to these supplies—and to their unimpeded transport through the strait to international markets—has long been a strategic priority for the major oil-importing countries (Palmer 1992). The relationship between oil, security, and the gulf area first arose in the years leading up to World War I, when Great Britain converted its warships from coal to oil propulsion. Because Britain had no significant reserves of its own at that time (the discovery of its North Sea fields came much later), it sought reliable foreign sources of supply to meet the nation’s military requirements. This led to a decision by the Cabinet to acquire control of the Anglo-Persian Oil Company (APOC), a private UK-based firm that had obtained a concession to promising reserves in southwest Persia. (APOC later became the Anglo-Iranian Oil Company, then British Petroleum.) Protection of this concession became a major British war aim, and British troops were dispatched to the area to ensure it did not fall under the control of German or Ottoman forces (Yergin 1991: 153–164, 173–76; Jones 1981: 9–31, 129–176).

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As oil’s importance in warfare became evident during World War I, through the introduction of such oil-powered weapons as tanks and aircraft, other European powers sought access to reserves in the Middle East, producing a scramble for imperial power and influence. At the height of the war, Britain and France signed a secret agreement—the Sykes-Picot Agreement—to divide up the oil-rich territories of the Ottoman Empire once the fighting was over; ultimately Britain took control of Iraq and France of Syria. In subsequent years, other powers, including Germany, also sought oil concessions in the Middle East (Yergin 1991: 184–206, 260–308; Jones 1981: 35–53). The United States did not play a significant role in the drive to gain control over Middle Eastern oil reserves during this period, because it could satisfy its national requirements from domestic fields. During World War II, however, President Franklin D. Roosevelt—facing expectations of declining US production in the years ahead—concluded that the United States would have to acquire control over a prolific foreign source of oil, much as Britain had done in Persia (later Iran). After searching for a suitable candidate, he selected Saudi Arabia to serve this purpose (Painter 1986: 32–51, 85–95; Stoff 1980: 34–88). To formalize this arrangement, Roosevelt met with King Abdulaziz ibn Saud on February 14, 1945, and brokered an agreement with him through which the United States would be granted exclusive access to the vast oil reserves of Saudi Arabia’s Eastern Province in return for a pledge to protect the kingdom and its ruling dynasty. This, in turn, led to the establishment of US military bases in the area and the deployment of a permanent US naval presence in the Persian Gulf (Palmer 1992: 20–25; Yergin 1991: 403–405). In the years that followed, the United States became ever more deeply involved in Persian Gulf affairs. Following the 1968 British decision to withdraw their forces from the region, President Richard M. Nixon chose Iran—then controlled by Shah Mohammad Reza Pahlavi—to serve as a substitute “gendarme” in the gulf and, in accordance with this plan, agreed to give the Iranians a vast array of modern US weapons (Klare 1985: 108– 126). When the shah was overthrown by a coalition of nationalists and radical clerics in 1979, President Jimmy Carter concluded that the United States would have to assume the role of regional gendarme on its own. This decision, articulated in Carter’s State of the Union address of January 23, 1980, led to a further buildup of US forces in the region (Palmer 1992: 101–111). The Carter Doctrine represents one of the most explicit and forceful expressions of the links among oil, geography, and military policy. Carter began by laying out the geopolitical stakes in the gulf: “The Soviet effort to dominate Afghanistan has brought Soviet military forces to within 300 miles of the Indian Ocean and close to the Straits of Hormuz, a waterway

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through which most of the world’s oil must flow. The Soviet Union is now attempting to consolidate a strategic position, therefore, that poses a grave threat to the free movement of Middle East oil.” Given the magnitude of this danger, he indicated, the United States could not remain passive. “Let our position be absolutely clear: An attempt by any outside force to gain control of the Persian Gulf region will be regarded as an assault on the vital interests of the United States of America, and such an assault will be repelled by any means necessary, including military force” (Carter 1980). To implement this edict, Carter announced a series of military measures aimed at bolstering US military capabilities in the greater gulf area. “We’ve increased and strengthened our naval presence in the Indian Ocean and we are now making arrangements for key naval and air facilities to be used by our forces in the region of northeast Africa and the Persian Gulf,” he declared on January 23. Because the United States did not then possess any forces specifically intended for operations in the gulf, Carter established a new group of forces—the Rapid Deployment Joint Task Force—to implement the new policy. This group was given added muscle in 1983, when President Ronald Reagan transformed the joint task force into the US Central Command (Centcom) (Odom 2005; Njølstad 2004; Palmer 1992: 101–117). Reagan was also the first US leader to implement the Carter Doctrine. During the Iran-Iraq War of 1980–1988, following persistent Iranian attacks on Kuwaiti and Saudi oil tankers, Reagan authorized the “reflagging” of these tankers with the US ensign and their protection by the US Navy (Operation Earnest Will) (Palmer 1992: 117–149). The protection of Persian Gulf oil was also cited by Reagan’s successor, President George H. W. Bush, as the justification for US efforts to eject Iraqi forces from Kuwait during the Gulf War of 1990–1991 (Operation Desert Storm). When Saddam Hussein later succeeded in reconstituting Iraqi forces, Bush’s son, George W. Bush, authorized the 2003 US invasion of Iraq (Klare 2004: 49– 53, 94–102; Palmer 1992: 150–192). Today the relationship among oil, security, and the Persian Gulf area remains as strong as ever. This is evident, for example, in the recurring statements by US leaders that the United States will use force if necessary to ensure the safe flow of Persian Gulf oil through the Strait of Hormuz in response to any effort by Iran to impede such shipping. The United States will “take action and reopen the Strait” if Iran tries to close it, declared General Martin E. Dempsey, chairman of the Joint Chiefs of Staff, in January 2012 (Bumiller, Schmitt, and Shanker 2012). To guarantee Centcom’s ability to accomplish this objective, the Barack Obama administration retained a substantial air and naval presence in the Persian Gulf area following the withdrawal of US combat forces from Iraq and Afghanistan.

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“We will have a robust continuing presence throughout the region,” Secretary of State Hillary Clinton declared in 2011 (Shanker and Myers 2011). Beyond the Gulf: US Oil-Protection Operations in the Caspian Sea Region and Africa

Ever since the oil crisis of 1973–1974, US leaders have sought to reduce the nation’s vulnerability to supply disruptions in the gulf area by increasing dependence on other oil-supplying regions. This effort, known as “diversification,” acquired increased emphasis after the fall of the shah in 1979 and the rise of Iraq as a significant threat to the safety of Persian Gulf oil exports. To reduce US reliance on the ever-turbulent gulf, the diversification drive placed particular emphasis on the procurement of oil from the Caspian Sea basin and West Africa, two promising alternative producing zones (National Energy Policy Development Group 2001). Although attractive as alternatives, these areas harbor threats of their own to the safe flow of oil, and so growing US reliance on their hydrocarbon output has led to increased US military involvement in both the Caspian region and Africa. The Caspian Sea basin first attracted widespread interest in the early 1990s, following the breakup of the Soviet Union. Until then, oil production in this region was under the control of central planners in Moscow, and there was little opportunity for either indigenous firms or foreign companies to become involved. After the Soviet breakup in 1992, however, the energyrich states of the region—Azerbaijan, Kazakhstan, Turkmenistan, and Uzbekistan—opened their countries to foreign investment, usually in conjunction with new state-owned companies (Klare 2001: 81–108). Before long this resulted in the establishment of several major international consortia for the extraction and export of the region’s energy resources. These include, for example, projects to exploit the Shah Deniz and Azeri-ChiragGunashli fields in Azerbaijan and the Kashagan and Tengiz fields in Kazakhstan; foreign participants in these projects include BP, Chevron, Eni of Italy, ExxonMobil, Royal Dutch Shell, Statoil of Norway, and Total of France (Klare 2008: 115–128, 137–141). Despite the keen international interest in these projects, the exploitation of Caspian basin reserves has posed substantial obstacles to the companies involved. To begin with, the Caspian Sea has no outlet to international waters, and so all oil leaving the region has to be carried by pipeline. To compound the problem, most existing pipeline routes traveled through Russia to the West and were unappealing to Western firms. The most attractive alternative routes travel across Iran to the Persian Gulf, but international

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investments in that country are punishable under US sanctions. To transport Caspian oil to international markets, the energy firms have had to build new pipelines across the Caucasus area to the Black Sea or the Mediterranean. This has posed additional problems: many of the trans-Caucasus pipeline routes pass through or near major areas of conflict, including Chechnya, Nagorno-Karabakh, and South Ossetia (Yergin 2011b: 43–79). Because of its interest in promoting the diversification of foreign oil supplies, the United States has sought to facilitate the construction of new pipelines across the Caucasus and, in recognition of the turmoil there, has taken steps to bolster the military capabilities of transit countries, notably Azerbaijan and Georgia. This effort began under President Bill Clinton, who took a personal interest in funneling Caspian energy to Western markets (LeVine 2007). By engaging in such efforts, he told Azerbaijan president Heydar Aliyev at a White House reception, “we not only help Azerbaijan to prosper, but also help diversify our energy supply and strengthen our nation’s security” (Clinton 1997). In line with this outlook, Clinton played a direct role in negotiations leading to the construction of one of the major new arteries, the Baku-Tbilisi-Ceyhan (BTC) pipeline, spanning from Baku on Azerbaijan’s Caspian coast to Tbilisi in Georgia and then to Ceyhan on Turkey’s Mediterranean coast. To ensure the safety of this conduit, Clinton authorized a substantial allotment of military aid to Azerbaijan and Georgia (Klare 2004: 132–139). A similar trajectory of increased US involvement can be seen in the oilproducing areas of West Africa. Keen to reduce US reliance on the Persian Gulf area and increase drilling opportunities for US oil firms, the George W. Bush administration placed particular emphasis on increased US involvement there. “African oil is of national strategic interest to us,” Assistant Secretary of State Walter Kansteiner III declared in 2002, “and it will increase and become more important as we go forward” (Crawley 2002). With strong support from Washington, major US oil companies, including Chevron and ExxonMobil, have acquired substantial stakes in Angola’s and Nigeria’s oil fields (Klare 2008: 157–164). Although Africa harbors significant reserves of oil and natural gas, it also contains areas of chronic violence and instability. To ensure the safety of African production and exports, the US government has stepped up its military assistance to friendly governments in West Africa. Much of this aid has gone to Nigeria, the leading producer in the area and the site of recurring antigovernment violence. Because this violence has often involved attacks on oil tankers and offshore oil platforms in the Gulf of Guinea, the United States has increased its naval presence in the area and worked with local governments to bolster their naval capabilities. To help sustain and manage these endeavors, President Bush authorized the establishment of the

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US Africa Command (Africom) in 2007, much as President Carter followed the enunciation of his famous doctrine with the creation of what became Centcom (Ploch 2011). The Changing Geopolitical Environment

In all three of these areas—the Persian Gulf, the Caspian basin, and West Africa—the United States continues to engage in significant efforts to ensure the safety of oil and gas production and exports. To a considerable degree, the threats faced by Washington in this regard stem from local conflicts and insurgencies, along with terrorist organizations such as al-Qaeda and the Islamic State. Increasingly, the United States must also contend with efforts by other major powers, notably China and Russia, to play a commanding role in these areas. Russia has sought to reestablish its dominant position in the Caucasus and Central Asia, so as to better exercise control over the flow of Caspian oil and natural gas. China, seeking access to additional supplies of energy, has begun to exert considerable influence in all three areas. In response to these efforts, the United States has tried to bolster its own presence in these regions, adding more dimensions to the geopolitics of oil and gas (Klare 2008: 88–209). Russia’s drive to reassert its position in the Caspian basin is being fueled by both political and economic objectives. Russia seeks to demonstrate its political dominance in an area once controlled by the czarist and Soviet empires, viewed by many in Moscow as constituting part of Russia’s natural sphere of influence. This has sparked various Russian initiatives— diplomatic, economic, and military—to exert influence over the governments of the newly independent states. Among other initiatives, Moscow has used the Collective Security Treaty Organization, a regional defense network, as an umbrella to provide arms and training to the forces of friendly regimes and legitimate the deployment of Russian forces in the region. At the same time, Moscow looks to funnel Caspian oil and gas exports through Russian pipelines on their way to markets elsewhere, thereby enjoying lucrative transit fees. These motives came together in the 2008 Russian confrontation with Georgia over the status of South Ossetia—a nominally selfgoverning enclave claimed by Georgia but linked to Russia. By seeking the decimation of Georgian forces, Moscow intended to weaken Georgia’s independence and threaten the viability of Western-backed pipelines such as the BTC, which passes near South Ossetia on its way to Turkey (Klare 2012a: 222–223; Klare 2008: 215–217, 226–227). China also seeks to increase its political influence in Africa, the Caspian basin, and other energy-producing areas, but the primary motive

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for its endeavors is to gain access to oil, gas, and mineral resources. China is now the world’s leading consumer of energy and is expected to account for the biggest share—40 percent—of the projected increase in global energy consumption over the next quarter of a century (US EIA 2013c: 179; Yergin 2011b: 189–224). As in the past, China’s security-conscious leaders aim to rely as much as possible on domestic sources of energy to satisfy the country’s growing needs but will nevertheless be forced to rely on imports to a considerable degree. This is especially true in the case of oil: because of limits on China’s ability to increase production from domestic wells, it will be forced to import an ever-increasing share of the nation’s oil requirements. As shown in Table 2.2, China’s oil import requirement will jump from 5.8 million barrels a day in 2012 to 10.1 million barrels in 2040, an increase of 74 percent (US EIA 2016d: 168, 223). Likewise, China is becoming increasingly dependent on imports of natural gas: from 22 percent in 2011, its reliance on imported gas will rise to an estimated 40 percent in 2035 (IEA 2013a: 103, 109). To ensure its ability to secure all this added oil and gas, China—like the United States before it—is extending its diplomatic and military sway to the major energy-producing regions (Economy and Levi 2014: 46–67). China’s drive to increase its influence in key energy-producing areas can be seen in its aggressive diplomatic outreach to leaders in Central Asia and Africa. Central Asia is of particular interest to Beijing because its oil and gas exports can be carried by pipeline directly to the Chinese border, eliminating the need for tankers that would travel through waters controlled by the US Navy (Erickson and Collins 2010). To promote such ties, China has showered Central Asian leaders with economic aid and diplomatic attention and invited them to play a conspicuous role in the Shanghai Cooperation Organisation (SCO), a regional economic and security organization. Under the auspices of the SCO, China has been supplying Central Asian forces with military aid and participating with them in joint military maneuvers (Perlez 2013b; Gill and Oresman 2003). Africa is also attractive to China as a source of energy because local governments appear open to increased Chinese involvement and the Western presence—though substantial—is less overbearing than it is in the Persian Gulf. To cultivate ties with African oil producers and allow for increased participation in their extractive operations by Chinese firms, Beijing has provided them with substantial economic aid and invited them to diplomatic extravaganzas such as the Forum on China-Africa Cooperation (Economy and Levi 2014: 68–98). As in Central Asia, moreover, it has provided friendly African governments with various forms of military assistance (Klare 2008: 164–171, 214). China has used similar arrangements in pursuit of African natural gas, as is readily observable in its recent

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multibillion-dollar dealings for LNG in Mozambique (Haas 2013; IEA 2011b: 43). Still in question is the degree to which China will imitate the United States by using military power to ensure the safety of its vital energy supply lines. Chinese naval officials have become particularly insistent on China’s need to enhance its ability to protect these lines. “With the expansion of the country’s economic interests, the navy wants to better protect the country’s transportation routes and the safety of our major sea lanes,” Rear Admiral Zhang Hua-chen declared in 2010. “In order to achieve this, the Chinese Navy needs to develop along the lines of bigger vessels and with more comprehensive capabilities” (Wong 2010). Recent comments by President Xi Jinping suggest that top government officials share this outlook: according to one account, Xi told a Politburo meeting in 2013 that China must become a “maritime strong power” (Perlez 2013a). China has acquired new warships, including an aircraft carrier, and is undertaking more deep-sea naval maneuvers. It remains unclear, however, whether China aims to achieve parity with the United States in terms of overall naval power (Holmes and Yoshihara 2007). Whatever their ultimate objectives, China’s and Russia’s efforts to establish close ties with key energy-producing countries is bound to generate increased friction with the United States. As indicated, China has followed the US precedent by using arms deliveries and military aid to cement relationships. In some cases, as in Nigeria and Kazakhstan, this has led to a competitive arms-supply process, with China and the United States using weapons transfers to win the favor of supplier governments. In other cases, China has forged such relationships with governments deemed hostile to US interests, such as Iran and Sudan, thus provoking deep concern in Washington. Russia’s efforts to extend its sway in the Caspian area—again using arms and military aid—has also sparked concern. As long as the overall balance of relations between Washington and the other two remains positive, these arms-supply endeavors will remain on the margins of US security interests; if, however, relations with China and/or Russia turn sour, these activities could prove to be a major source of friction (Klare 2008: 211–219). New Fuels, New Technologies, New Geographies

In addition to the growing involvement of China and Russia in these oilproducing regions, the geopolitics of energy is being transformed in other ways. Most significant in this regard are a growing shift toward reliance on natural gas as the fuel of choice and the introduction of new drilling technologies that allow for the exploitation of previously inaccessible oil and gas reserves.

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According to International Energy Agency (IEA) projections, the share of world energy provided by natural gas is expected to rise from 21 percent in 2014 to 24 percent in 2040, while the shares held by both oil and coal will experience a noticeable decline (IEA 2016e: 550). The expected increase in gas consumption is the product of several factors, including efforts by many countries to reduce their emissions of carbon dioxide and, as noted earlier, a desire to diversify fuel dependence away from excessive reliance on oil (Stern 2012). In the United States, the attraction of gas has been further enhanced by a drop in its price, made possible by new technologies, especially hydraulic fracturing, which allow the extraction of supplies from previously inaccessible domestic shale reserves (US EIA 2013c: 41–66). Because natural gas is often produced from the same geological formations as those for oil—and thus is usually found in the same locations as major deposits of petroleum—an increase in global reliance on gas will not result in a dramatic shift in energy geopolitics. Of the ten countries with the largest reserves of natural gas, six—Iran, Nigeria, Russia, Saudi Arabia, the United Arab Emirates, and Venezuela—are also among the top ten holders of oil reserves (BP 2016: 20). These countries have long played key roles in the geopolitics of energy and will continue to do so in the future as natural gas comes to play a more significant role. But there are some noticeable standouts in the roster of major gas producers: Qatar, with the world’s thirdlargest reserves; Turkmenistan, with the fourth-largest; the United States, with the fifth; and Australia, number thirteen. These countries and a number of others will add a new dimension to the geopolitical equation. Of perhaps the greatest significance in all this is the emergence of the Caspian Sea basin and Central Asia as major sources of natural gas. Together, the four major Caspian producers—Azerbaijan, Kazakhstan, Turkmenistan, and Uzbekistan—possess about 11 percent of the world’s gas reserves, or as much as North and South America combined (BP 2016: 6, 20). Until 1992, all of this gas was funneled into Soviet pipelines and used in accordance with policies set by central planners in Moscow (Jentleson 1986). With the breakup of the Soviet Union, however, these states have sought multiple clients for their gas, including new customers in the west (Europe), east (China), and south (India and Pakistan). As noted, Russia also seeks to play a commanding role in the region and funnel as much of the gas northward, into its own territory, as was the case during the Soviet era. This has led to a fierce, competitive struggle to clinch deals with the countries involved and build (or expand) pipelines in all four directions (Högselius 2013; Paik 2012; Klare 2008: 128–141). The leaders of Turkmenistan, for example, have been the object of intense courtship by leaders of all the major players. The European Union has placed high priority on building a new gas pipeline under the Caspian

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Sea to transport Turkmen gas to a terminal near Baku, Azerbaijan, where it can connect with planned conduits that will extend across the Caucasus to Turkey and southern Europe (European Commission 2011). The Russians, fearful of losing their market share in Europe, have put immense pressure on Turkmenistan’s leaders to build new pipelines along the east side of the Caspian to connect to existing conduits in Russia (Dempsey 2007). Meanwhile China has succeeded in building a pipeline from eastern Turkmenistan to western China via Uzbekistan and Kazakhstan, resulting in ever-deepening Chinese involvement in the region (US EIA 2012a). India and Pakistan hope to build pipelines from Turkmenistan to their countries via Afghanistan, when and if conditions in that country make such an undertaking possible (US EIA 2012a). The emergence of Qatar, Australia, and the United States as major gas exporters has also affected the global geopolitical equation. In these cases, a shift in the mode of delivery is affecting the geopolitical equation: by exporting their gas in the form of LNG rather than shipping it via pipeline, these producers can sell to a wider world market. Similarly, by building LNG receiving terminals, major gas-importing countries such as China, Japan, South Korea, and the European nations can multiply their sources of supply, thereby minimizing the risks of overreliance on one or two major suppliers. This is especially attractive for the EU countries, which seek to reduce their reliance on pipeline-delivered Russian gas. To satisfy this demand, Qatar, Nigeria, Australia, and others are stepping up their gas production and building new LNG export terminals. The United States presents an especially interesting case. Until a few years ago, the country was planning to build more LNG terminals to import gas, in anticipation of future shortages. Now, as a result of increased domestic production, it is converting some existing terminals to allow the export of gas and considering the construction of new, entirely export-oriented terminals (IEA 2013b: 127). One of the arguments advanced for allowing such exports is that deliveries of cheap US LNG to Europe would help reduce that area’s dependence on Russian gas, thus reducing Moscow’s ability to apply political pressure on European governments (Massey and Vukmanovic 2014). The increase in domestic US gas output is the result of a determined drive by US energy firms to use advanced technologies to exploit oil and gas reserves once considered inaccessible. This drive was undertaken less for geopolitical purposes than to address a fundamental challenge to their industry: the systemic decline of existing oil and gas reserves and growing reliance on newer fields that are often harder to exploit than those they are replacing, whether because they are deeper underground, further offshore, further north, or in less permeable rock formations. To take advantage of these hard-to-reach reserves, the energy companies are devoting enormous

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effort and resources to the development of new, more capable extractive technologies. Although their intent in developing these technologies has been to sustain production in the face of prospective decline, their use does have significant geopolitical implications. In particular, these developments include deploying deep-sea drilling platforms, which allows for exploiting deepwater fields in the Gulf of Mexico, the South Atlantic, and the South China Sea; introducing ice-hardened platforms, allowing for the exploitation of reserves in Siberia and the Arctic region; and the widespread use of fracking, permitting the extraction of oil and natural gas from impermeable shale formations in Argentina, Canada, China, and the United States (Levi 2013: 1–80; Yergin 2011b: 242–262). Offshore Oil and the Arctic

Oil companies have long drilled in shallow coastal areas adjacent to major onshore reserves, for example, in waters off Texas and Louisiana in the United States and off Baku in what is now Azerbaijan. But the development of deepwater drilling is a relatively recent phenomenon. In 2005, Chevron set a record by drilling in 3,500 feet of water in the Gulf of Mexico, a major site for deepwater innovation. Just a year later, Chevron doubled that depth at its Jack No. 2 well at another Gulf of Mexico location. Shell was the next to break records, announcing in 2010 that it had drilled 8,000 feet beneath sea level at its Perdido field, 200 miles east of the Texas coastline (Klare 2012a: 41–49). The Brazilians are also beginning to reach extreme depths in their efforts to exploit newly discovered undersea reservoirs in the South Atlantic, called “pre-salt” fields as they lie below a thick layer of salt (US EIA 2013b). Record-breaking depths have also been reached in waters off India and Angola. As was true of the emergence of new drilling opportunities in the Caspian Sea basin and West Africa, the development of these offshore fields has sparked enormous interest from the major oil-consuming countries and aroused fresh geopolitical competition. Brazil’s pre-salt fields, for example, are believed to house as much as 80 billion barrels of oil, pushing Brazil into the top tier of oil producers and giving that country added international clout. Many observers attribute Brazil’s more assertive foreign policy—for example, its (abortive) 2010 drive to broker a peace deal between Iran and the West—to its newfound petroleum wealth (Barrionuevo 2010). The prospect of obtaining more oil from a friendly Western Hemisphere nation has also prompted the United States to devote more attention to Brazil. “We want to work with you,” President Obama told a group of Brazilian business leaders in March 2011. “We want to help with technology and support to

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develop these oil reserves safely, and when you’re ready to start selling, we want to be one of your best customers” (Obama 2011). Brazil’s pre-salt fields lie entirely within the 200 nautical mile “exclusive economic zone” (EEZ) claimed by Brazil, and so are not a source of contention with other states. But many important deepwater fields are located in waters falling within the overlapping EEZs of two or more powers, leading to disputes over ownership. This is true, for example, of undersea oil and sea deposits in the East and South China Seas. The East China Sea houses a major gas field claimed by both China and Japan, and the South China Sea houses oil and gas fields claimed by China, Vietnam, and the Philippines. These countries have sought to exploit these fields, and in the process have faced stiff opposition—some of it violent—from the other claimants (US EIA 2014a, 2013f). In 2014, for example, China deployed a drilling rig in an area of the South China Sea said by Vietnam to lie within its EEZ, prompting naval clashes at sea (fortunately without producing casualties) and antiChinese rioting across Vietnam (resulting in several deaths). The parties to these disputes have pledged to resolve them through peaceful means, but all states involved continue to deploy air and naval forces in the contested areas, and the risk of an armed encounter remains significant (Klare 2015: 10). The prospect of expanded drilling in the Arctic region has sparked similar interest and contestation. By all accounts, the Arctic harbors vast reserves of oil and gas. According to a 2008 study of the US Geological Survey the area houses approximately 30 percent of the world’s undiscovered natural gas reserves and 13 percent of its undiscovered oil (US Geological Survey 2008). However, the region’s very harsh weather conditions have made it extremely difficult for energy firms to operate there. As a result of global warming, however, operating conditions have become noticeably improved, especially with the shrinkage of the Arctic ice cap. To exploit these nowmore-accessible reserves, oil firms are deploying new drilling platforms with an enhanced capacity to resist collisions with floating sea ice (O’Rourke 2013; Budzik 2009). Royal Dutch Shell, for example, attempted to drill in parts of the Beaufort and Chukchi Seas adjacent to Alaska for years, but recently quit this venture due to losses and operating difficulties. Statoil is extracting gas from Norway’s sector of the Barents Sea, while Russia’s Gazprom is preparing to drill in the Pechora Sea, off northern Siberia. Many other such endeavors, including a collaborative effort by Exxon and Rosneft to exploit oil reserves in the Kara Sea, have borne fruit in recent years, despite US sanctions causing a temporary freeze in operations (Conley and Rohloff 2015: 3–5, 33–34; Klare 2012a: 70–93). The accelerated development of the Arctic’s oil and gas reserves poses many significant environmental issues, given the fragility of many Arctic ecosystems and the likelihood that any oil spills would produce far more

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damage than comparable disasters in more temperate, resilient environments (O’Rourke 2013: 30–31; Goldenberg 2010). Energy development in the Arctic is also likely to spark geopolitical tensions. This is because of the immense resource potential of the region and the fact that disputes have arisen over the location of offshore boundaries—and thus over the ownership of certain energy reserves. The United States, for example, has a boundary dispute with Russia in the Bering Sea and with Canada in the Beaufort Sea. Canada has a dispute with Greenland over their mutual boundary, as does Greenland with Iceland (O’Rourke 2013: 15–16; Hober 2011: 54–60). Ownership of the polar area—a potential source of oil and natural gas—is also in dispute, with Canada, Greenland, and Russia all claiming large swaths of the region. These disputes would not arouse much concern in the absence of major energy deposits, but take on greater significance when the states involved hope to procure significant economic benefits from the areas in question. As noted by US secretary of defense Chuck Hagel in 2013, “a flood of interest in energy exploration [in the Arctic] has the potential to heighten tensions over other issues” (Hagel 2013). The risk of tension and conflict in the Arctic is further exacerbated by the determination of key regional policymakers to rely on military power to reinforce their claims to prized Arctic real estate. Although all the Arctic nations have pledged to refrain from the use of force in asserting their claims, most have announced plans to enhance their capacity to engage in combat operations in the area (Smith 2011: 117–124; Conley and Kraut 2010). Russia, for example, has organized a new strategic command for the Arctic zone, established new bases in the Arctic, and deployed specially equipped combat forces there. This buildup, said President Vladimir Putin, “will make it possible to substantially strengthen our military and border security and also increase the effectiveness of the protection of natural resources” (Conley and Rohloff 2015: 9–13; Kipp 2011; Conley and Kraut 2010: 23–25). Canada has undertaken plans to bolster its presence in the Arctic, establishing a new base at Resolute Bay on Cornwallis Island and ordering a new fleet of ice-hardened patrol ships (Conley and Kraut 2010: 17–18). Norway, which shares a border with Russia in its far north, has relocated its combined military headquarters to Boda, above the Arctic Circle, and taken other steps to enhance its Arctic combat capabilities (Conley and Kraut 2010: 21–23). How all this will play out cannot be foreseen, but it does appear likely that the Arctic region will acquire increased geopolitical significance in the years ahead as interest grows in its resources and global warming allows increased drilling there. Whether this will lead to increased international tension will depend on the willingness of local powers to resolve their boundary disputes and refrain from the use of force in asserting their

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territorial prerogatives. Should the disputes be resolved, it is unlikely that armed conflict will erupt in the area. If, however, the countries involved prove unable to settle their differences and begin fighting over other issues, the Arctic could become a site of friction and strife. The Shale Revolution

The introduction of new extractive technologies is transforming the geopolitics of energy in yet another way: by facilitating the extraction of oil and natural gas from shale formations. Unlike the sandstone and other permeable rocks from which hydrocarbons are normally extracted, shale is a dense material that can only be exploited with the application of extreme force. Only recently, with the perfection of fracking techniques, have energy firms been able to exploit shale deposits on a commercial basis. As a result of their efforts, large quantities of oil and gas are being extracted from major shale deposits in the United States, including the Bakken formation in North Dakota, Eagle Ford and Barnett in Texas, and the Marcellus formation in Pennsylvania and New York (Yergin 2011b: 325–341). According to the EIA, these and other such deposits will yield as much as 2.2 million barrels of oil a day in 2030, and 14.2 trillion cubic feet of gas (US EIA 2013a: 148). So far, almost all of the oil and gas being extracted from shale has come from these US deposits. This “shale revolution,” as it has been called, has provided the United States with considerable economic benefits and, in the view of many analysts, geopolitical advantages. The latter stem from the fact that the United States can substantially reduce its reliance on oil imports from the Middle East and other areas of conflict—thereby eliminating the need to support foreign oil providers, as it has in the past, and giving Washington a freer hand in dealing with foreign governments (Yergin 2011b). “Increasing US energy supplies act as a cushion that helps reduce our vulnerability to global supply disruptions and price shocks,” National Security Advisor Tom Donilon declared in April 2013. “It also affords us a stronger hand in pursuing and implementing our international security goals.” As an example of success in this regard, Donilon indicated that increased US output had allowed Washington to impose tough curbs on Iranian oil exports without squeezing global supplies, thus inducing the Iranians to seek a negotiated solution to the dispute over their nuclear activities (Donilon 2013). Increased domestic gas output is also helping spark fresh investment in industries that require large supplies of affordable energy, thus bolstering the US economic position vis-àvis its principal competitors (Morse 2012). Although the United States is likely to remain the principal producer of oil and gas from shale, other countries possess large shale deposits and har-

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bor aspirations of developing them on a large scale. According to the EIA, the largest non-US shale deposits are in China, Argentina, Algeria, Canada, and Mexico (US EIA 2013e: 10). Should these deposits be developed on a scale comparable to that found in the United States, they could confer similar economic and geopolitical investments. For example, China could substantially reduce its reliance on imported energy and thereby reduce its risk of entanglement in foreign disputes and conflicts. Long in the thrall of neighboring energy giants Brazil and Venezuela, Argentina could emerge as a major South American energy supplier. Mexico, which faces a decline in its conventional oil output, could restore its role as a significant producer (US EIA 2013e: 12–15). The development of shale reserves in the United States and other countries could also have significant geopolitical implications for Russia. Presently Russia is the world’s leading supplier of natural gas to Europe and provides a significant share of its imported oil. Moreover, Russia is becoming a major supplier of oil and gas to China, Japan, and other Asian nations. These exports provide a substantial share of Russia’s export income and governmental revenues and have helped to fuel the nation’s drive to restore its status as a major world power (US EIA 2013d; Yergin 2011b: 21–42). However, with the United States expected to begin exporting substantial supplies of gas to Europe and Asia in the form of LNG, Russia could experience a decline in its gas exports to these regions and a corresponding reduction in its geopolitical clout. The boom in US oil and gas production and the consequent effort by Saudi-led OPEC since 2014 to restrain this growth have also resulted in a significant drop in energy prices. This has deprived Moscow of funds needed to sustain its military modernization and support for proRussian separatists in Ukraine and elsewhere. It is still too early to see how all of this will play out, but the topic has aroused great interest in both Russia and its neighbors (Herszhenhorn 2014; Gold and Gilbert 2013). Conclusion

Although much remains uncertain in the realm of energy geopolitics, the underlying factors that govern this phenomenon—the perception that oil and natural gas represent vital commodities whose acquisition constitutes a matter of national security, and the geographic disconnect between major centers of supply and demand—will remain in play. New sources of supply will emerge, and the center of gravity of world oil and gas consumption will shift eastward, toward China and India, but the fundamental dynamic of governmental involvement in the energy trade will persist. As in the past, this involvement will entail the use of military instruments, whether in the

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form of military aid to favored suppliers or the use of force to ensure access to critical supplies. Of the various factors contributing to shifts in the global geopolitics of energy, technology has had an especially powerful impact. Improved technology has allowed not only the extraction of hydrocarbons in regions once considered inaccessible, such as the Arctic and Siberia, but also the exploitation of deep undersea reservoirs. This in turn has extended the space in which geopolitical competition can occur. At the same time, advanced technologies have allowed the exploitation of impermeable shale rock, helping spark a major shift toward reliance on natural gas. Future technological developments will certainly introduce further wrinkles into the geopolitical equation. As long as oil and natural gas provide the majority of the world’s energy supply, however, the basic pattern of geopolitical contestation will persist. The one major development that could significantly alter this equation is a profound shift in consumption patterns from reliance on fossil fuels to large-scale reliance on renewable sources of energy, such as wind, solar, and geothermal power. Greater reliance on renewables will change the game in myriad ways—not least by allowing energy-consuming nations to satisfy a large share of their energy requirements from domestic sources, thereby eliminating the disconnect between supply and demand. Adequate energy supplies will remain vital to healthy economies in this scenario, but because renewable energy can be generated almost anywhere, the procurement of energy will lose its close attachment to national security affairs. Although greater reliance on renewables would largely eliminate dependence on nonrenewable sources of energy such as oil, gas, and uranium, it could produce increased dependence on certain highly specialized materials, such as lithium and rare earth elements, used in advanced batteries, solar panels, and wind turbines. These materials, like oil and gas, exist in relatively limited quantities and are highly concentrated in a handful of locations. Although growing consumption of such materials may not result in the sort of military activities long associated with oil, it could lead to international competition and crisis. In 2010, for example, China—then responsible for about 95 percent of the world’s rare earth element production—cut off the flow of the materials to Japan during a dispute over ownership of contested islands in the East China Sea (Klare 2012a: 152–163). Oil, coal, and natural gas will remain the world’s dominant fuels for some time to come, generating the sort of geopolitical contests described herein. As climate change progresses, however, the transition to renewables is bound to occur, making such competition less likely. Whether this will result in a more stable and peaceful world or whether new forms of energy geopolitics will arise is one of the great questions to be considered in the years to come.

3 Oil’s New Reality Philippe Le Billon and Gavin Bridge

On November 12, 2012, the International Energy Agency (IEA) announced that US oil production would surpass that of Saudi Arabia by 2020, and that by 2030 the United States would be a net oil exporter (IEA 2012a: 1). The headline-grabbing projection was welcomed by the US National Intelligence Council, who saw it as evidence that energy independence was around the corner and would help buffer the shock of China’s economic rise (Shanker 2012). Peak oil may have been a guiding concern at the dawn of the twenty-first century, but a degree of petro-optimism is now back in vogue (Miller and Sorrell 2014). Unconventional reserves—such as bitumen (from tar sands) and tight oil (accessed through hydraulic fracturing, or fracking)—are regarded by some as game changers, with production from these reserves enabled by new applications of drilling technologies, higher prices, environmental deregulation, and a modernization of financial reporting that has redefined what counts as oil reserves.1 A little over 1.6 trillion barrels of oil are now available underground for extraction (US EIA 2016a). With unconventional oil reserves becoming available, liquid hydrocarbon production looks set to plateau rather than peak and rapidly decline. Above ground, the extraction and combustion of oil are firmly embedded in the fabric of modern societies, through the built environment and cultural norms of consumption or military strategy and political patronage. Oil seems set to remain a major source of energy—particularly in the transportation sector—through at least the first half of the twenty-first century. In 2014, oil still represented 33 percent of the world energy mix—ahead of coal at 30 percent and gas at 24 percent—but down from 46 percent in 1973, when the first oil crisis led to sharp reductions in consumption for heating and power generation (British Petroleum [BP] 2015). The new petro-optimism suggests that oil could remain globally the single largest energy type in the foreseeable future. Though the use of natural gas is on the rise, it remains unlikely to supplant oil’s central role in transportation and thus oil’s major economic and military importance. 43

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It is precisely because oil has a future that we need to be concerned. The obsession in peak oil with looming scarcity misdiagnoses the challenge posed by future oil production. The age of plenty may be over but, contra peak oil, the continuation of oil production and consumption—rather than its decline— is the primary socioenvironmental problem. This continuity in turn reflects not only oil’s material qualities as a fuel of choice but the many rigidities and vested interests built through a century of oil dependence. The importance of oil over the twentieth century can hardly be overstated. Oil, writes historian David Painter (2012), “fuelled the American Century.” The United States was the world’s leading oil producer until the 1970s and still houses five of the largest oil companies; along with the Soviet Union, the United States was also the only major power to hold significant oil reserves. Oil control, in turn, helped consolidate US economic and military dominance. A more ambiguous understanding of oil’s centrality to US economic and political life emerged toward the end of the twentieth century as evidence of climate change and the high economic and social costs of military involvement in Iraq (and elsewhere) exposed oil’s strategic, financial, and environmental liabilities. There have been significant increases in US oil (and gas) output since the financial crisis of 2008, however, and oil has regained some of its former gloss as a foundation of national economic power and defining feature of the “American way of life” (Jaffe and Morse 2013; Maugeri 2012). Oil’s lead role in transportation—and its importance to the geographical projection of power—continues to give it a strategic character shared by no other commodity.2 These strategic dimensions, along with massive revenues and high capital intensity, have resulted in powerful actors and vested interests eager to secure their positions in the world. Many governments, but most notably the US, UK, Russian, French, and now Chinese governments, have worked closely with their oil industries (often in response to industry requests) “to gain and maintain control of overseas oil reserves, reflecting a symbiosis of national security interests and the interests of the oil companies” (Painter 2012: 24).3 Recognizing the continuing centrality of oil, we set aside in this chapter the doomster accounts of peak oil and cornucopian projections of an unconventional resource revolution to consider oil as part of a broader global energy dilemma: the problem facing societies that, having developed around and through cheap fossil fuels, continue to struggle to find ways of reducing carbon dioxide emissions and ensuring affordable and reliable sources of energy while also improving the developmental impact of oil for producing countries.4 The legacy of oil’s age of plenty includes declining conventional oil reserves, volatile prices, climate change, and major political and economic distortions in most oil-rich countries. This is the context for what we call oil’s “new reality,” a phrase intended to capture significant shifts in the geological, geopolitical, and geoeconomic context of global oil

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production and consumption. The politics of oil in the Anthropocene period, we argue, involves more than a zero-sum game over a fixed and declining resource—a scramble at the end of the age of plenty for Nature’s unclaimed gifts. Instead, politics after the age of plenty center on changes in the availability, accessibility, affordability, and acceptability of oil (Bridge and Le Billon 2012). We consider the strategies by which states and other parties seek to respond to this new reality and discuss how these strategies might be deployed differently in oil-producing and -consuming countries. The dynamics of competition, conflict, and cooperation associated with oil’s new reality point to the imperative for more effective global oil governance. We highlight four priorities for improving governance of the oil production network (by which we mean the firms, states, and other actors involved in extracting, processing, shipping, and refining oil and consuming oil products). The goal of such governance is to make oil better—that is, to improve the performance of oil’s global production network on economic, social, and environmental criteria. In the longer term, however, the goal is to move beyond oil by decoupling it from society’s demand for energy. Oil’s geological future is characterized by a growing proportion of “hard to get” reserves (such as Arctic, ultra-deepwater, and shale deposits) or lowgrade hydrocarbons such as bitumen (tar sands). This often means lower energy return on energy invested and higher environmental impacts. At the same time, the oil sector is broad and powerful. It is somewhat insulated from consumer pressure, weaker states, and rival energy sources. Actors in the oil sector have never been shy about trying to control supply, boost demand, and promote the primacy of oil. A central issue, then, is how to challenge oil’s political and economic incumbency and the influence it has over oil’s future. It requires addressing the vested interests that seek to maintain “oil as usual” rather than significantly improving oil’s contribution to social, economic, and environmental goals and accelerating transition beyond oil. Evidence of these difficulties is plain to see: from the massive disparity between expenditures on fossil and renewable energies and the repeated failure in the United States to remove oil subsidies in the tax code and establish a carbon tax; to Russia’s jailing of Greenpeace activists seeking to peacefully denounce Arctic oil development (Stewart 2015); and Canada’s rejection of the Kyoto Protocol, self-proclamation as an “energy superpower,” and marshaling of all diplomatic assets on behalf of the private sector. Oil’s New Reality

Over the past 150 years, over a trillion barrels of oil have been extracted from the Earth, over half of it since around 1980. At the same time, global

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oil reserves have grown. Proven world reserves grew by 60 percent between 1992–2012, and by 2014 they stood at a reported 1.65 trillion barrels (BP 2015; US EIA 2016a).5 The clue to this apparent paradox is that reserves (unlike the total planetary resource) are not fixed but are shaped by geological knowledge, technology, political decisions, and the economics of production. As oil companies probe the Earth, they produce oil at the top of the well and new reserves at the bottom. For most of the twentieth century, exploration activity and investment in existing fields “produced” reserves faster than they were recovered, and most of the world’s largest fields—the supergiants that continue to supply today’s demand—were discovered between the 1930s and 1960s. Exploration and technological change continue to yield new reserves but—as suggested by the IEA’s startling projections—there are some significant changes. First, finding new reserves of conventional oil—the type of crude oil that has underpinned twentieth-century growth—is proving increasingly difficult. The future of conventional oil will largely remain in the Middle East, but it is clouded by uncertainties over the real volume of reserves, political factors, and rising domestic oil consumption. Second, the quality of reserves is changing. As the highest-value light crudes are depleted (although see the recent growth in Iraq’s oil output and in North Dakota’s tight light crude), the physical and chemical profile of reserves is shifting toward heavier, poorer-quality oils that are more costly to extract, upgrade, and refine and are associated with more emissions. The growth of unconventional reserves is challenging the primacy of Saudi Arabia in global reserves, with Canada, Venezuela, and Russia holding major reserves in heavy oil and bitumen. The booking of these new reserves by international oil companies (IOCs)—made possible by the modernization of oil and gas reporting on financial markets—is also influencing power relations within the industry. Exxon’s bitumen reserves, accounting for about 30 percent of its total oil reserves, have helped maintain its high share prices, thereby facilitating acquisitions that consolidate its dominant position.6 Third, in the search for new reserves, the frontier of extraction is changing. The move to offshore fields in the Gulf of Mexico, North Sea, and Gulf of Guinea has intensified, with offshore oil rising from 20 percent of total production in 1990 to about 33 percent by 2012 (Ferentinos 2013). These new frontiers include the Arctic, the ultra-deepwater environments offshore (i.e., over 1,500 meters deep), as well as “high-risk” countries with limited state capacity. These unconventional locations are increasingly a feature of the international political economy of oil. Production from ultra-deepwater environments in Brazil and the Gulf of Mexico has been growing over the past decade. The explosion on the Deepwater Horizon drilling rig in 2010, and the subsequent uncapped flow of crude from the Macondo field at around

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1,500 meters below the surface, indicates the risks and challenges of sourcing supply from unconventional environments.7 Techniques such as horizontal drilling and fracking—facilitated by regulation/deregulation of air and water quality and transportation—are enabling access to new reserves of light oil trapped in low-permeability rocks, as illustrated by the tight or shale oil boom in several US states, which has contributed to reducing US crude oil imports from 10 million barrels a day in 2005 to 7 million barrels a day by 2014. For petro-optimists, unconventional is already becoming the new conventional: within less than a decade the United States and Canada are expected to become major oil and gas exporters, thanks to a rather unique combination of geology, politics, and economics fostering growth in unconventional oil output. For petro-optimists this holds the appealing prospect of a new era of stability: “oil without politics” (Jaffe and Morse 2013). The petro-optimism associated with the US oil boom, however, not only needs to be tempered, but more importantly it should not deter efforts to reduce oil consumption, especially in the United States (Yetiv 2015). The new reality of oil also relates to significant shifts in demand. Overlaid on the highly uneven geography of global oil reserves is a different pattern of industrial development and economic growth. The discrepancy between these two different geographies—between where oil is found and where it is required—underpins several significant features of the global political economy of oil. First, geographical imbalances in consumption and production are the basis for international oil trade: three of every five barrels of oil produced is exported and imported, with net outflows of petroleum products from the Middle East, North and West Africa, Latin America, and Russia and net inflows into East Asia, Europe, and the United States. Second, the number of consuming countries is much larger than those holding reserves, so the market power of oil-importing countries is relatively weak, thereby increasing incentives (around the security and price of supply) to look toward alternative energy sources or domestic development of unconventional reserves. Third, oil consumption is declining in many Organisation for Economic Co-operation and Development (OECD) countries but continues to rise at the global scale: non-OECD consumption surpassed that of OECD countries in 2007 for primary energy and in 2013 for oil (see Figure 3.1). As the world economy’s center of gravity shifts away from North America and Europe toward Asia, so market growth—and overall demand—has tilted decisively east. China’s demand for oil outstripped its domestic capacity in 1993 and since then has been a significant importer and an increasingly assertive presence in the search for access to new reserves. Oil consumption in China doubled between 2002 and 2013, and net imports rose from nearly two million to over six million barrels a day— although some imports are tied to China’s growing position in regional

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refining (BP 2013). Fourth, among traditional oil exporters—such as Saudi Arabia—domestic demand for oil is growing in ways that erode exportable surplus: oil consumption in Saudi Arabia rose over 75 percent in the past decade while output increased by less than 30 percent (see also Klare, Chapter 2 in this volume). Fifth, among growing oil importers such as China and India, there is also a shift in the nature of demand, toward the lighter fractions available from refining crude oil that are used as transport fuels (diesel, gasoline, jet fuel) and away from heavier heating oils. Finally, there is growing consideration for the environmental and social acceptability of oil alongside traditional concerns for its availability. Peak demand— rather than supply—is a reality in the OECD countries, whereas in some countries “demand destruction” has been a policy objective as part of broader efforts to decarbonize economies as a response to climate change

Figure 3.1 Primary Energy and Oil Consumption, 1965–2014 (OECD and non-OECD)

Source: British Petroleum (2015).

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and, for some net importers, to improve their balance of trade. Most decarbonization efforts in China and the United States, the two largest emitters, have focused on coal power plants, and there have been only limited initiatives targeting oil (such as incremental improvements in vehicle fuel consumption standards). At the global scale, oil continues to be firmly embedded in current forms of economic growth, and rising world demand has exposed the diminishing availability and accessibility of the so-called conventional oil that has been the bedrock of the industry for most of its 150 years. Efforts to address the shortfall in supply and secure oil in an increasingly competitive market have required accessing unconventional oil (such as bituminous sands and shale oil) or conventional oil in unconventional places, in part because the bulk of the world’s conventional oil reserves are controlled by national oil companies (predominantly in the Middle East). The governments of these countries can therefore theoretically control the rate at which conventional oil is produced, but they have been either unwilling—or unable—to ramp up production (on OPEC’s ineffectiveness, see Colgan 2014). New supply is typically harder to get and of poorer quality, so the supply gap is increasingly being filled by more costly (and often dirtier) oil extracted in riskier operating environments. As firms push into these environments, the long-standing social and environmental challenges of extraction and development are made visible—as with BP’s Deepwater Horizon oil spill, greenhouse gas emissions from tar sands, and wars in Iraq or Sudan (Le Billon and Savage 2016; Watts 2016; Le Billon 2005)—and oil firms are increasingly being called to account for their performance on social development, human rights, and protecting the environment. The historical liability of “carbon majors” also needs to be taken into account. Together, the six largest oil majors—Chevron, ExxonMobil, BP, Shell, ConocoPhillips, and Total—would have produced hydrocarbons accounting for about 13 percent of global anthropogenic greenhouse gas emissions between 1751 and 2010 (Heede 2014). The erosion of surplus that sharply raised prices and reduced affordability in the first decade of the twenty-first century shifted oil from being a commodity (obtainable in the market place) to a strategic good (where market mechanisms alone are insufficient for procuring the resource) and at the same time created additional volatility through scope for speculation. Economic growth in countries such as China, India, and Brazil is indicative of an emergent world political order defined less by the economic and political power of the United States. The growing transnational activity of resource-seeking, state-owned oil firms—such as PetroChina, ONGC, and Petrobras—is a powerful expression of these geoeconomic and geopolitical shifts. Their emergence highlights the decreasing analytical value of the classic distinction

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within work on the international political economy of oil between resourceseeking international oil companies (IOCs) and market-seeking national oil companies (NOCs). Not only are NOCs an increasingly diverse group—for many state-owned firms, the level of state ownership has been reduced over time via public offering with the state retaining a controlling share—but IOCs and the large reserve-holding NOCs increasingly cooperate with each other in developing the more challenging fields. Moreover, a number of NOCs have emerged from Asian economies that are not market-seeking but resourceseeking: firms such as the Korea National Oil Company, ONGC, CNOOC, and PetroChina are state-owned firms but as important as their national ownership is their strategy of transnationalization and their competition with the IOCs for access to resources (see Victor, Hults, and Thurber 2012). The new reality, then, refers to significant shifts in the resource base— and in geoeconomic and geopolitical power. As a result of a prodigious growth in the production and consumption of oil over the course of the twentieth century, the quality of crudes is declining: the oil added to new reserves is generally dirtier (in terms of energy needs, carbon contribution, and local environmental footprint), more costly to extract, and located in environments that push the limits of design and implementation. There are also uncertainties over the size of available reserves, creating concerns that the historic pattern of supply growing to match demand may no longer hold. Against this background, world demand continues to grow, driving prices and speculation about future supplies. Growing domestic demand in major oil-exporting countries suggests that their surplus for export will be increasingly squeezed, while domestic demand in Asia is behind the emergence of new, state-controlled transnational firms seeking resources to supply home markets. The trillion barrels of oil produced to date has not only driven growth and productivity in industrial economies but has contributed to the accumulation of carbon dioxide in the atmosphere, generated water and air pollution, and conspicuously failed to create a basis for social development in many oil-producing economies. Together these changes have exposed a governance deficit around oil. During the twentieth century, oil politics centered on the management of abundance, state power, and market growth. Today the politics of oil are increasingly about the way states, companies, civil society organizations, and consumers negotiate (partial) solutions to this governance deficit and, in so doing, determine the future of oil.8 Responding to the New Reality

Interactions among three broad groups of actors will determine the future of oil: the oil companies that control investment and production decisions, the

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governments of exporting and importing states, and civil society coalitions demanding change and seeking to hold corporations and governments to account. Some progress has been made: OECD-based corporations cannot deduct bribes paid to foreign officials from their taxes, and some companies—such as Chevron and Total—have faced costly settlements with US authorities; tax payments to host governments are becoming more transparent in many countries; denunciations of human rights abuses and environmental impacts have caused project delays or divestments; and fines have been imposed for oil pollution (Le Billon 2011). Yet for all these measures of progress, oil companies have been adept at coopting critics, “constructively” shifting and softening agendas, and lobbying governments (Gillies 2010; Juhasz 2009). For most of the twentieth century, oil companies and governments dominated oil governance processes. There were primarily three issues that defined governance in this period of plenty: market share and prices in conditions of oversupply, security of supply in the face of market failures as a result of adverse geopolitical and natural disaster events, and access to sovereign resources. For the most part, governments and companies engaged international oil governance as a zero-sum game in which access to oil (and oil markets) underpinned economic growth, political clout, and military power. Oil security may be a global affair that no country can single-handedly address, yet nationalist agendas and commercial competition have dominated public policy and markets. Most governments have treated energy policy as a sovereign matter, cooperating only in their self-interest and generally along the lines of core producer or consumer groups. Until the mid-1990s, the international governance system consisted mostly of three relatively small clubs. The first and oldest is the club of IOCs, the “Seven Sisters” or “Big Oil.” Although competitive, these companies do collude and generally have the same industry interests in mind, making it the most cohesive if informal of the three clubs. The second club, OPEC, was founded by Venezuela and Persian Gulf monarchies and nationalist governments to secure fair and stable prices by coordinating their policies and breaking the IOCs’ control over their resources, including by creating their own NOCs. Finally, there is the IEA, the club of rich oil-consuming states founded in response to the 1973 oil crisis. Mostly seeking to ensure oil supplies by actively supporting the production activities of the IOCs and breaking the hold of OPEC through coordination and large supply stocks, the IEA has come to take on a broader role in international energy governance issues.9 If to some extent competitive, both within and between them, these three clubs cooperated to fulfill a rather narrow sense of energy security: oil could pollute and finance dictatorships, but as long as it would flow at a reasonable pace and price, few club members would challenge the system.

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These clubs have now lost part of their relevance due to relatively new and cross-cutting issues, such as sustainability, human rights, development, and climate change. The growing weight of economic players such as China, India, and Brazil questions the relevance of the restricted membership of these institutions. In short, the governance game and its players are changing: demand is shifting from Western OECD members to Asian consumers; NOCs are internationalizing, and many have long sought to emulate and collaborate with IOCs; and different constituencies and ethical priorities are represented, including through the more frequent participation of civil society organizations in negotiations (Citino 2010). One of the major drivers has been the effectiveness of a number of civil society movements and advocacy campaigns that from the early 1990s successfully moved issues such as indigenous rights, environmental protection, or corruption onto the oil governance agenda. Part of that effectiveness relied on broader shifts in the processes and agenda of international governance: the end of the Cold War and the institutionalization of environmental sustainability constituted important watersheds. Other factors have included the mounting scientific evidence on climate change, growing evidence of economic and political challenges of resource dependence, as well as increasing recognition of conventional oil depletion. Companies have responded in different ways. European oil companies have generally been more proactive and progressive in their strategies toward reducing emissions than US companies, in part a reflection of the regulatory and political contexts from which they operate—with, for example, the EU actively pursuing the implementation of the Kyoto Protocol while the United States had not even ratified it (Skjaerseth and Skodvin 2004). In the mid-1990s, BP and Shell, for example, quit the Global Climate Coalition, a US-dominated industry lobby set up in 1989 to advocate against dramatic emission cuts. In a replay of this transatlantic shift, several European companies set up the Oil and Gas Climate Initiative in 2014, without being joined by their US peers (Patel and Blas 2015). Historic experience indicates that societies respond to significant shifts in energy supply and demand in a range of ways. We outline three strategies in response to oil’s new reality (see also Friedrichs 2010): State Responses

• Liberalism: open up national oil reserves to foreign investment, lower barriers to trade in oil (and upstream and downstream oil services) via multilateral treaties on investment and trade, and prioritize markets (over planning and regulation) as a means of allocating access to resources and environment.

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• Statist interventionism: includes securing supply via ownership of “equity oil” and infrastructure, subsidizing oil production and consumption, and reshaping oil control and access through military interventions.

• Adaptation and innovation beyond oil: address supply constraints and climate change through public policies and community initiatives, including institutional and technological innovations that build resilience to market shocks, drive the decarbonization of energy systems, and reduce demand.

This stylized (partial) spectrum of responses suggests some very different potential outcomes. Much is at stake in how states collectively respond to the new realities of oil. We can expect a mix of state-led responses that will vary from country to country, supplemented with corporate and consumer-driven responses. In practice, the (in)actions of oil companies shape oil’s future, whether this involves blocking legislation opposed to their interests, pursuing their own strategies such as moving into unconventionals or going offshore, successfully lobbying to change definitions of what constitute oil reserves, or bolstering their position in electricity markets (in the context of policies that promote decarbonization through the electrification of energy supply) via the control of electrical grid inputs, particularly natural gas. In the United States, the most likely scenario in the short term at the federal level is the current combination of liberalism via trade agreements and deregulation and statist interventions via continued oil production subsidies. Some elements of adaptation and innovation are also present through the funding of alternatives to oil-fueled transportation, including advanced biofuels, but oil subsidies far surpass the amount for renewables (Heubaum 2012). Despite setbacks resulting from high-profile protests against major infrastructure development—such as the Keystone XL pipeline—a productivist ethos characterized by limited regulation predominates, as seen in the rapid development of tight oil (More 2013). East Asia is likely to see a combination of technological innovation (such as electric vehicles), liberalism, and limited socioeconomic adaptation, with the possibility of predatory militarism in the China Seas. China may continue to opt for a “neomercantilist” strategy of bilateral treaties for supply access and multilateral ones for transit. Most low-income countries are likely to turn to socioeconomic adaptation, with some risk of militarism. The new reality of oil creates particular challenges for oil producing countries around price and security of demand, but also around domestic consumption (e.g., Indonesia, and increasingly Iran and Saudi Arabia,

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which could be a net importer by 2037 given current trends). Oil-exporting states also question demand trends given uncertainties arising from fluctuations in economic growth, with OPEC models indicating, for example, a difference of around 18 million barrels a day between high and low economic growth scenarios out to 2035 (OPEC 2012). Technological and policy shifts in the transport sector and, over the longer term, from the prospect of an expansion of carbon legislation beyond Europe add to this uncertainty. Oil exporters also face distinctive challenges on climate change, although OPEC’s position on the historical responsibility of developed economies is clear (Barnett 2007). Beyond investing in enhanced oil recovery to get more oil from aging reservoirs, oil exporters are opening up new fields, increasing strategic partnerships with consumer countries (e.g., downstream deals between Saudi Aramco and PetroChina), and growing the nonoil sector to diversify beyond oil. Producers with strong NOCs are most likely to pursue neomercantilist strategies, protecting access to domestic reserves and limiting foreign investment to oil services. Producers with low-capacity NOCs—such as Kazakhstan and Azerbaijan—are likely to pursue liberal market strategies that continue to see them open to investment in the upstream and downstream sectors. Oil producers are unlikely to leave oil in the soil, forswearing oil production in hope of generating compensatory revenues, especially in light of the collapse of the Yasuni-ITT proposal in Ecuador (Martin 2011). Collectively these different adaptation strategies will reconfigure the geographies of uneven development associated with oil’s global production network. The business of producing oil has become increasingly entangled with broader social issues such as climate change, human rights, and financial speculation. Nongovernmental organizations (NGOs) and some governments are requiring oil companies to account for their contribution to social goals that extend well beyond the business of producing, refining, and marketing oil. The politics of oil, then, also revolves around the relationships between firms and states and entities outside the formal production network and the way these new relationships have begun to transform the identity of core actors. Nowhere is this clearer—and the implications for responsibility and accountability potentially greater—than in the effort by NGOs (and some governments) to reframe the production and consumption of oil as part of the global carbon cycle. The politics of oil in the Anthropocene age are increasingly bound up with the politics of pollution and climate change, as traditional concerns about depletion and energy security become paired Nonstate Responses

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with greenhouse gas emissions and debate over critical threshold concentrations of carbon dioxide in the atmosphere. Global climate change means that carbon abundance—rather than oil scarcity—is emerging as the critical constraint on the oil production network: mobilizing the amount of carbon locked up in proven oil reserves would push the world well beyond the 450 ppm CO2 threshold accepted by the UN Framework Convention on Climate Change as a tipping point for dangerous climate change. Potential emissions from the world’s proven oil reserves are estimated to be around 620 Gt CO2, while the entire carbon budget (including coal and gas) for the period 2011–2050 has been calculated at 565 Gt CO2 if the world is to avoid a 2°C rise in temperature. From this perspective, much of the carbon locked up in proven reserves—and on the balance sheets of publicly listed oil companies—is “unburnable” (McGlade and Ekins 2015; Carbon Tracker Initiative 2011; Stockman 2011). For oil producers, serious efforts to stem the accumulation of atmospheric carbon raise the interesting prospect of them focusing on the “backstream” of hydrocarbon industries (Bridge and Le Billon 2012: 36), becoming stewards of underground carbon stocks rather than extractors of oil. For oil-exporting governments—and companies holding marginal, high-cost reserves—concerted moves toward a low-carbon energy future may leave them holding assets of declining value. Increasingly shareholder value is tied to a company’s performance on environmental and social grounds: the BP Deepwater Horizon explosion, for example, decreased the market valuation of BP by $93 billion within two months. Commercial banks and international financial institutions (IFIs) are becoming more entangled in conflicts over the environmental, developmental, and human rights performance of the oil production network. Many projects demand multibillion-dollar investments that may seem beyond the capacity of even oil majors to finance via the balance sheet. Construction of the Baku-Tbilisi-Ceyhan pipeline, for example, involved fifteen commercial banks, seven export credit guarantee agencies, and three IFIs, which together provided loans worth 70 percent of the $4 billion project cost (Platform n.d.). Yet given the vast revenues generated from exploitation, securing funding from a wide array of institutions, especially export credit agencies and IFIs—as well as other oil companies through development consortiums—is also about spreading risk and leveraging the political and economic influence of these partners to ensure projects get completed. Prominent other examples include World Bank backing for Exxon’s Chad-Cameroon pipeline (Pegg 2009). The business opportunities presented by new oil projects have exposed banks to significant criticism from environmental and human rights groups. Faced with growing accusations of complicity in human rights abuses, oil

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and mining companies worked in the early 2000s with human rights NGOs and the US and UK governments to curb abuses by security forces protecting extractive ventures by defining good practices through the Voluntary Principles on Security and Human Rights. IFIs such as the World Bank and the European Bank for Reconstruction and Development (EBRD) have adopted procedures for assessing the environmental and social impact of project financing. A growing number of commercial banks have adopted the Equator Principles, which, like the IFI procedures, require an evaluation and benchmarking of environmental and social impacts. The development of these environmental and social standards by banks has provided NGOs with a degree of leverage over oil development projects that they may not have via national political channels or the oil companies. A sustained campaign by environmental groups over the social, environmental, and development impacts of Shell’s Sakhalin-II project in Russia, for example, targeted a loan decision by the EBRD as a way to influence aspects of project development (Bradshaw 2005). Funded by state banks and without making recourse to IFIs, NOC investments typically lack an analogous point of leverage for NGOs. Four Priorities for Governing Oil

The new reality of oil sets four main priorities for oil governance: reducing price volatility, matching oil supply and demand, transitioning to lowcarbon energy sources, and addressing the “oil curse.” The order of these priorities and their potential impacts will vary for different countries and social groups over time. High-priority measures should include those tasks that can be rapidly achieved and those that have longer-term effects. Chief among these is reducing the stock of inefficient vehicles and promoting low-hydrocarbon forms of transportation. Prioritization also needs to consider equity dimensions: similar efforts cannot be demanded from poor countries as from rich ones. Reducing rural poverty remains a priority for many countries, and hydrocarbon-based rural transportation has an important role to play here. Finally, it is about rethinking the role of hydrocarbons—and expectations for energy services as a whole—within society (on the US case, see Lovins 2011). Oil prices are volatile, yet these price variations can be tempered. For much of the 1990s, oil prices remained within the range of $22–28 per barrel, partly the result (some argue) of a deliberate policy of price stabilization Reducing Price Volatility

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within a “reasonable” target price zone by OPEC (Slaibi, Chapman, and Daouk 2010). Yet such views often overinflate OPEC’s role (see Colgan 2014), while policies can only work if there is spare capacity to meet supply disruptions or rapid demand growth, if the US dollar holds its value, and if speculators do not dominate financial markets. This proved not to be the case from 2001, when OPEC tightened supplies, Asian demand boomed, the US dollar declined against gold and the euro, and speculators held a growing share of oil futures positions. Price volatility flared most acutely during 2008–2009 when prices reached $147/barrel in July 2008, before plunging to $33 within six months, rebounding to $113 by March 2011, declining to $26 by January 2016, before regaining ground to $55 a year later. Fear of future turbulence—and its economic and political consequences—has again become a major feature of oil markets (Le Billon and Cervantes 2009). These conditions have led many governments to look into preventive measures. Heads of state at the G-20 summit in 2009 committed to improving transparency in energy markets, reinforcing producer-consumer consultation, and strengthening market supervision—notably to reduce speculation (Chevalier 2010). Key actors in the industry generally want to see prices remain high: investments in unconventional oil extraction require an historically high price environment to ensure their commercial viability, while many oilexporting countries (such as Russia, Nigeria, and Venezuela) require high prices to sustain their oil-dependent budget. The 50 percent fall in the price of oil in the second half of 2014 exposed the financial weaknesses of highcost unconventional oil projects and highlighted familiar tensions among OPEC members with differential abilities to weather a period of low oil prices (according to their relative production costs, economic diversification, and financial reserves). This price volatility should be reduced by greater market transparency and coordination and through oil revenue– smoothing instruments enabling countercyclical policies among producers (Ossowski 2013). A fuel subsidy and taxation system that reduces shocks for consumers and public treasuries while progressively reducing demand is also warranted. With major supply constraints in the conventional oil sector and the rapid demographic growth of new oil consumers, energy security will require matching demand to supply through a mix of demand destruction—whether as a result of prolonged economic recession, high market prices, increased fuel taxes, or government quota—and new sources of supply. To keep pace with demand, an estimated $15 trillion in investment is required in upstream Matching Oil Demand and Supply

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oil and gas for the period up to 2035 (IEA 2012a). Mobilizing this financing is difficult, not only because of its sheer size and the relative uncertainty of exploration and oil prices but also because of the pattern of reserve control. Most reserves are under the control of national governments eager to increase revenues through price rather than volume, and some of the NOCs dominating the supply market face tighter capital access than do IOCs. This can be addressed by fostering greater NOC–IOC collaboration and facilitating NOCs’ access to capital markets. As discussed shortly, a set of constraints and incentives could also help redirect some of these investments into reducing demand and shifting to alternative fuels. Oil consumption subsidies in producer countries—valued at $523 billion in 2011—inflate demand, and their reduction is a primary goal of the IEA, while additional subsidies to fossil fuel production could bring the total to about $1 trillion a year (OCI 2012). Given the unwillingness of many oil producers to move in that direction, a strong measure likely to face much resistance from the oil industry is to increase the taxation of oil companies while capping prices. Another, possibly more painful approach is to increase fuel taxes at the consumer level and redirect revenues toward the reduction of demand. Production increases also face environmental and other regulatory constraints on access, which have come under criticism from all but progressive reformers—especially in the United States. Opening up many of these remaining reserves would have a mostly short-term positive effect on oil availability (and to a lesser extent on affordability) while entailing major social and environmental costs. To reduce demand, higher fuel efficiency and fuel taxes are needed. Fuel efficiency can be improved on conventional vehicles through more efficient engines and power trains (e.g., turbocharged gas, diesel, hybrid electric-gasoline), better transmissions (e.g., continuously variable transmissions), improved aerodynamics and rolling resistance, lower weight, and smaller size. Fuel efficiency alone, however, will only buy limited time as the number of vehicles increases. Greater efficiency can result from a shift to more efficient modes of transportation, such as mass transit. Each additional mile of public transport use can save three to seven passenger miles in a car, due to more direct travel routes (think bus lanes), trip chaining, ownership of fewer cars per household, and an increased preference for higher density residential areas. Fuel tax remains the single most effective solution, but it has proven to be a politically challenging objective in the United States, where low taxation and individual mobility remain strong values. In the meantime, China is seeking to avoid the US pathway to oil dependence by progressively increasing fuel taxes, mandating stricter fuel efficiency, and promoting electric vehicles; yet China also has massive

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asphalt roads programs and the world’s largest car market. A long-term priority is to shift away from fossil fuels and reduce transportation needs through improved urban planning, cultural change, and a relocalization of some production processes. Whereas oil-related governance was mostly about controlling oil prices and supplies, it is now also about decarbonizing oil and moving to alternative energies. Decarbonizing oil is a major challenge. Current carbon capture technologies cannot be applied to mobile sources, and decarbonizing vehicle emissions requires new technologies that are still in their infancy. Fuel alternatives include natural gas, biofuels, and hydrogen as well as electricity. Natural gas can substitute for gasoline and is already available in many countries as a transportation fuel and to upgrade unconventional oil, such as Alberta’s bitumen. Oil majors have taken rhetorical and practical steps to promote and benefit from a supposedly greener energy future fueled by natural gas. Following acquisitions and project development, many oil majors (including Shell and Total) are now producing more gas than oil. Their main target is coal and its dominance in electricity generation, where there are opportunities for gas to substitute. Casting natural gas as a cleaner alternative, Shell’s CEO argued that it was absolutely key to “shift coal out of power generation and move gas in,” while the CEO of French oil company Total bluntly declared that coal was “the enemy” (Katakey and Patel 2015). Natural gas is supposedly only half as “dirty” as coal, but much of it is now coming from hydraulic fracturing and involves energy-intensive liquefaction for its transportation, and leaky gas plants can produce “greater near-term warming than coal plants” (Zhang, Myhrvold, and Caldeira 2014). Meanwhile coal producers and users are seeking with mixed results to reduce particulates and improve emission capture to pre-empt carbon pricing from reducing coal’s share of the electricity market (Urbina 2016). Biofuels are often presented as an environmentally friendly alternative to fossil fuels. Yet current modes of production are fossil fuel–intensive (e.g., agricultural use of diesel), while the production of biofuels on cleared land releases between 17 and 420 times more greenhouse gases than they save compared with gasoline. Furthermore, first-generation biofuels, such as ethanol from corn, place major pressure on water, farmland, and food production (Borras, McMichael, and Scoones 2010). Second-generation biofuels, including crop residues and wood by-products, offer a more viable option but remain difficult to process, and their allocation to fuel undermines their contribution to soil quality (Fargione et al. 2008). Hydrogen is by far the cleanest liquid fuel at the point of use because it only emits water Decarbonizing Transportation

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vapor, but like electricity, it is only an energy carrier that requires primary energy inputs. Hydrogen vehicles are less efficient than electric vehicles, and outside of Toyota’s commitment to them, the limited efforts put into developing hydrogen highways seem to be losing steam. Clean forms of energy on a level equivalent to the 95 million barrels of oil equivalents per day (MBOED) consumed around the world are hard to come by. Hydrocarbons could provide a clean energy source under conditions where concentrated production facilitates carbon capture and where a nonemitting energy carrier—hydrogen or electric battery—is used at the point of consumption. Surplus sources of energy are limited but include idle electricity during off-peak periods. Global hydropower output represents only about 10 MBOED, nuclear power half that, and wind and solar are currently negligible. Geothermal energy could provide a long-term option due to continuous baseload power, minimal visual impacts, and a small environmental footprint. Current geothermal systems, however, release greenhouse gases sequestered in reservoirs. Tax reforms that shift subsidies and profits from fossil fuels to the development and rollout of cleaner fuels are needed to accelerate this transition. Divestment from fossil fuels can also play a role in sending clear financial signals from shareholders. In September 2014, the Rockefeller Family Fund (built on oil) announced that it was divesting from fossil fuels, starting with stocks in coal and tar sands (Schwartz 2014). Another 180 institutions representing about $50 billion in assets have pledged to divest from fossil fuels. Yet many have resisted such moves, including universities—with Harvard’s president declaring that its $36 billion endowment “is a resource, not an instrument to impel social or political change” (Madery 2014). Ironically, early divestiture may have proven financially wise, given the fall of fossil stocks due to oversupply since the last quarter of 2014. One of the main obstacles to shifting beyond petroleum is that many people are stuck with existing oil infrastructures, resulting in part from widely spread suburban housing, nonresidential downtown areas, and lack of (nonoil) public transportation. Low-density suburban housing makes residents vulnerable to oil price hikes. Beyond city planning and transportation policies, a number of social movements have emerged to build “post–cheap oil” alternative communities, lifestyles, and livelihoods such as transition towns, which seek to foster local civil society innovation to reduce oil dependence (Newman, Beatley, and Boyer 2009), while the move to a bio-based economy faces major challenges (Langeveld, Sanders, and Meeusen 2012). There is little doubt that oil will be around for decades, and expectations are that prices will remain high by historical standards, although volatile. It is Preventing the Oil Curse

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thus crucial to mitigate the negative environmental and social impacts of oil extraction and ensure that producing countries escape the resource curse so that the next few decades of wealth transfer are not wasted. Addressing the resource curse will help reduce supply and transit disruptions resulting from domestic unrest and outright conflict and from sanctions imposed by mostly Western countries against so-called rogue regimes—as seen in the past against Iran, Iraq, and Libya, and more recently against Russia through a ban on collaboration over oil exploration and production in the Arctic (Panin 2014). It should also help prepare producing countries for a post-oil context by diversifying their economies and opening their political institutions to attenuate the shocks of revenue decline. Finally, tackling the resource curse can improve development outcomes and prevent disruptions in oil production and volatility in prices: higher levels of corruption reduce production while political instability and economic sanctions slow down field development and reduce supplies, as demonstrated in Iraq, Iran, Libya, and Nigeria (Le Billon 2013). The resource curse is not a given, and the quality of institutions and soundness of policies matter a great deal to outcomes (Ross 2012). There is now a better understanding of processes at work and greater awareness within producing countries (around improving macroeconomic management in particular). Though far from sufficient, some momentum has built over the past decade through initiatives such as the Extractive Industries Transparency Initiative; the Natural Resource Charter, which defines best practices along the value chain; numerous aid programs, such as Norway’s Oil for Development; tighter controls on corruption; and greater attention to illicit financial flows, including tax evasion by oil companies (Le Billon 2011).10 In the area of prospecting and award licensing, publicly funded prospecting can help governments better assess the value of what they are making available to companies. NOCs have a role to play—notably to ensure domestic technical knowhow and higher returns—yet like IOCs also require robust regulation to maximize returns. Public bidding of oil blocks is a must to ensure that returns are maximized through open competition and corruption risk is minimized through transparent procedures involving little discretionary power. Operations need to be properly regulated, with environmental and social impact prevention and mitigation mechanisms to avoid conflicts with local communities and strict metering and cost monitoring to prepare for taxation. Tax collection needs to be based on competent evaluation, with independent verification of company payments and government receipts. Auditing all along the revenue flow is crucial, especially with regard to transfer mispricing on the tax collection side and embezzlement by officials on the expenditure side. Finally, revenues must balance allocations to savings, current expenditures, and long-term investments—

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with spending prioritizing sustainability, poverty alleviation, and long-term growth outside of the non-renewable resource sector (Humphreys, Sachs, and Stiglitz 2007). Conclusion

Our account has sought to capture the emergence of a new reality of oil at the end of the age of plenty. In doing so, we have pointed at an apparently intractable challenge: that efforts to sustain supply in the face of rising demand will further exacerbate the economic, social, and environmental ills associated with capturing, producing, and consuming oil. There is then, we conclude, a critical problem of governance for oil in the Anthropocene age. The world lacks an effective platform to negotiate long-term energy issues. The two main institutions, OPEC and IEA, remain largely hampered by their role as producer and consumer clubs, and emergent structures such as the International Energy Forum and the International Renewable Energy Agency are also closely tied to producer roots. There are a number of ad hoc initiatives on key issues, such as revenue transparency or deep decarbonization, but fragmented approaches face a risk of long-term failure when poorly institutionalized and not backed by a broad social movement.11 In the short to medium term, the challenge is to make oil better—that is, improve oil’s capacity to deliver social development, disable its links to militarism and violence, accelerate the decoupling of oil from carbon dioxide emissions, and find ways to organize oil along fairer, more ethical lines. Making oil better might seem a modest proposition: it is nothing of the sort. It recognizes that oil now consistently underperforms on broad social objectives and that ultimately a firm or industry’s license to operate should be conditional on its contribution to social goals. In the longer term, the task is to find ways to move beyond oil. This will involve action now to accelerate oil’s exit from the transportation sector of the economy and curb energy demand. Redefining oil’s role starts with slowing down the growth of unconventional oil development while maintaining high oil prices, preferably through taxation—a direction of travel that contrasts with US experience. Given the proliferation of oil throughout modern life, policies to disembed it will have broad range and reach, including policies on urban design, funding public transportation, economic restructuring of oil-exporting countries, and allocation and pricing of carbon. Strategically, the choice between better oil and beyond oil is a false one. First, pursuing better oil needs not undermine a move beyond oil. A desirable shift to alternative fuels entails a broader transition toward more affordable sources of energy and modes of transportation, as well as

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lower-carbon and more socially just economies. Second, the most likely geopolitical scenario is that some countries will continue to take an early and precautionary path to post-oil transitions, whereas others—limited by their economic capacity or political ability to affect such a shift—will remain at the mercy of a declining and problematic resource. The great transition, in other words, may be instead a great divergence between the oil-free and the oil-fueled. This divergence will notably be played out through energy companies, with some actively pursuing alternative energy paths, while others such as Exxon sticking to hydrocarbons. A partial transition will remove some of the supply constraint for oil-fueled countries, but it will also risk taking some of the pressure off from oil consumers and producers to actually improve oil’s problematic impacts. The most progressive countries should thus not jettison oil—and their interest in better oil—too soon because their contribution could make a difference. Last but not least, many poor countries and communities will de facto move beyond oil: not as a result of ethical choices, but simply because they will be priced out over the long term. Given the stark environmental and political realities of oil, there is a clear need to make oil better and to accelerate a transition beyond oil. Notes

1. Most noticeably, the US Securities and Exchange Commission reclassified bitumen, for example, as oil. http://www.sec.gov/rules/final/2008/33-8995.pdf. About 32 percent of ExxonMobil’s proven oil reserves and 40 percent of Shell’s consisted of bitumen and synthetic oil. http://www.exxonmobil.com//Corporate/Files/news_pub _ir_finstmts2012.pdf; http://reports.shell.com/annual-report/2012/businessreview /upstream/reserves.php. 2. Uranium comes second given its military uses, but its economic importance is much lower. Gas and coal are much less important, and most minerals can be traded, stocked, or substituted. 3. On the United States, see Painter (2012: 24); on the United Kingdom, see for example Jones (1977); on France, see Feigenbaum (1985) and Yates (2009); on China, see Harrison (1977) and Power, Mohan, and Tan-Mullins (2012). 4. For a broader account of global energy dilemmas, see Bradshaw (2013). 5. Proven reserves were 1,039,300 million barrels at the end of 1992 and 1,668,900 million at the end of 2012. The latter figure includes estimates for tar sands and liquid fractions associated with gas production (condensates and natural gas liquids) as well as crude oil (BP 2013). 6. Through a US$31 billion stock swap deal with XTO, a gas fracking company, Exxon became the biggest US producer of natural gas (Gold 2009). 7. The Lac-Mégantic (Quebec) train disaster in 2013—in which seventy-two oil tank cars traveling from the Bakken tight oil fields in North Dakota to an oil refinery in New Brunswick caught fire and derailed in the center of town, killing more than forty people—highlighted the dramatic rise in oil movements by rail associated with the US oil boom and the deregulation of rail transport.

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8. The most well-known example is the creation of the Extractive Industries Transparency Initiative (EITI), which saw, for example, Exxon try hard to get Equatorial Guinea to be seen as a credible participant in this revenue transparency regime. Civil society organizations denounced the lack of local accountability mechanisms in Equatorial Guinea, the government of which was expelled from the regime while Exxon has continued oil exploitation in the country. 9. The IEA has been described as rather ineffective beyond information collection and publication: for an analysis of the inception of the IEA in the broader context of the oil crisis and US dollar recycling, see Spiro (1999). 10. By 2015, EITI had thirty-one compliant countries, not including Angola and other countries of initial concern. EITI’s reliance on voluntary participation by governments and on effective civil society organizations to bring about accountability over misused oil revenues, for example, does not address the relative weakness of such organizations in authoritarian oil-rich states—hence the need for a global mandatory disclosure mechanism. 11. The need for public pressure is well described in the case of the Keystone XL pipeline by Lizza (2013). For example, the three common pillars of deep decarbonization are energy efficiency and conservation, low-carbon electricity, and fuel switching (Guérin, Mas, and Waisman 2014).

4 Oil Elites and Transnational Alliances Naná de Graaff

The energy industry is in continuous transition, which in this volume is characterized as a balancing act between natural resource scarcity and plenty. Shifts in patterns of production and consumption, forces of demand and supply, fluctuating prices, developments in technology, geopolitical factors, and historical legacies influence this balance. These factors can be seen as generating a world of relative plenty, determined by technological developments and characterized by an interdependent, cooperative, and positive-sum energy world (Yergin 2006; Nye 2005; Keohane and Nye 1997) or leading to a world of increasing scarcity, marked by increased zero-sum interstate and intrastate resource conflicts (Klare 2001, 2004, 2012a). The introductory chapters of this volume have outlined different sides in this debate. This chapter draws attention to the organization of scarcity and plenty by analyzing corporate power structures of the global oil and gas industry in light of a broader ongoing shift in the center of gravity toward the non–Organisation for Economic Co-operation and Development (OECD) world. In particular, this chapter investigates how the global expansion of national oil companies (NOCs) from non-OECD countries has affected corporate alliances and oil elite networks at the top of the industry. The major proponents of those rising non-OECD NOCs have been branded the “new Seven Sisters” (Hoyos 2007a, 2007b), a label that refers back to the socalled Seven Sisters, the cartel of mainly Anglo-American private oil majors that dominated the global oil order during the first half of the twentieth century. This label is not entirely correct because the new Seven Sisters in no comparable way resemble a cartel or seek to control prices (or sector dominance) similar to the old Seven Sisters. They do, however, control about a third of the world’s oil and gas production and more than a third of its oil and gas reserves, and some industry experts claim that they are the new “rule makers” (Hoyos 2007a).1 The label thus conveys the perception that stateowned NOCs with a non-OECD origin have become challengers to the inter65

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national oil companies (IOCs) and might threaten their interests and business model (Vivoda 2009; see also Jaffe 2007; Victor, Hults, and Thurber 2012). This perception forms the starting point of this chapter. Based on a newly constructed panel database, the chapter shows that major non-OECD NOCs have indeed expanded their reach, activities, and investments significantly in the past decades (i.e., since the mid-1990s). At the same time, this outward expansion and the concomitant transnationalization of non-OECD NOCs has been carried out in cooperation with IOCs through the formation of hybrid corporate alliances—such as joint ventures—thereby allowing the NOCs to integrate within the core of the global energy market. This development points to an energy world in which non-Western NOCs—such as Gazprom and China National Petroleum Corporation (CNPC)—are not so much rivals to private Western oil companies such as ExxonMobil, BP, and Shell, or that the new Seven Sisters are “taking over” (Odell 2006), but that they are becoming regular competitors, just like other IOCs, with increasingly joined interests and interdependencies and a less zero-sum distribution of power between them (De Graaff 2011, 2013). However, as the chapter will subsequently show, such cooperation and integration is hardly found at the level of the directors of NOCs and IOCs (i.e., those that direct and guide the strategies and interests of these oil majors). A social network analysis of the directors of the world’s largest oil companies—and their ties to other firms and to the state—shows that there is a lack of integration of non-OECD oil elites within the corporate elite networks that are typical of and prevalent among OECD corporate directors more generally and in which the IOC directors were indeed closely embedded. With this particular focus on directors and elite power structures, the study builds further on an extensive literature on how directors of major transnational corporations (TNCs) form both national and transnational corporate networks by sitting on multiple boards simultaneously (Heemskerk 2013; Domhoff 2009 [1967]; Kentor and Jang 2004; Dooley 1969), as well as being affiliated to a network of corporate planning and policy planning bodies such as think tanks, business associations, and elite planning clubs such as the Bilderberg Group (Van Apeldoorn and De Graaff 2014; Carroll and Carson 2003). These networks and venues are crucial for forming long-term business strategies and creating shared values, trust, and more general corporate interests that stretch beyond the interests of individual firms (Carroll 2010; Van Apeldoorn 2002). The finding that non-Western NOC directors are hardly integrated into this business community means that they have little

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access to the social platforms where elite consensus on the rules of the game is reached. The lack of integration at this level arguably contributes to the perception that non-OECD NOCs are threatening market competition. This relates to a fundamental remaining difference between IOCs and NOCs, which is that although the NOCs are internationalizing and in their foreign operations and activities are behaving more IOC-like—with similar responsibilities and facing similar constraints—they remain tightly linked to the state and the responsibilities that come with this role. This duality is reinforced by the NOC directors, which are much more extensively and directly affiliated with their governments through personal ties than is the case with the IOC directors. NOC directors thus have to balance between the “two faces” they have to keep up of being competent managers on one hand and loyal statesmen on the other. This distinctive dual role of the nonWestern NOCs and their directors will be illustrated by the case of Chinese NOCs (De Graaff 2014). The outward expansion of non-OECD NOCs is a manifestation of a much broader development in the global political economy: the rise of nonOECD powers more generally. The exponential economic growth in countries outside the OECD core—China in particular—is creating a shift in the center of gravity of economic power, pushing non-OECD investment and firms abroad and directly affecting patterns of energy consumption and production. The next section provides a sketch of the longer-term change in geographical patterns of energy consumption and production, reserves ownership, and refining capacity, which forms an essential context for the rise of non-OECD NOCs of the past decades. The third and main section focuses on the power structures at the top of the industry. This section presents the main results of a mapping of the changing corporate networks of major nonOECD NOCs and their interorganizational ties (De Graaff 2011) and of the configuration of the interpersonal ties (social networks) of the world’s largest NOCs’ and IOCs’ directors (De Graaff 2012a). Finally, these findings are elaborated by looking more specifically at the case of Chinese NOCs. In the concluding section I summarize the findings and reflect on the implications of these changing power structures at the top of the oil industry. Shifting Patterns in World Energy Consumption and Production

As is now widely established, we are currently witnessing a major shift in power in the global political economy, due to the so-called emerging economies—particularly with powerhouse China constituting such a new

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economic growth pole outside the OECD core (World Bank 2011). Intimately related to this shift are the changing patterns of energy production and consumption in which there has been a long-term shift in the respective share of the OECD and the non-OECD world in terms of primary energy production and consumption of hydrocarbons (oil, gas, and coal). The most remarkable aspect of this shift is that the share of consumption of energy in the non-OECD world has surpassed the OECD world in 2008 (BP 2015). The International Energy Agency (IEA) projects that in the next twenty-five years, 90 percent of the projected growth in global energy use will come from the non-OECD economies (IEA 2011a). It should be noted that China in particular is the major driver of this trend, with its exponential growth in energy consumption; in 2009, China surpassed the United States to become the world’s number one energy consumer (BP 2015). Growth in energy consumption of non-OECD countries is both an indicator and a driver of rising influence of non-OECD players. Another key indicator for the distribution of power is the ownership of reserves. The most fundamental shift in that respect took place with the nationalizations of the 1970s (Stevens 2008; Parra 2004; Yergin 1991; Rodman 1988), when most major non-OECD resource holders took hold of their subsoil riches. Yet we do observe a widening gap between OECD and non-OECD countries in terms of (proven) oil and gas reserves (Figure 4.1), largely due to an (exponential) increase on the part of the non-OECD members.2 The lead that resource rich non-OECD countries have upstream in terms of ownership of reserves gives them influence and control over access to these reserves and is often seen as a major advantage for the NOCs from such resource-holding countries. However, it should be emphasized that this power is circumscribed by the need for investment, technology, and markets. To the extent that non-OECD NOCs cannot provide these themselves, they remain dependent on IOCs to reap the wealth that their subsurface holds (Labban 2008; Parra 2004). This is also illustrated by developments in the shale industry, where IOC involvements and investments are required in many potentially shalerich non-OECD countries. A telling example here is Argentina, where in 2012 President Cristina Fernández de Kirchner sent shock waves across corporate boards by nationalizing Argentina’s major oil company, YPF, thereby expelling Spanish Repsol. After a little more than a year, the Argentine government announced that it had agreed on a major joint venture between YPF and a different foreign oil giant, Chevron, which it needs for expertise and investments to exploit its vast potential shale oil and gas reserves, particularly in the so-called Vaca Muerta field (Economist 2013a).

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Figure 4.1 Proven Oil and Gas Reserves, 1980 and 2014 (OECD and non-OECD) (&!!" (&!!"!# !#

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Although IOCs still have an advantage over NOCs in that respect, an increasingly important role upstream is played by international oil service companies, such as Halliburton and Schlumberger, which can provide needed technology and know-how. Most of these oil field service companies originate from the OECD, predominantly the United States. Although these firms potentially make NOCs less dependent on IOCs, their presence also indicates a lack of autonomy on the part of non-OECD NOCs. In addition, producers’ capabilities and power of access to—and control of— reserves are greatly influenced by price and market conditions (De Graaff 2013) and on how, for instance, the oil futures market is placed at the heart of the current oil-pricing regime (Fattouh 2006: 68–69). However, in the downstream sector a notable shift is taking place. Since 2010, the nonOECD part of the world has surpassed the OECD countries in terms of their refining capacity (BP 2015). China in particular has exponentially increased its refining capacity. This shows that, collectively, the non-OECD countries—in addition to the advantage they have established in the upstream part of the hydrocarbon sector since the 1970s—are increasingly expanding into the downstream sector. While some major non-OECD producers and their NOCs have been improving their downstream capacity for decades (Levy 1982), the extent of their growing share in refining—and the fact that they have surpassed the OECD countries in this respect—is a significant indication of non-OECD countries’ growing clout (De Sá 2012). Downstream integration has also been described as a strategy that non-OECD resource seekers use to strengthen their relationships with major producers. China’s investments and joint ventures with major producers around the world—most notably

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with Saudi Arabia—have been highlighted in this respect (Al-Tamimi 2014; Jiang and Sinton 2011). The development of world-class refining facilities in partnership with OPEC suppliers is seen by some commentators as a long-term strategy to cement their relationship with these suppliers (Hu 2012; Meyer 2010; Calabrese 2009; Alterman and Garver 2008). Although in due time this might imply a replacement of the special relationship between the United States and those countries, it must be noted that the dominant position of the United States in terms of its military protection and control over worldwide oil flows is as yet unchallenged. This is a geopolitical reality the Chinese are well aware of, and it is part of their socalled Malacca Dilemma—the fact that over 80 percent of China’s energy imports pass through the Malacca Straits and waters patrolled by US and Southeast Asian navy vessels (Zhang 2011), one of the reasons for their growing assertiveness in the South China Sea and the Maritime Silk Road that is part of the recently launched One Belt, One Road initiative. The foregoing has briefly sketched the context of shifting geographical patterns of energy production, consumption, reserves ownership, and refining, showing a gradual shift in which non-OECD countries account for an increasingly greater share, particularly because of the exponential rise of the new economic growth poles in Asia. Next, we will see if and how these aggregate developments are mirrored in the corporate organization and business elite community structures at the commanding heights of the industry. Corporate Elite Networks in the Global Oil Industry

This section focuses on the power structure at the top of the oil and gas industry and the way it has been affected by the rise of non-OECD NOCs. This will be done in a twofold manner: first by presenting the main results of a longitudinal analysis of the world’s five largest state-owned oil companies and their changing corporate networks, and second through social network analysis of the corporate elite networks in which these oil companies’ directors are embedded. This approach can be placed within a scholarly tradition called power structure research, which analyzes elite formation and sees the unequal distribution of resources (e.g., wealth, political office, corporate control) as a base for power that is concentrated and institutionalized through formal and informal social networks (Van Apeldoorn and De Graaff 2014; Heemskerk 2013; Burris 2012; Carroll 2010; Domhoff 2009 [1967]). Such corporate and political elite networks are established through the commer-

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cial relations of firms (i.e., investments, joint ventures, strategic alliances). But also, importantly, they are consolidated through the professional and personal networks of directors of the firms linking them to a wider social context (e.g., other firms, policy planning networks, and the state). These professional and personal networks form crucial channels for trust building, the coordination of business interests, and the creation of a common worldview (Carroll 2010). Firms and elites from emerging economies have hitherto remained off the radar of this scholarly tradition. This study provides a first step for exploring and assessing their growing influence in the oil sector. In the last part of this section, the broader findings and implications of the patterns in these corporate elite networks are elaborated and illustrated by way of a more in-depth analysis of the Chinese globalizing NOCs. Chinese NOCs represent a new breed of non-OECD NOCs because they are primarily resource seeking, rather than resource holding, which is the traditional role of NOCs. Moreover, Chinese NOCs, originating in the world’s largest user of energy and arguably the most important challenger of AngloAmerican dominance, can be viewed as a primary example of non-OECD NOC competitors. The analyses are based on a new data set of oil companies’ interorganizational networks and their directors’ interpersonal networks and make use of the method of social network analysis (SNA). SNA as a method is particularly useful for identifying and visualizing relations between actors or units and helps interpret and analyze patterns in these relations (see Scott and Carrington 2011; Wasserman and Faust 1994; Scott 1991). Thereby it reveals interdependencies and shared attributes of actors, instead of merely comparing their individual attributes. As Carroll writes, SNA enables: “a cartography of social space that moves beyond the impressionistic and anecdotal . . . [b]y examining the actual relations that link persons and / or organizations into specific configurations of social structure” (Carroll 2010: 11). As a proxy for the top of the energy industry, I have taken the rankings of the Petroleum Intelligence Weekly (PIW). The PIW annual ranking is widely recognized and based on operational data from more than 130 firms. It uses several distinct rankings—such as proven reserves, production, refinery capacity, and product sales volumes—which are then added together to determine a cumulative, overall position of the firm. For the more in-depth analyses I focused on the top of the PIW top fifty ranking. The selected companies are: Saudi Aramco (100 percent state-owned, Saudi Arabia), National Iranian Oil Company (100 percent state-owned, Iran), ExxonMobil (US, IOC), Petróleos de Venezuela (PDVSA) (100 per-

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cent state-owned, Venezuela), CNPC/PetroChina (100 percent stateowned, China), Gazprom (50 percent state-owned, Russia), British Petroleum (BP) (UK, IOC), Royal Dutch Shell (Netherlands/UK, IOC), Chevron (US, IOC), and Total (France, IOC). This selection of companies generated a total of 182 directors—94 IOC and 88 NOC—in 2007. For each individual company and director, a complete mapping was made of their relevant affiliations. For company directors this mapping included, for example, corporate directorships, political affiliations, and affiliations with policy planning organizations. For the companies selected for this study (concentrating on five major NOCs), this entailed a mapping of all corporate affiliations (e.g., joint ventures, subsidiaries, strategic alliances, equity investments, and service contracts abroad) as well as operations involving foreign partners domestically. Because the analysis of the corporate networks of the non-OECD NOCs aims at capturing a change, a comparison was made between the networks in 1997 and 2007. For the oil elite networks, no such comparison was made because very little integration was found in 2007, and it could hardly be expected to have been a more integrated network a decade earlier. Data were collected from, for example, annual reports of the companies, biographies and CVs of directors, websites (corporate and institutional), and existing databases such as Hoover’s company database, Orbis (Burea van Dijk), and Business Week. The software programs Ucinet and Netdraw (Borgatti, Everett, and Freeman 2002) were used to conduct the network analyses. The results are described next. The rise and expansion of non-OECD NOCs has been seen by some analysts as a threat to the interests of IOCs and their future competitiveness and has raised concerns about the viability of the (neo)liberal economic model and market-based governance mechanisms (e.g., Vivoda 2009; Helm 2005). The longitudinal mapping of the changing corporate networks established by the five non-OECD NOCs identified above reveals, however, that alongside their expansion, the world’s largest non-OECD NOCs increasingly cooperate with the private IOCs and other NOCs (see, for an elaborate analysis, De Graaff 2011). In 1997 the corporate networks established by the five major NOCs involved 40 percent of other key players in the global energy market (measured as the top fifty ranking by PIW earlier mentioned). By 2007 this had increased to almost 75 percent. During this period the selected NOCs more than doubled their joint ventures abroad and tripled their domestic joint ventures (which involved foreign partners). This increase in corporate relations took place through The Transnationalizing of Non-OECD NOCs

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upstream alliances and investments, which nearly tripled (from 46 to 132), and mid- and downstream partnerships and investments, which almost doubled (68 to 117). That the growth of the transnational networks and the increased global presence of non-OECD NOCs has not implied an outright takeover of IOCs, as is sometimes feared, but increased cooperation with them is illustrated by Figure 4.2. This figure shows the aggregate number of partnership types (i.e., NOC-NOC, IOC-NOC, hybrid-NOC, hybrid-IOC, hybrid-hybrid) established by the five selected non-OECD NOCs in 1997 and 2007. Figure 4.2 shows that the IOC-NOC alliances of this selection of companies doubled in the period 1997–2007 and still make up the largest share. Another cooperation model that is rapidly increasing is the NOC-NOC alliance, which quadrupled in the case of these five NOCs. The largest increase, however, took place in the category of NOC-hybrid alliances; from virtually nonexistent to 20 percent of all the different types of alliances in 2007. Hybrid oil companies are here identified as distinctive from NOCs (100 percent state-owned) and IOCs (publicly listed) because they are partially state-owned.

Figure 4.2 Partnership Types of Five Top Non-OECD NOCs, 1997 and 2007

60 50

Total Affiliations

40

NOC-NOC N OC-NOC

N OC-IOC NOC-IOC

30

Hybrid-NOC H ybrid-NOC

20

Hybrid-IOC Hybrid-IOC

10

Hybrid-Hybrid Hybrid-Hybrid

0

1997

Source: De Graaff (2011: 277).

2007

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Partnerships between IOCs and NOCs as such are nothing new (see Parra 2004; Rodman 1988; Levy 1982), and what John Dunning has called “alliance capitalism” is probably the norm in the energy business (Yergin 2011b: 87–105; Dunning 1997). What these more recent findings show is that with the growth of non-OECD NOCs since the mid-1990s, these types of hybrid alliances are exponentially increasing. In other words, the globalization of state-owned energy firms from the non-OECD world over the past decades has contributed to an increasing transnationalization and hybridization of the global energy sector.3 Moreover, as one expert put it, these more recent developments entail a gradual “blurring of categories.”4 Resource-holding NOCs, traditionally operating mainly within their national borders, are increasingly expanding beyond them and moving down the oil value chain, cooperating with IOCs to get access to or acquire technological know-how and management expertise. Adding to this blurring of roles and categories are the major resource-seeking NOCs, which, as noted already, represent a whole new category and are in more direct competition with the IOCs. As will be elaborated, while these types of resource-seeking NOCs are increasingly acting as IOCs abroad, they retain a distinctive identity of state-owned entity—in fact one might want to call them international national oil companies. Let us now see to what extent the directors of non-OECD NOCs and OECD IOCs have followed a similar pattern. As noted, an extensive literature has documented that with the globalization of production, transnational corporate elite networks—established by the directors of major TNCs through interlocking directorates, for example—have significantly grown and form a crucial social tissue for the long-term and broader directions of corporate power and strategy. Interlocking directorates are seen in this literature as an important locus for corporate elite power (e.g., Kentor and Jang 2004) because they “link the key centres of command within the corporate economy” (Carroll 2010: 7) and “serve as channels of communication among directors, facilitating a common worldview” (Carroll 2010: 9). One would expect that the directors and managers of the non-Western NOCs with the internationalization of their firms have also formed such (transnational) networks and, moreover, that they might have integrated into the established networks of the Western corporate elites and thus increasingly become part of these channels of communication that facilitate a common worldview. However, in contrast to the increased cooperation between NOCs and IOCs, the corporate elite networks established by directors in charge of the world’s major IOCs and NOCs reveal distinctive patterns with respect to the practice of interlocking directorates and their state-firm relations (De Graaff 2012a).5 These will be discussed through an SNA of the networks of the directors of these companies in 2007.

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The first finding that stands out is that no non-OECD director (i.e., originating from a non-OECD country) appeared on the boards of the major IOCs, whereas only a few OECD directors were present on the NOC boards. In other words, little formal integration across the OECD/non-OECD divide is found at the level of the major IOC and NOC boards. This also implies that although there is some access for Westerners to some of the non-OECD NOC boards (i.e., Saudi Aramco, Gazprom, and PetroChina), non-OECD directors have no access to the IOC boards. As of yet, OECD directors thus seem to have more opportunity to exert influence within the non-OECD companies analyzed here than the other way around. That such board membership matters and is a sign of influence was illustrated when with the takeover of TNK-BP by Rosneft (see Claes, Chapter 5 in this volume), an important part of the deal was to give former BP executive Bob Dudley and two other non-Russian directors seats at the board of the Russian oil company. It is also why we find US directors on Saudi Aramco’s board, which expresses the company’s and country’s historical and close relationship with the United States. Similarly, the presence of a German director on Gazprom’s board can be seen in light of the extensive energy trade ties between Germany and Russia. This relationship was forged in particular under the leadership of Gerhard Schröder, who had close ties to Vladimir Putin. Tellingly, after his chancellorship, Schröder became head of the shareholder committee of Nordstream I—the contested new pipeline that transports gas directly from Vyborg in Russia to Germany. These examples also illustrate how corporate elite networks and the coordination of business interests are simultaneously underpinning and reflecting geopolitical relations and realities. The general lack of integration at the board level also signals the potential for geopolitical tensions and sensitivities. With respect to the general extent of interlocking directorates of the oil company directors, OECD directors have a much more extensive share of corporate interlocks in general. As Table 4.1 shows, 39 percent of the Oil Elite Networks: Also Transnationalizing?

Table 4.1 Distribution Corporate Interlocks, OECD and Non-OECD Directors Corporate Interlocks (%)

OECD directors Non-OECD directors Total

39 13 52

National Corporate Interlocks (%)

Source: Adapted from De Graaff (2012a).

53 14 67

Transnational Corporate Interlocks (%) 29 4 33

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OECD directors had corporate interlocks, whereas for the non-OECD directors this was only the case for 13 percent. Two thirds (67 percent) of all the corporate links that the oil company directors established in 2007 were national interlocks, whereas one third (33 percent) comprised transnational corporate interlocks.6 This extent of transnational interlocking is substantial compared with findings in the literature on transnational corporate interlocking more generally. Carroll, for instance, found one quarter of transnational corporate interlocks in a global network of leading corporate and financial firms for 1996 (Carroll 2010: 29). What is even more significant in the context of the present study is the distribution between OECD and non-OECD directors: of those 33 percent of transnational corporate interlocks, non-OECD directors only established 4 percent. When examining the network of these interlocking directorates more closely, we find that the OECD directors through their interlocking directorates link the oil companies to a network of the world’s major TNCs in several key industries (extractive industries, car industry, defense, technology), as well as to key players of global financial capital (such as Goldman Sachs, Royal Bank of Scotland, Société Générale). It thus comprises a network of corporate meeting places—or elite intersections—of the “big oil linkers,” who hold between three and thirteen corporate board memberships simultaneously with often at least one executive function. While oil company directors in general are firmly embedded in TNC elite networks, this hardly applies to the directors of the major non-OECD NOCs. The exceptions here are Gazprom and Saudi Aramco, which do have a few directors with ties to the TNC network. In most cases these directors turned out to be OECD directors, a few examples of which have been discussed already (for a more extensive analysis of these different corporate networks, see De Graaff 2012a). This underscores the asymmetry in terms of influence of non-OECD directors in Western corporate elite networks. It implies that they have hardly any access to the old boys’ networks in which a more general corporate strategy and elite consensus is shaped. This elite segregation is arguably an important reason for the persistent suspicion against NOCs and other state-owned entities, which is aggravated by the fact that many of these directors are also intimately related to the state. In 2007, the major NOCs in this selection had twenty-seven directors simultaneously in positions at the state level, establishing a total of forty-six state interlocks, while this applied to only six IOC directors (a total of seven interlocks). Moreover, the IOC directors only held advisory positions and in general displayed a revolving door pattern that is more typical of Western state-firm relations (Van Apeldoorn and De Graaff 2014). NOC directors, by contrast, had highly ranked state positions—often at a ministerial or vice

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ministerial level—and many more direct overlaps (for a more in-depth analysis of these state–firm linkages, see De Graaff 2012a). These distinctive differences in the state-firm relations of the oil company directors not only explain but arguably also maintain the lack of integration of non-OECD oil directors within OECD corporate elite networks, since the former’s intimate relations with government is perceived as threatening to Western private business interests and values, thus creating a reason to block access to such strategic business venues. In sum, the findings presented so far have revealed the increasingly networked nature of the global energy market, with a growing number of hybrid alliances and a general blurring among the different company types, with non-OECD NOCs becoming active global players outside their domestic borders. They also reveal that the non-OECD oil elites, while directing the major expansion of their NOCs—which generates increased cooperation with OECD private majors and higher levels of interdependency—did not integrate into the existing Western corporate elite networks to which IOC directors were extensively connected. The non-OECD directors are still extensively linked to their respective home states, and this indicates that elite power is still very distinctively organized and sharply divided and Western elite networks are still dominant. Although it might be a matter of time—that is, there may be a time lag between closer corporate cooperation and elite integration—it also implies that the non-OECD oil elites have not been coopted—and thus so far are following a distinctive trajectory in terms of their internationalization. As an illustration of this distinctive trajectory the next subsection will more closely examine the case of Chinese NOCs, which arguably represent a primary case of nonOECD NOCs with a globalizing strategy. Much has been written on the expansion of the Chinese NOCs (Moyo 2012; Holslag 2006; Zweig and Jianhai 2005), which is often portrayed as a mercantilist strategy charted by the Chinese state to lock up energy supplies around the world for the sole purpose of supplying Chinese consumers. These portrayals are overdrawn for several reasons (for forceful rebuttals, see Downs 2007a, 2007b; for the complexities involved in Chinese energy governance domestically and abroad, see Andrews-Speed and Dannreuther 2011; Kong 2011; Andrews-Speed 2004). Certainly part of the impulse for foreign expansion—the so-called going global strategy—was generated by an exponentially growing need for energy supplies and by the perception that an expansion of the NOCs would be an effective way to attain that goal. But it is as much (and The Two Faces of Chinese NOCs

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increasingly) driven by corporate interests and incentives (Jiang 2012; Downs 2007a, 2007b). Some commentators even argue that oil executives only pay lip service to what is in effect seen as a flawed assumption, namely, the idea that energy supply security can be obtained through Chinese companies’ acquisitions abroad (Downs 2008: 128).7 As observed by Jiang (2012: 416): “CNPC leadership is a governmental position first and foremost.” Subsequently, NOC managers must balance corporate and party-state interests if they want to advance their political careers, because their evaluation by the Chinese Communist Party is based not only on general performance but also on their commitment to party-state interests (Jiang 2012). This points to the complex and contradictory relation between Chinese NOCs and the state and illustrates how Chinese oil elites form an important nexus in this regard. While formal corporate governance of the Chinese NOCs, according to Jiang (2012: 396), “mimics the best practices of the West” (referring to the annual corporate responsibility report), the performance criteria by which managers are evaluated do not include traditional metrics of stock price, shareholder returns, or economic value added but measures such as “improving ideological and political work, enhancing Party conduct and anti-corruption campaign,” “eliminating factors that cause instability,” and “preventing occurrence of mass commotion” (Jiang 2012: 397; see Downs 2008 for some concrete examples of how this plays out). The two faces of the Chinese oil elites are also mirrored in descriptions of the dual role played by Chinese NOCs—operating as an IOC abroad but still as an NOC domestically.8 This duality on one hand brings the Chinese NOCs advantages of state support, for instance, in political and financial backing for oil deals. The $2 billion loan of the Chinese Export Import Bank to Angola most likely facilitated the entrance of Chinese NOCs in Angola (see Downs 2007a: 53). On the other hand it implies additional responsibilities such as energy supply security and social commitments at home (for instance, the companies are responsible for the pensions of their employees). At the same time, by becoming more IOC-like and competing abroad, they face similar constraints, including resource nationalism, security issues (such as they have been experiencing in Sudan), and questions of how to ensure and safeguard their foreign employees in politically unstable regions, increased pressure for transparency (e.g., the Extractive Industries Transparency Initiative), and “good governance” (Lahn et al. 2007). The notion of the dual character of expanding Chinese NOCs—while warranting a study on its own—holds two important implications for the present chapter. First, it implies that even if parts of the Chinese NOCs

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become increasingly IOC-like and increasingly adapt to Western-style governance (in particular their listed subsidiaries such as CNPCs PetroChina), they remain firmly tied to a very different form of governance with a set of priorities, values, and interests that are tightly bound to the state (Kong 2011). This duality is reinforced by Chinese oil elites who want to make a political career and therefore maintain the balancing act between their two sides. Second, following from the first implication, this dual character is an indicator of hybridization. It implies that with their expansion abroad, Chinese NOCs are essentially combining private and “statist” governance in one entity (see, for a more elaborate analysis, De Graaff 2013, 2014). Conclusion

This chapter has focused on (changing) power structures at the top of the oil and gas industry, by illustrating how—against a backdrop of a broader fundamental power shift from the Atlantic to the Pacific, and concomitant geographical shifts in patterns of energy consumption and production—the recent global expansion of non-OECD NOCs has generated increasingly hybrid alliances between NOCs, IOCs, and hybrid oil companies. Although this development from the mid-1990s onward signals increased integration of non-OECD NOCs into the global energy market, such patterns were not mirrored at the level of directorships, what I have labeled “oil elites.” In fact, the mapping of these oil elite networks revealed distinctive patterns and very little integration between OECD and non-OECD networks. A significant share of the OECD oil company directors are closely interlocked with a transnational network of major TNCs from several core industries and finance, but non-OECD directors were hardly connected to these networks. Because such networks are seen as important channels of (informal) power and influence and the coordination of (wider) business interests, this relative lack of integration indicates that non-OECD directors still lack access to such crucial venues of influence and coordination. The presence of some OECD directors at the NOC boards was shown to be related to geopolitical concerns, thus also pointing to the potential for geopolitical conflicts. At the same time, the scarcity of such personal interlocks arguably makes the hybrid corporate alliances between IOCs and NOCs more vulnerable, especially in cases and contexts where the strategic and geopolitical stakes are high. An example here could be the ExxonRosneft joint venture in the Arctic, at the University-1 well, from which ExxonMobil withdrew in fall 2014 due to the Russian sanctions imposed by the US government.

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The divide between the non-OECD and OECD in terms of elite integration might also make alliances between non-OECD statist regimes more attractive. For instance, the battle over the highly prospective N Block in Kazakhstan was lost by Shell because ConocoPhillips managed to enlist the support of a state-owned entity in the joint venture, which was then preferred by the Kazakh government (De Graaff 2013: 171–172). In-depth case studies such as the above would be required to assess whether indeed these propositions hold and would be promising avenues for further research. It should also be noted that formal directorships and interlocks—and the social power or influence that may be derived from such ties—do not capture more informal ties and behind-the-scene business and political dealings. For example, the so-called wax cartel, in which product and sales managers of some of the world’s leading oil majors (such as ExxonMobil and Shell) had been controlling 75 percent of the European paraffin market, was revealed in 2008 by the EU commissioner for competition (Carvajal and Castle 2008). Documentation of such ties, however, requires a different type of analysis and data (see Spiro 1999 for an interesting and excellent account on the “secret auctions” of US Treasury bonds to Saudi Arabia as part of the petro-dollar recycling agreement in the 1970s). What SNA and the mapping of the interlocks can provide is a systematic empirical analysis and visualization of social ties that represent a particular corporate and political power structure. This may in turn serve as a stepping stone for further in-depth inquiry of additional modalities in which oil elites meet and coordinate their interests. Taken together, these findings raise important questions about the power balance between NOCs and IOCs and the extent to which non-OECD NOCs have actually become the new rule makers (Hoyos 2007a). The development since the mid-1990s does not seem to indicate a simple takeover of NOCs (Wälde 2008; Odell 2006; Helm 2005) or a “return to state capitalism” (Bremmer 2008, 2009) but an increasingly hybrid and complex mixture of energy relations in which state-owned and private entities coexist and are increasingly required to cooperate. For IOCs this might imply that they need to consider new strategies (Vivoda 2009). In addition to seeking active support from their home states, they might need to join forces with other stateowned entities (such as sovereign wealth funds and NOCs) to gain access to resources, as illustrated by the example with Shell and the N Block. Although resource holders can decide to break with particular rules or use these to their advantage, depending on their bargaining power (Vivoda 2009; Vernon 1971), this does not necessarily imply that they are also rule makers. For instance, in November 2014 when Saudi Arabia decided to keep output high in spite of dwindling oil prices in the context of the US shale production, this was not so much an attempt to be a rule maker—they

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did not break with any established market rules or institutions nor establish any new rules—they used rules to their advantage or at least did not give in to US political pressure to act as a swing producer (as they had done many times before when prices had been falling, see Yergin 1991). Although it is clear that non-OECD NOCs are becoming increasingly influential players—a trend that is not confined to their role in the energy order but is part of a much wider development in the global political economy—they seem, in fact, not to have become the new rule makers yet. This is, for instance, illustrated by the fact that China, the world’s largest energy consumer, is not a member of the IEA, which is one of the most influential global governance bodies and the number one watchdog of consuming countries (Lesage, Van de Graaf, and Westphal 2010). Instead, the IEA hopes, as its former deputy executive director Richard Jones stated: “that through greater engagement they [i.e., nonmembers such as China, India, and Russia] will become more and more willing to move in what we consider to be the right—i.e., market-oriented—directions, for our mutual benefit.”9 Rather, as the quote indicates, non-OECD NOCs are expected to and have become better at playing by a rule set largely defined within an OECD framework and by OECD actors. It is, for instance, by hiring US lawyers that NOCs are seen as capable of understanding and playing the rules of the game (De Graaff 2013). Similarly, it is likely that a US service company will provide the NOCs with the necessary technology to eventually compete with the IOCs. The content of these rules are primarily tailored to competition, privileging shareholder value, and (short-term) profit making, that is, promoting and opening up space for the extension and deepening of capital accumulation (De Graaff 2013). The findings presented here on the lack of integration of non-OECD NOC directors into the still-dominant Western corporate networks where elite consensus on the rules of the game is shaped are another indication that they are not rule makers yet. At the same time, non-OECD NOCs retain a distinctive business model—in particular, domestically—in which the state plays a more directing role and remains the major (or sole) owner. Hence, they need to balance their international commitments with national requirements. The latter, while probably encouraging NOCs toward participation in global oil markets and financial circuits, will also emphasize values of the dominant political ideology and national interests such as supply security and social stability. This hybridity is most vividly illustrated by the double roles played by the expanding Chinese NOCs and their managers as they increasingly operate as IOCs abroad while retaining their role as NOCs domestically, a duality that was described in the last part of the chapter. Internationally, they are adapting to the rules of the game of international

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business and learning to play by these rules, as mentioned. Domestically they still adhere to the national rules of the game, closely tied to the state apparatus and to the respective set of expectations, responsibilities, and (in)formal rules. Thus, non-OECD NOCs’ expansion is generating not only more hybrid forms of cooperation and a persistent transnationalization of the global energy relations but also a more hybrid governance of these energy relations. In addition, it should be noted that with the transnationalization of the global energy order, other types of private actors are becoming increasingly influential and autonomous. Limitations of space prohibit further elaboration of this issue, but, for instance, financial speculators and investors, corporate lawyers, and international energy service companies are increasingly affecting the power balance between the traditional trilateral oligopoly of consumer states, producer states, and oil companies (Roncaglia 1985) and contribute to the marketization and financialization of energy governance (De Graaff 2013). A final consideration: the focus of this chapter has been on fossil fuels (oil and gas in particular) because these are still the dominant energy sources and a focal point of current vested corporate and political interests.10 A promising and relevant future avenue for research would be to investigate the implications of the rising power of non-OECD countries, firms, and elites for the transition toward a more sustainable energy economy based on renewable resources. Major non-OECD countries such as China and India are taking a leading global role in terms of renewable energy investment (Bloomberg New Energy Finance 2013). Given their latecomer disadvantage in the fossil fuels industry, it is arguably an attractive catch-up strategy to become front runners in renewable energy sources and technology. Moreover, it could be argued that their state-directed business model is well suited for the development of such an infant industry that needs state support to be commercially viable. By providing findings of the influence of rising non-OECD powers and their firms on the configuration of corporate power at the apex of the global energy order, this study may contribute to the development of such a research line. Notes

1. The companies of the new Seven Sisters are Saudi Aramco (Saudi Arabia), Gazprom (Russia), CNPC/PetroChina (China), National Iranian Oil Company, Petrobras (Brazil), Petronas (Malaysia), and Pétroleos de Venezuela (Hoyos 2007a). 2. It should be noted, however, that data on reserves are highly sensitive and generally not seen as very reliable. In particular, large resource holders are said to have an incentive to inflate their reserves because it is an indicator of economic

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power. Nonetheless such aggregate data provide a sufficient indication of the extent and direction of these trends. 3. By hybridization I mean that within these partnerships—for instance, in a joint venture—private capital and state-owned capital coexist but are not fused, that is, they remain distinctive entities, therefore hybrid. 4. Telephone interview by author with Valerie Marcel, Chatham House, Royal Institute for International Affairs, associate fellow and NOC expert, December 16, 2009. 5. An interlocking directorate means a linkage among corporations created by an individual who sits on two or more corporate boards. State-firm relations refer to individual corporate director’s ties to government. 6. A national corporate tie in this case means that an oil company director sits on another board of his own nationality; a transnational corporate tie means that a director sits on another board of a different nationality than his own. 7. Interview by author with Weihan Wang, professor at University of International Business and Economics, Beijing, February 26, 2010, conducted in Houston, Texas. 8. Telephone interview by author with Xu Xiaojie, former director of CNPC’s overseas investments, January 21, 2010. See also, on the complexity of Chinese energy governance, Andrews-Speed and Dannreuther (2011), Kong (2011), and AndrewsSpeed (2004). 9. Interview by author with Richard Jones, at the time deputy executive director of the International Energy Agency, November 19, 2009, conducted in Paris, France. 10. The 2012 World Energy Outlook report stated that fossil fuels would remain dominant in the global energy mix and moreover were subsidized by around $523 billion in 2011, six times more than renewables subsidies (IEA 2012a: 69, 233).

5 The Scramble for Arctic Oil and Natural Gas Dag Harald Claes

Over the past few decades, a combination of climatic and economic changes has brought the Arctic to the forefront of global political attention. One of the most visible effects of global climate change is the shrinking of the polar ice cap, which makes the Arctic region more accessible for commercial activities such as maritime transportation, fisheries, mining, and oil and gas exploration. Combined with a general notion of increasing global scarcity of oil and gas resources, attention to the Arctic oil and gas resources has increased dramatically. This renewed attention is often based on misunderstanding and misinterpretation of the economic, political, and institutional aspects of the development of these resources. In this chapter I discuss the geological prospects, commercial viability, and legal and political aspects of Arctic oil and gas exploration. First, it is necessary to describe the changing conditions for increased commercial activity in the Arctic region in general. The Arctic Scramble

One of the most visible consequences of climate change is the retraction of the sea ice in the Arctic Ocean. This influences the natural conditions for animals and humans in the region. In 2015, extension of the maximum Arctic sea ice fell to its lowest level since satellite recording started in 1978, while the annual minimum ice coverage for 2016 tied for second lowest ever recorded (NSIDC 2016, 2015). The potential for an ice-free Arctic Ocean in the summer is now within years, not decades, as earlier estimated. The ice retraction will have climatic consequences as “a calm ocean soaks up about 93 percent of the sunlight striking it,” while “snow-covered ice, by contrast, reflects more than 90 percent of solar energy” (Kramer 2013). This phenomenon, known as Arctic amplification, implies that the Arctic will warm far more than the rest of the globe and provide this second-order con85

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tribution to global warming (Harriss 2012). The rapid warming changes conditions for the whole ecosystem in the region. Animals dependent on permanent ice, such as polar bears, will face the potential of near extinction. Likewise, commercial activities based on permafrost will literally be on weaker ground. Fish species dependent on warmer water will potentially travel farther north as Arctic waters warm up. Among the indigenous people, such as the Inuit, there are still some who depend on hunting polar bears, seals, and other animals. They will face fundamental challenges in sustaining their traditional hunting methods and ways of life. The shrinking of the ice cap opens opportunities for new commercial activities in the Arctic, for instance, the possibility of following fish stocks moving north and gaining easier access to previously ice-capped mineral resources. The opening of ice-free sea routes in the Northwest and Northeast Passages may shorten the sailing distance for maritime trade between Europe and Asia as much as 50 percent, compared with the currently used shipping lanes via the Suez or Panama Canals. For offshore activities such as shipping and oil and gas exploration, the ice melting is potentially preferable. For onshore activities, warmer Arctic climate reduces the time ice roads and tundra are sufficiently frozen to permit travel. Permanent installations that previously were based on permanent frozen ground now have to be constructed with man-made foundations. The Arctic has been inhabited for more than 10,000 years and has been commercially exploited for the last several thousand years. Arctic oil activity has almost a 100-year history (Pratt 1944). In the Canadian Northwest Territories, oil drilling commenced in 1920. The largest oil field in North America, the Alaska North Slope, was discovered in 1968. In the early 1970s, many major oil producing countries nationalized their oil industries. This made the international oil companies seek resources in other oil provinces, such as Alaska, the Norwegian continental shelf, and onshore West Siberia. In the mid-1980s the oil price fell, and oil was regarded as any other commodity, if not in abundance, then with sufficient supply at reasonable prices for the foreseeable future. The push for Arctic resources was postponed. During the first decade of the new millennium, increased energy consumption in several emerging economies and lack of large new discoveries made many analysts predict a near future of oil scarcity. A steep price increase from 2003 to 2008 fueled this perception (Deffeyes 2010). Prominent scholars see increased political conflicts arising from this apparent increased scarcity of energy resources. This also goes for the Arctic (Borgerson 2013; Klare 2012a; Klare, Chapter 2 in this volume). Among governments and the international oil companies the oil and gas resources in the Arctic have gained importance over the past decades. Russian authorities have announced that the Arctic, in particular the Arctic

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offshore, will be a cornerstone of their future energy production. The northern part of the Scandinavian Peninsula has a warmer climate than other parts of the Arctic on the same latitude due to the North Atlantic current. Thus, oil and gas exploration in the Barents Sea (about 75°N) is not affected by ice, solid nor drifting. Norway continues to announce licensing rounds in the Barents Sea after some promising discoveries were made in 2011. Furthermore, Norway and Russia have agreed on a delimitation of the continental shelf in the Barents Sea, whereupon Norway immediately started seismic surveys in its part of the formerly disputed area. The Russian government issued offshore licenses to state-dominated Rosneft, who then signed cooperation agreements with ExxonMobil, Eni, and Statoil to explore and develop resources in the Kara and Barents Seas. On Greenland the local authorities see possible oil revenues as an economic platform for future independence from Denmark. Oil-consuming countries have also taken an interest in Arctic energy resources. In October 2008, the European Parliament stated that it “remains particularly concerned over the ongoing race for natural resources in the Arctic, which may lead to security threats for the EU and overall international instability” (European Parliament 2008). Chinese oil companies have also set their eyes on Arctic oil and gas exploration (Stein 2015). Taken together, these observations suggest that something is going on, maybe not a bonanza or oil rush, but still the increased activity represents a possibility for the Arctic to become a new oil and gas province. Or is it a case where there is much ado about (almost) nothing? Are Arctic Oil and Gas Resources (Globally) Important?

In 2008, the US Geological Survey (USGS) published an appraisal of undiscovered Arctic oil and gas resources, known as the Circum-Arctic Resource Appraisal (CARA). The USGS study is not based on data from exploratory drilling. It estimates the probability of oil and gas accumulations in thirtythree onshore and offshore geological provinces north of the Arctic Circle, of which eight provinces were found to have less than 10 percent probability of at least one significant accumulation of hydrocarbons. The total potential of undiscovered conventional resources in the remaining twenty-five provinces was estimated to constitute “90 billion barrels of oil (BBO) and 1,669 trillion cubic feet of natural gas (tcf), and 44 billion barrels of natural gas liquids” (USGS 2008: 4). There are also discovered resources in the Arctic. Anthony Spencer and colleagues present figures based on the IHS database, suggesting a total of approximately 60 BBO discovered recoverable resources in the Arctic region (Spencer et al. 2011: 2). The Arctic share of undiscovered oil

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and gas has been used in public debate to emphasize the global importance of Arctic resources, often disregarding the fact that there are large quantities of discovered and recoverable reserves globally, particularly if one adds unconventional oils from shale, sands, and even coal. So far there are few systematic estimates of the global potential of such resources. Table 5.1 compares the Arctic resources with global conventional resources. Perhaps the most important insight from this table is that there are a lot of discovered oil reserves in the world that have not yet been developed or are under development. In this perspective the Arctic resources are less impressive. The gas resources in the Arctic are substantially larger than the oil resources. Recently, more unconventional shale oil and gas has become profitable to produce. If we include Canadian oil sands, the world oil resources indicated in Table 5.1 would increase by 10 percent, further reducing the Arctic share. In the longer term the Arctic has unconventional gas resources, too, in the form of gas hydrates. These resources feed into an academic, technical, commercial, and political debate regarding global energy resources. Because the oil and gas resources in the Arctic are mostly unexplored, it is uncertain how much of these resources can be turned into commercial reserves. Furthermore, the environmental challenges and concerns are higher in the Arctic than in most other oil- and gas-rich areas of the world. The Arctic natural environment is very vulnerable to oil spills, for instance. The Exxon Valdez accident in 1989 still plays an important role in political debates around Arctic exploration. As the oil price rose from about $20/barrel in 2003 to $147/barrel in July 2008, panic broke out among the large oil consumers over the prospect of continuous price increases and possibly physical shortage. The release of the CARA report in 2008 was impeccable timing for consumers. The prospect of large available resources in the Arctic might have eased the fear of a future of continuous oil shortages. CARA is very important, is widely cited, and serves as a starting point of almost all economic, political, and academic discussions of Arctic energy. However, the methodological limitations of the study are often neglected. For large parts of the region, the Table 5.1 The Arctic Share of World Conventional Oil and Gas Resources Oil Natural Gas Arctic World Arctic Arctic World Arctic (BBO) (BBO) Share (%) (tcf) (tcf) Share (%)

Undiscovered Discovereda Total

90 60 150

732 1579 2,311

12.3 3.8 6.5

1,669 1,615 3,284

Sources: Spencer et al. (2011); USGS (2008). Note: a. Estimated reserve growth and remaining reserves.

5,196 8,453 13,649

32.1 19.1 24.1

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CARA estimates are based on very broad seismic surveys, nothing like industrial seismic work carried out in concentrated areas prior to exploration drilling. It relies on a probabilistic methodology of geological analysis and analogy modeling: The CARA team analysed each Arctic AU (assessment unit) to determine the geological properties most likely to control the sizes and numbers of undiscovered petroleum accumulations. Families of AUs from the analogue database with similar geological properties were identified. . . . The CARA results suggest there is a high probability (>95 percent chance) that more than 44 BBO [billion barrels of oil], a one in two chance (>50 percent) that more than 83 BBO, and a 1 in 20 chance (5 percent) that as much as 157 BBO could be added to the category of proved reserves from new discoveries north of the Arctic circle. (Gautier et al. 2009: 1177–1178)

The USGS estimates three times as much gas as oil, distributed along the same probability scale as presented above for oil: 95 percent: 770 tcf; 50 percent: 1,547 tcf; and 5 percent: 2,990 tcf, with the mean of 1,669 tcf (Gautier et al. 2009: 1178; USGS 2008).1 These scales of probabilities are important for future commercial investments in the Arctic as investors compare the probability of success in the Arctic, based on these figures, with similar figures for other petroleum provinces. The USGS study evaluated all areas north of the Arctic Circle (66.56°N). The total area north of the Arctic Circle constitutes 30,604,000 km2. An area this size can hardly be considered a single oil or gas province,2 and there is nothing to suggest the potential resources in this enormous area will be developed in any coordinated way. It is also necessary to consider the distribution of the resources along various geographical, climatic, economic, and political dimensions. The surface is split in three parts of about equal size: one third above land; one third ocean floor less than 500 meters deep; and one third deepwater basin. The USGS study divides the Arctic into thirty-three petroleum provinces. Twenty-five of these were assumed to have a 10 percent or greater probability of at least one significant undiscovered petroleum accumulation (USGS 2008). More than 70 percent of the oil resources are assumed to be located in five provinces: Arctic Alaska, Amerasia Basin, East Greenland Rift Basin, East Barents Basin, and West Greenland–East Canada. More than 70 percent of the gas resources are assumed to be located in three provinces: West Siberian Basin, East Barents Basin, and Arctic Alaska (see Figure 5.1).3 Most of the resources are thus fairly concentrated and most of the undiscovered oil and gas resources (84 percent) are located offshore, a circumstance that usually increases the production costs compared with onshore production. But the resources are concentrated in relatively shallow waters (i.e., less than 500 meters). The deepwater basin is expected to have

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Figure 5.1 Main Arctic Oil and Gas Reserve Basins

Source: US EIA (2012c).

less resource potential and would constitute a challenge for oil and gas exploration regardless of ice and weather conditions. In one sense the CARA is a first cut because it estimates probabilities in larger subsections of the Arctic. It cannot say more accurately where resources are to be found within these areas. To do so, extensive seismic surveying and subsequent exploration drilling are required. This relates to a widespread confusion regarding the terms resources and reserves. Resources are geologically defined natural concentrations of minerals. Turning estimated resources into actual reserves requires more specific geological certainty on the accumulation of hydrocarbons able to escape from their rock reservoir, technological solutions to extract the petroleum or gas from a particular reservoir, and the commercial potential to have the oil or gas sold with a profit. This is illustrated by the following definition of proved reserves: “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” (BP 2013: 6). All concepts used in this definition can change. Today, most of them do. The USGS appraisal of Arctic resources changed the geological understanding of that region, innovations in engineering increase the recovery rate of existing fields, and technological breakthroughs have turned shale

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deposits of oil and gas from unrecoverable to recoverable in just half a decade. Certainty of commercial reserves can only be created by exploratory drilling. In oil and gas provinces all over the world, companies drill dry holes in seemingly geologically prosperous locations. Even if oil or gas concentrations are found, they may not be produced. That depends on the cost of production relative to the market price. It follows that even though the total amount of oil and gas resources in the ground is estimated correctly, the amount recoverable for production and consumption varies with a number of technological, economic, and political factors. For oil companies the control of (or at least access to) proven reserves is crucial to the appraisal of the companies’ financial condition. Since reserves estimates always will be estimates, it could lead to attempts to increase the figures to look more financially solid. As an illustration, the chairman of Shell, Sir Philip Watts, resigned in 2004, after it was disclosed that the company had overstated its oil reserves by at least 20 percent. States might also have an interest in increasing national reserves figures. This is particularly the case among members of the Organization of the Petroleum Exporting Countries (OPEC), where reserve estimates occasionally have been discussed as part of the basis for distribution of production quotas (McGlade 2012: 265; see also Claes 2001: 245–246). However, in the modern history of oil there has never been a situation of actual physical shortage of supply. In 1973, Arab oil producers tried to create a shortage for political reasons, but the installed production capacity of the world was then and has been since sufficient to serve demand. Even in the summer of 2008, when the price was $147/barrel, no physical shortage appeared. Thus, the price cannot be taken as a signal of actual physical shortage. Furthermore, when countries have decreased their production for commercial or political reasons they are usually able to reverse these strategies. The most important oil producer in the world, Saudi Arabia, was predicted to have an imminent decline in oil production a decade ago: “In all probability, output peaked in 1981 at an unsustainable level of about 10.5 million barrels per day (mbd)” (Simmons 2005: 334). In 2015, Saudi Arabia had an average production of 12 mbd. At the same time, the United States produced 12.7 mbd, 1.6 mbd higher than the so-called peak in 1972, and with an increase from 2010 of almost 70 percent. Over the past decade global oil production has grown by an annual average of 1.2 percent. In the same period, estimated proven reserves have grown by almost 25 percent. There is simply no evidence of shortage or of an imminent peak in global oil supplies. In this situation, the role of the Arctic resources is dependent on their relative attractiveness compared with other oil and gas resources in the world. Thus the investment and operating costs are vital to the development of the Arctic resources. There are a number of factors increasing the costs of

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development of Arctic resources. In general, the permanent or part-time icecovered seas will imply development of special equipment and put seasonal restrictions on the drilling activities. Sub-sea technology could avoid some of these constraints. Distance to the markets and the possible need for icebreaker and specially designed oil tankers constitute another cost driver. The IEA has estimated that the cost of developing an offshore Arctic production field (including drilling, production facilities, and operating and decommissioning components) with the easiest accessible Arctic energy resources to be about $35–40/barrel (IEA 2008: 206). The more complicated Arctic offshore areas are assumed to have production costs up to $100/barrel. With the long lead time for development of these resources, the future price of oil and gas is crucial for companies considering investing in Arctic production. With the present global oversupply of gas and oil, the prospect of rapid investments in Arctic oil and gas exploration looks dim, particularly as there are other opportunities for investments and exploration available to the companies. Most of these other opportunities have lower costs and risks. Philip Budzik detailed factors that increase the costs of Arctic oil and gas exploration and production compared with other regions of the world. He listed: Harsh winter weather requires that the equipment be specially designed to withstand the frigid temperatures; On Arctic lands, poor soil conditions can require additional site preparation to prevent equipment and structures from sinking; The marshy Arctic tundra can also preclude exploration activities during the warm months of the year; In Arctic seas, the icepack can damage offshore facilities, while also hindering the shipment of personnel, materials, equipment, and oil for long time periods; Long supply lines from the world’s manufacturing centers require equipment redundancy and a larger inventory of spare parts to insure reliability; Limited transportation access and long supply lines reduce the transportation options and increase transportation costs; [and] Higher wages and salaries are required to induce personnel to work in the isolated and inhospitable Arctic. (Budzik 2009: 9)

The specific locations of the most promising resources are important because they decide under which political and economic framework conditions they will be developed. The USGS study indicated that the resources by far most likely to be economically viable to produce are those located in Arctic Alaska. For natural gas, the East Barents Basin and the West Siberian Basin are the most promising, and both belong to Russia. Also, Arctic Alaska contains substantial quantities of natural gas. The future major development of Arctic oil and gas reserves are thus most likely to be concentrated in these areas, although minor production activities could take place in other locations. Lars Lindholt and Solveig Glomsrød estimated

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future Arctic oil and gas production under various oil price scenarios and the regional distribution of the future production. Their base case scenario had an oil price of $80/barrel until 2030. In this case 81 percent of total Arctic oil production from 2008 until 2030 would come from Russia, and 14 percent would come from Alaska. This would leave only 5 percent of oil from other sources. The same figures for natural gas production suggested that 94 percent would come from Russia alone (Lindholt and Glomsrød 2009: 72–73). These estimates are in line with the present situation. In 2008, 97 percent of total Arctic oil and gas production came from onshore fields in Russia and Alaska (Arctic Council 2009: 7), and two thirds of Russian oil and gas was produced north of the polar circle. By mid-2016, Russian Arctic oil production from three new oil fields (Kharyaga, Trebs and Titov, and Prirazlomnoye) had increased to over 100,000 barrels/day, while newer Arctic terminals were handling 230,000 barrels/day, up from 130,000 in January 2015 (Lee 2016). For European oil and gas consumers, the conclusion is obvious: their access to any substantial quantity of Arctic energy resources most likely goes through Russia, both presently and in the future (Harsem and Claes 2013). Arctic Oil and Gas Activities

As shown in Table 5.2, more than 400 oil and gas fields have been discovered north of the Arctic Circle after the drilling of more than 2,000 exploratory wells. The Arctic share of world oil production was about 10 percent in 2010 (Lindholt and Glomsrød 2011: 16). Present Arctic production is dominated by Russia. About 60 percent of Russian oil resources and 95 percent of gas resources are located in the Arctic, and 20 percent of Russia’s gross domestic product and 22 percent of Russian exports are tied to its Arctic region (Flake 2014: 105). Most of Russian oil and gas production is onshore above the polar circle. Although most Arctic oil resources are found in either Russian or US territories, for recoverable gas, the concentration is almost entirely in Russian territories. The five Arctic coastal states are giving great attention to the oil and gas resources under their jurisdictions. Some of them have a longer history of Arctic oil and gas production, and others have barely any activity at all (see Table 5.2). In the 1970s, several large gas fields were discovered in the Yamalo-Nenets Autonomous Okrug. Production capacity was rapidly built up, and pipelines Russia

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Table 5.2 Arctic Petroleum Activity by Country

Russia US Norway Canada Greenland Total

Wildcat Wells 1,141 627 118 108 12 2,006

Discoveries 259 128 37 20 0 444

Source: Spencer et al. (2011: 2).

BBO

34.7 24.5 1.2 0.5 0 60.9

Oil

%

57.0 40.2 2.0 0.8 0 100.0

BBO

255.8 8.7 2.2 2.5 0 269.2

Gas

%

95.1 3.2 0.8 0.9 0 100.0

taking the gas thousands of kilometers to the west were constructed. In 1988, the world’s largest gas field, Urengoy, peaked with an output of 300 bcm. This field alone constituted half of total production in the Russian Federation. As the early giant fields are approaching depletion, production is being held up by satellite fields and other smaller fields in the region. Plans for further expansion have been under way since the 1980s, when exploration activity on the Yamal Peninsula intensified. Both field development and infrastructure construction was halted in the early 1990s. In 2006, the project was taken up again by the state-dominated gas company Gazprom. Production plans called for a build-up to 115 bcm (possibly 140 bcm) in the course of a few years and subsequent development of the huge Kharasavey field on the northwestern shore of the Yamal Peninsula (Claes and Moe 2014). Oil production started in the same area in the 1990s. Several international companies, particularly Conoco but also Total and Norsk Hydro, were engaged in the development of oil fields. By 2009, oil production in the district had reached about 18 million tons. Production from the northern fields is transported by pipeline to a sea terminal in the shallow Pechora Sea, twenty-two kilometers off the coast at Varandey. Production from southern fields is piped through the Komi Republic into the main pipeline network. There is a considerable resource potential in Nenets allowing for increased oil output (Claes and Moe 2014). Geological exploration of the Russian Arctic continental shelf started in the Barents Sea in 1971. The first exploration drilling beyond shallow waters took place in 1982 (Bergesen, Moe, and Østreng 1987: 32–33). Through the 1980s a considerable seismic surveying program was carried out, and further drilling was undertaken in the Barents Sea and the Kara Sea. Overall the assessment was of a very promising resource base, and several important discoveries were made, including Shtokman and Ludlovskoye in the Barents Sea and Leningradskoye and Rusanovskoye in the Kara Sea, all super giant gas fields. Oil discoveries were smaller or uncertain, but exploration drilling had been very limited. Thus, the rate of discovery was very high. By 2011,

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the initial total estimate of official Russian oil and gas offshore resources, discovered and undiscovered, constituted 70 billion tons of oil equivalent; of this, 7 billion tons have actually been deemed “discovered” (Khramov 2012). Turning discoveries into actual producing fields has proven harder. The giant Shtokman gas field is an illustrating case. In Russia, foreign companies can participate in development of oil and gas fields only as subpartners to Rosneft or Gazprom. In the Shtokman case, a separate company for the development of the field (SDAG) was set up in 2008, with Gazprom (51 percent), Total (25 percent), and Statoil (24 percent). The foreign partners in SDAG had no ownership claim to the resources. The investment decision was postponed several times. In 2012, Statoil pulled out of SDAG; in June 2015, Total followed suit. Lassi Heininen and Gleb Yarovoy see three factors determining the future of Shtokman: development of new, more cost-efficient and environmentally friendly technologies for offshore drilling; positive trends and favorable outlook in the world gas market; and improving and adapting tax legislation in Russia (Yarovoy, Heininen, and Sergunin 2013). The Shtokman field is so large it would require substantial infrastructure investments. With present market conditions, the project is not likely to proceed. So far Russia has only one active Arctic offshore oil field, Prirazlomnoye, in the Pechora Sea. Although production is increasing rapidly (crossing a million barrels of total cumulative production in September 2014), a major challenge remains the transportation of oil from the field as the production platform is surrounded by ice for a period of six to seven months a year. Nonetheless, the Russian state and its NOCs may have great incentive to increase its development (Gurzu 2016). Alaska

In 1968 the Prudhoe Bay Oil Field was discovered. Three years later the OPEC countries took control over oil price-setting through the Tehran and Tripoli Agreements with the international oil companies and followed this with the oil embargo of October 1973. These events triggered an increase in the market price for crude oil from $2.10/barrel in the spring of 1973 to $10.50/barrel in the spring of 1974 (Claes 2001: 172). At the same time, several oil-producing states in the Middle East nationalized their oil industries, and the international oil companies needed to replace their exploration and production in that region. The Alaskan discoveries were very timely for the companies. The oil production in Alaska increased rapidly around 1980, as shown in Figure 5.2. The political turmoil in the Middle East created the second oil price shock with an increase from $13.80/barrel in the autumn of 1978 to $38.80/barrel in the autumn of 1979. After a peak in 1988, Alaskan oil production has fallen gradually. The total historical production of oil and gas in

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Alaska constitutes more than 16 billion barrels of oil and 6 billion cubic feet of natural gas. In 1988, Alaska accounted for almost 25 percent of US oil production. In 2015, this share was down to 5.1 percent (US EIA 2016b). Although production is declining, there is a potential for further development of Alaskan oil and gas resources. A 2002 USGS assessment of the National Petroleum Reserve–Alaska resulted in a mean estimate of 10.6 billion barrels of oil and 61.4 tcf of natural gas (USGS 2002). An assessment of the separate Arctic National Wildlife Refuge gave a mean estimate of 10.4 billion barrels of technically recoverable oil and 7.7 tcf of natural gas (USGS 2002). In 2006, the US Department of Interior, Minerals Management Service (MMS) (now known as the Bureau of Ocean Energy Management), estimated the offshore region of the Beaufort Sea only and found mean recoverable oil at 8.22 billion barrels and 27.7 tcf of natural gas. With huge geological structures, the continental shelf under the Chukchi Sea region also offers great promise. The MMS estimated a mean of 15.4 billion barrels of oil and 77 tcf of gas under the Chukchi Sea (US Department of the Interior 2006: 6). Royal Dutch Shell had been the most ambitious company in Alaska in recent years. However, concrete results were lacking. Shell spent about $7 billion on leases, rents, and drilling activities without a single commercially viable drilling operation (Katakey and Zhu 2015; Mufson 2014). Although having identified a major oil reservoir in the summer of 2015, the combination of weak prospects of further discoveries, the dramatic fall in oil prices, and increased regulatory restrictions by the Obama administration, made the company abandon all offshore drilling activity in the Arctic in September 2015 (Barrett 2015). In December 2016, US president Barack Obama invoked the 1953 Outer Continental Shelf (OCS) Lands Act to block indefinitely energy development in the Arctic and Atlantic Oceans. Simultaneously, Canadian prime minister Justin Trudeau announced a similar move to designate all Canadian Arctic waters as indefinitely off limits to future offshore oil and gas licensing, although this decision would be reviewed every five years. The withdrawal areas announced by Obama encompass 3.8 million acres in the north and mid–Atlantic Ocean off the East Coast and 115 million acres in the US Arctic Ocean. The Arctic withdrawal encompasses the entire US Chukchi Sea and significant portions of the US Beaufort Sea (Dlouhy and Wingrove 2016). Most of the present Norwegian oil and gas activity is located south of the Arctic Circle. However, a new province is opening in the Barents Sea. Development of oil and gas activities in this area gained new momentum Norway

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after the delimitation agreement between Russia and Norway. Until this agreement, the parties had a mutual moratorium on oil and gas exploration in the contested area. The uncontested part of the Norwegian Barents Sea was opened for petroleum exploration in 1979, and the first exploration well was drilled the following year. About 130 exploration wells have been drilled in this area. Until recently the results have not been very encouraging. With the delimitation agreement, the previously disputed area can be opened for petroleum activities. Minutes after the agreement entered into force in July 2011, the Norwegian petroleum authorities started acquiring seismic data in the area. After exploratory wells drilled in the region, one gas field (Snøhvit) and one oil field (Goliat) have become operational. Snøhvit is the only producing gas field in Norway’s Arctic region, and it is the most northerly operating gas field in the world. The Goliat oil field was discovered in 2000, and development was approved by authorities in 2009. Production finally began in March 2016. Italy’s Eni is also operating this field. The Norwegian government seems determined to develop the region. In spring 2016, ten licenses were awarded to thirteen companies, with assigned exploration programs. These awards were challenged by Greenpeace Nordic and Nature & Youth, who claimed that the licenses fly in the face of the Paris Agreement, and thus took the government to court. The case will be heard at Oslo Crown court in 2017. It will be the first of its kind in Norway. In the autumn of 2016, the Norwegian government announced yet another licensing round, with the prospect of further exploration in the Norwegian part of the Barents Sea. Statoil is eagerly anticipating an aggressive drilling program there, including the northernmost well ever drilled—Korpfjell, near the Russian border (Holter 2017). Northern Canada holds about one-quarter of Canada’s remaining discovered resources of conventional petroleum. One billion barrels of oil and 19.8 tcf of gas are estimated to reside there. Present production from the Arctic areas is low. The main areas are Mackenzie Valley and onshore Yukon, with twenty-six significant discoveries and three producing fields (the Norman Wells oil field and the Kotaneelee and the Pointed Mountain gas fields); Arctic Islands, with nineteen significant discoveries, but no production at present; and the Mackenzie Delta/Beaufort Sea, discovered resources of more than 1 billion barrels of oil and 9 tcf of gas in fifty-three significant discoveries. Four trillion cubic feet of marketable gas have been identified in three onshore and offshore discoveries, including over 200 million barCanada

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rels in the Amauligak field. On the Mackenzie Delta, the Ikhil gas discovery is being developed to supply natural gas to the town of Inuvik. Chevron and Statoil have plans for exploratory drilling and a substantial seismic program in the Beaufort Sea, while ExxonMobil and BP jointly hold lease rights to more than a million acres in the Beaufort Sea through at least 2028 (Jerving et al. 2015). However, at present, these companies have either suspended exploratory drilling activities or anticipate no offshore drilling activities in the near term. Compared to the Canadian oil sands reserves, the conventional Arctic oil fields will likely be of marginal importance. The Canadian oil sands constitute more than 9 percent of global oil reserves and produce over 2 million barrels of oil per day. Arctic exploration has not been very successful, and the drilling costs are high. It is unlikely that the Canadian Arctic will be a major oil or gas province in the foreseeable future. However, the Arctic is of great political importance, and Canada will continue to be an important actor in Arctic affairs. As indicated already, the USGS finds the areas offshore of Greenland among the most promising for the location of recoverable oil and gas reserves. Following the development of the North Sea oil province, five exploration wells were drilled outside Greenland in the 1970s and one in 2000, with no commercial discoveries. All licenses were returned to the government in 2001. The government drew up another plan and since 2002 about twenty licenses have been awarded for exploratory drilling offshore West Greenland. Cairn Energy has conducted exploration drilling, but the total number of exploration wells, including those drilled in the 1970s, amount to only fifteen. No commercial discoveries have been made so far. The latest attempt to date was made in autumn 2011, by Cairn Energy, with an unsuccessful drilling in the West Disko area (Macalister 2011). The government that took office in March 2013 is more reluctant to support oil and gas activity than its predecessor. It has proposed a very moderate policy as it intends to hand out new licenses only as old licenses are turned in. The most active foreign company in Greenland is the Scottish-based Cairn Energy. Cairn has been operating in Greenland since 2007, and it is the largest acreage holder of offshore Greenland. The company drilled eight exploratory wells in 2010 and 2011. In 2014, Cairn put its operation in Greenland on hold. Statoil, GDF Suez, and Dong Energy have all withdrawn from awarded licenses after the oil price collapse, beginning in late 2014. Statoil holds on to one single license, as it has an exploration period until 2029. Greenland

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The Cairn drilling operation has received criticism from Greenpeace for leaking 225 tons of toxic materials into the sea. Also, representatives of Greenland’s fishery industry have voiced concern regarding the consequences of potential oil spills. The Macondo accident in the Gulf of Mexico also raised skepticism about Greenland. Generally, Arctic waters are regarded as more vulnerable than other oil provinces in case of oil spills. One key reason for this is that the cold temperature prolongs the breakdown of the oil spilled. Oil and gas drilling are made more difficult by the potential for permanent or drifting ice. This is the situation for the offshore areas northwest of Greenland. The southern part of Greenland is below the Arctic Circle and not very exposed to the ice problem. The air temperature, also used to define the Arctic region, is lower on Greenland than for Norwegian areas at the same latitude. On the political level, Greenland has a strong incentive to accelerate exploration, investment, and production. The 56,000 inhabitants on the island are presently not economically self-sufficient. The annual transfers from Denmark constitute about $10,000 per capita. Although self-rule has been granted in a number of governance areas, full independence from Denmark would require a more solid economic basis than what is the case today. Increased revenues from oil and gas production are the likeliest way to achieve independence. Sovereign Claims and Jurisdiction in the Arctic

One of the most spectacular recent Arctic events was the Russian flag-planting on the subseabed at the North Pole in 2007 (Struck 2007). Although the expedition made international media headlines, it had no legal, jurisdictional value. As Canadian minister of foreign affairs Peter MacKay commented: “This isn’t the 15th century. You can’t go around the world and just plant flags and say we’re claiming this territory” (CTV News 2007). Furthermore, as Michael Klare points out in this volume (see Chapter 2): “the risk of tension and conflict in the Arctic is further exacerbated by the determination of key regional policymakers to rely on military power to reinforce their claims to prized Arctic real estate.” In some cases, Arctic states have agreed to settle territorial disputes before allowing for oil and gas exploration. Russia and Norway had a moratorium on all kinds of exploration for more than forty years until their delimitation agreement. When discussing state jurisdiction in the Arctic region, it is important to separate sea and seabed boundaries. Key concepts regarding sea boundaries are the distinction between internal waters (inside the baseline), territorial sea (12 nautical miles from the baseline) and exclusive economic

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zones (200 nautical miles from the baseline). Alf Hoel identified eight maritime boundary issue complexes in the Arctic, of which four are bilateral: in the Bering Sea, the United States and Russia agreed to a delimitation line in 1990, but Russia has not yet ratified the treaty; in the Beaufort Sea, the boundary line between Canada and the United States has not been settled (Hoel 2009: 87–90). There are also two disputed boundary areas between Greenland and Canada. When comparing the map of the USGS appraisal of oil and gas resources and the map of the territorial claims, it is clear that only a very small fraction of oil and gas resources will be beyond state jurisdiction. The amount of oil and gas in these remaining disputed areas is very small and would have very high production costs. As a result, nearly all potential oil and gas development will take place in areas that are under undisputed jurisdiction of one of the five coastal states. In cases where oil and gas fields extend across territorial borders there will be precedence for so-called unitization agreements. The delimitation agreement between Norway and Russia in the Barents Sea in 2010 has a separate protocol on such unitization of field development (Norway Foreign Ministry 2010: Art. 5). This treaty requires that deposits of hydrocarbons crossing the border must be developed in cooperation between the two parties and is in line with the similar agreement between Norway and the United Kingdom in the North Sea. In the Arctic, the continental shelves of the five Arctic states (United States, Canada, Russia, Norway, and Denmark/Greenland), extend beyond the exclusive economic zone of 200 nautical miles. The coastal states are required to submit documentation to determine the extent of their continental shelves to the UN Commission on the Limits of the Continental Shelf. This commission reviews the submissions in accordance with established guidelines and makes recommendations regarding the outer limits claims on the continental shelf of each state. At the time of this writing, Norway has gained such a recommendation based on its submission. Russia submitted its documentation to the commission in 2001, and the commission found the substantiation of the Arctic claim insufficient and asked for more information. Since then a new submission was prepared and it was submitted on August 3, 2015. Canada and Denmark submitted their claims in 2014. Canada, Russia, and Denmark all lay claim to overlapping areas under the North Pole, and they will engage in negotiations to settle these claims. The UN commission has no authority to determine competing claims. If states do not agree with the recommendations, the case could be referred to the International Court of Justice in The Hague. The fifth coastal state, the United States, has not ratified the United Nations Convention on the Law of the Sea (UNCLOS) treaty due to opposition in Congress. The United States is still eligible to claim an extended continental shelf and has cooperated

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with the other countries in accordance with the treaty. The US government has established an interagency body (the Extended Continental Shelf Task Force) to determine the extent of the US continental shelf. In 2015, a demand for a more active Arctic policy emerged in the United States. The National Petroleum Council (2015) published a report, Arctic Potential—Realizing the Promise of U.S. Arctic Oil and Gas Resources. The message in the report was that the United States lagged behind the other Arctic states in developing oil and gas resources. Furthermore, these leaders of the US oil community argued that nonratification of the UNCLOS treaty was hurting US strategic and economic interests in the Arctic. Scott Borgerson argued similarly, while renouncing his former perspective that anarchy was coming to the Arctic with the potential for armed brinkmanship. He now salutes the cooperative strategies of the five coastal states, particularly the Ilulissat Declaration of 2008, wherein all parties agreed to adhere to the UNCLOS procedures for handling overlapping territorial claims (Borgerson 2013).4 His main concern is the lack of US ratification of UNCLOS and a passive Arctic policy. There is obviously room for a more active US presence in Arctic affairs. However, sharp conflicts among the five coastal states are not likely (Dodds 2016). They all have an interest in putting up a common front against external actors trying to gain access to Arctic resources. Apart from the sovereign coastal states, there is the Arctic Council, established in Ottawa in 1996, and it plays a vital role in the governance of Arctic affairs. The aim was to create an intergovernmental forum for cooperation, coordination, and interaction among the Arctic states. In addition to the five coastal states noted above, Denmark, Iceland, and Sweden are full members of the council. Several groups of indigenous peoples are permanent participants as well. Furthermore, twelve non-Arctic countries have been admitted as observers.5 Given the perception of increased activities in the Arctic, the Arctic Council has initiated cooperation and confidence building among member states, particularly in providing common and necessary infrastructural services. Two recent legally binding agreements typify the degree of cooperation: the 2011 Agreement on Cooperation on Aeronautical and Maritime Search and Rescue; and the 2013 Agreement on Cooperation on Marine Oil Pollution, Preparedness and Response. These are the first legally binding agreements negotiated under the auspices of the Arctic Council, signaling an increasing role for the organization. Growing intergovernmental cooperation in the Arctic is buttressed by increasing cooperation among commercial actors. The structure of the global oil industry has become more integrated as it has become more complex. New state oil companies have emerged from producing and consuming states, and several mergers and acquisitions have occurred, all while leading

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oil companies continue to outsource engineering and technological services to more specialized firms. As a result, cooperative arrangements among and between national and private oil companies have exploded. Interestingly, and perhaps because of this burgeoning complex interdependence, neither national nor private firms can monopolize the necessary input factors for oil and gas production (Claes 2011: 308–310). This is particularly the case where the economic risks are high, because the companies seek many partners for burden-sharing, which creates many opportunities for input factors to be made more common among them (Alloway 2016). The Arctic is a prominent case in this respect. The oil companies operating in the Arctic often create various forms of cooperation to share costs and reduce risks. There is a potential for high cost overruns because Arctic operations face environmental and climatic challenges unseen in other regions of the world. The time from discovery to production will most likely be much longer for Arctic projects than for those in established oil and gas provinces. Because the Arctic is a more remote place, infrastructure investments are much higher, even compared with other unconventional petroleum regions, such as the deep waters in the Gulf of Mexico. Cooperation among companies from different countries across the world is the order of the day in the modern oil industry. When investing in a novel region such as the Arctic, the companies demand the utmost level of political stability. The required cooperation among the companies will add to the push for political cooperation, not conflict, among the Arctic states. Nonetheless, the exchange of sanctions between the US and European states on one side and Russia on the other has hurt cooperation between the Western and Russian oil and oil-service companies. However, an interesting split has emerged between the United States and Europe. ExxonMobil’s joint venture with Rosneft is temporarily frozen, but many European oil companies continue to develop their cooperation with Russian companies (Farchy 2016, 2015; Staalesen 2016). One can only speculate whether this is a sign of the unsustainability of the present sanctions. Conclusion

There are many popular views concerning Arctic oil and gas resources. First is a perception that these resources are gigantic compared to the resources in the rest of the world. Second, these giant oil and gas resources are in a no-man’s-land, open to a modern land grab by any person or country able to occupy the territories, if necessary by military means. Third, the Arctic coastal states are first in line in this resource race, locked in a fierce zerosum conflict with each other, possibly on the brink of using force (Conley

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and Rohloff 2015). These widespread views are really myths, and they are all wrong. Arctic resources are substantial, but not of immense global importance, especially not when considering the vast production from the previously untapped unconventional shale oil and shale gas resources. There are almost no areas of no-man’s-land in the Arctic. The few areas outside state jurisdictions are of little importance to petroleum activities. All the Arctic coastal states, in word and deed, adhere to the regulations and processes prescribed by UNCLOS in determining their border disputes and demarcations of their continental shelves. Furthermore, the amount of oil and gas that can eventually be subject to profitable commercial extraction in the Arctic, especially offshore, is highly uncertain. The likelihood of largescale Arctic production has been reduced further by the oil price decline since late 2014, Royal Dutch Shell’s suspension of drilling offshore Alaska, and the many delays in exploration and drilling announced by other firms and states. Finally, the harsh climatic conditions and the long distance from remote production to any final market are important cost factors and potential obstacles to development of oil and gas resources in the Arctic region. At present and in some parts of the Arctic, there are important oil and gas provinces, such as Alaska, the Barents Sea, and most important in Russian onshore and coastal offshore areas. These will continue to be important provinces. If commercially viable discoveries are made in Greenlandic territories, these will most likely be developed because they can serve as an economic tool for independence from Denmark. The Arctic oil and gas provinces will be of some importance, but they will by no means serve as a game changer in the global oil and gas markets. Even more important, the Arctic oil and gas resources are unlikely to be the subject of political or military conflict among the Arctic states. Notes

1. Converted to oil equivalents, the figures are 12,833 BOE, 25,783 BOE, and 49,833 BOE with a mean of 27,817 BOE. 2. For comparison, the Arctic Ocean is 14,056,000 km2 and the Persian Gulf is 251,000 km2. 3. A table of the estimations for the provinces are found in USGS 2008. 4. See the text of the Ilulissat Declaration at http://www.oceanlaw.org/downloads /arctic/Ilulissat_Declaration.pdf. 5. These are France, Germany, The Netherlands, Poland, Spain, United Kingdom, China, Italy, Japan, South Korea, Singapore, and India.

6 The US Energy Complex: The Price of Independence Timothy C. Lehmann You know, there’s no doubt in my mind that one of these days, instead of people driving up to a gas station they’re going to be going up to a fueling station. And they’ll be able to have choices to choose from. Got a hydrogenpowered car, you’ll be able to have that choice. If you want 85 percent, maybe someday 100 percent, ethanol, that’ll be an option available, too. —President George W. Bush (April 25, 2006)

The all-of-the-above energy strategy I announced a few years ago is working, and today, America is closer to energy independence than we’ve been in decades. One of the reasons why is natural gas. . . . This Congress can help by putting people to work building fueling stations that shift more cars and trucks from foreign oil to American natural gas. —President Barack Obama (January 28, 2014)

In less than a single decade, US presidents have promised “freedom cars” running on US-produced hydrogen or ethanol as well as natural gas–powered vehicles as a necessary corollary to an American energy “renaissance” based in shale oil and natural gas. In these visionary assessments, the “fueling station” infrastructures for these new fuels seamlessly come into existence, as will the monumental transformation of industrial engine and vehicles production to run on these alternative fuels. Presumably, customer choice and the much-ballyhooed abundance of alternative fuels will spontaneously create these necessary infrastructure and industrial production realities. Not to be delimited by energy and industrial progress for their own sake, these presidential proclamations have always had an explicit object of securing US energy independence and liberating the United States from an “addiction” to the “tyranny of oil,” particularly Middle Eastern oil. This rhetoric and the widespread American belief in a happy marriage among abundant energy supplies, excessive consumption, and political independence have endured in similar fashion since the oil shocks of the 1970s. Public declarations by US leaders at the highest levels have usually been tinged with odd admixtures of utopian faith in industrial and techno105

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logical progress coupled with semi-xenophobic misrepresentation of the function of Middle Eastern oil within the US hegemonic system. The United States has never relied inordinately on the Middle East for domestic oil consumption, and there have been precious few significant displacements of oil in the domestic consumer market. As is true across the world, oil also remains the dominant energy type. For the United States, in 2015, oil was 36 percent of the total energy mix, and of course it has negligible alternatives in its primary transportation end use. These facts persist and challenge our understanding of how the interrelated US and global energy systems work to sustain a founding ethos of the postwar US system—the orderly provision of energy supplies for maximum mobility and growth with fleeting concern for efficiency or the environment. This chapter examines the roots and current predicament of the US pursuit of a version of hemispheric energy and political autonomy in conjunction with its long-standing dominance over the Middle East for the purpose of influencing others (Brzezinski 2003/2004). Whereas other sources of US energy supplies are addressed, oil and to a lesser extent natural gas are the focal points of the chapter because they continue to dominate elite calculation and are primary to the pivotal transportation end use. The chapter demonstrates that although there are indeed abundant energy supplies for North American hemispheric autonomy, there has been no escape from a deeply embedded socioeconomic infrastructure dominated by climateharming fossil fuels, particularly oil (Heede 2014; Groom 2013). Somewhat paradoxically, the United States dominates the Middle East to influence others who, like the Japanese and Germans, pursue greater efficiency in energy use while the United States continues to insulate its relatively inefficient domestic sphere, particularly from allied industrial challengers and potentially hostile energy producers. The United States defines its domestic sphere quite broadly to include North America and usually the whole of the Western Hemisphere. Unsurprisingly, this sphere has seen the least progress away from inefficient fossil fuel use; instead, unconventional energy sources have been developed including Canadian tar sands and the shale oil and natural gas of the Dakotas and Texas. This is as it has always been in the postwar era. At this point, US leaders’ optimistic calls for oil-free energy independence ought to ring as hollow as an empty oil drum. For example, to date there are precisely zero 100 percent ethanol vehicles on US roads, and the hydrogen revolution has largely fizzled, as there were only approximately thirty-three hydrogen fueling stations in the United States in early 2017 (US Department of Energy, Alternative Fuels Data Center [DOE AFDC] 2017). In 2010, there were a total of 421 hydrogen fuel vehicles on US roads, while compressed natural gas powered only about 115,000 vehicles. Despite their expanded presence and improved environmental performance in heavy-duty trucking, for example, the total number of natural gas vehicles in use now may actually

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be down from a peak in 2002, when 311,227 were in use (US DOE AFDC 2017; Cardwell and Krauss 2013; Energy Vision 2013). These 311,227 vehicles in 2002 had some form of natural gas—compressed, liquefied, or liquefied petroleum gas—powering them, but the total in 2010 was only 262,254 (Oak Ridge National Laboratory 2012: 92–95). More narrowly, in 2010, there were only a little over 3,000 liquefied natural gas (LNG)–powered vehicles in the United States. If natural gas and LNG in particular are the future of US transportation fuels, they have a very long way to go. Of course, ownership of hybrid and all-electric cars is rising, but they remain a small fraction of sales, with only 382,704 hybrid electric vehicles sold in 2012, in an overall car market near 15 million. In contrast to Daniel Yergin’s claim that US energy use is twice as efficient as in the 1970s (Yergin 2009: 94), the relatively inefficient structure of US oil demand remains largely intact, with 71 percent of US oil consumption in 2015 going toward the primary end use as transportation fuel (US EIA 2016c: 61, 67). Even more inconsistent with Yergin’s opinion, per capita oil use in the United States would likely still be rising if the oil embedded in imported products were factored in, such as in the plastics imported from China (Bradshaw 2013: 44). Figure 6.1 shows per capita oil use in the United States actually rising from 1985 to 2005, with only a slight decline in recent years due to the economic contraction beginning in 2007–2008. US oil demand basically ebbs and flows with economic growth, while incremental supply needs are simply being met by the development of more costly conventional and unconventional hemispheric resources. The unconventional energy revolution in the Americas is about supplementing declining conventional energy production to maintain the existing structure of energy demand, not to replace it. More important, it is about preserving a hallowed strategic tradition of obtaining the vast majority of energy resources necessary for domestic US consumption from the friendlier confines of the Western Hemisphere. The Role of the Middle East in US Management of the Postwar Energy System

The infrastructure for a culture of outsized US oil consumption grew directly from the dominance of US oil, which secured victory in World War II (Painter 2012; Goralski and Freeburg 1987). Given the large-scale demand by the United States and its allies in the war, US concern for sufficient oil reserves for the postwar period informed a great deal of the internal and allied debate among US and British leaders in the last years of the war. President Franklin D. Roosevelt’s petroleum coordinator for war, Harold Ickes, played an important role in these debates, and he sounded an alarm in January 1944, when he published an article titled “We’re Running Out of

Figure 6.1 US Oil Trends, 1918–2014

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Oil” (Ickes 1944). Quite reasonably, he feared that the British were maneuvering to corner future production and trade markets from the oil reserves of the Middle East. Britain had done this after World War I to the potential long-term detriment of the United States. Because the United States continued to supply nearly 70 percent of the allied oil needs in the war through excessive US production, this necessarily depleted reserves, raising the fear again for US control of adequate future oil reserves. Anglo-American jockeying for postwar position in the Middle East threatened allied unity, requiring an intervention by the principals. In February 1944, Roosevelt and Winston Churchill guaranteed each other’s exclusive spheres in Saudi Arabia and Iran, respectively, in the cheeky language of not “horning in” or casting “sheep’s eyes” on the other’s Middle Eastern “possessions” (Stoff 1980: 148–150). Irrespective of the principals’ agreement, Ralph Davies, the deputy petroleum coordinator to Ickes on leave from Standard Oil of California (Chevron), cautioned his civilian superior that he had overstepped the facts in his January 1944 article. In March 1944, Davies wrote Ickes: If you do not reasonably recognize the possibility of additional large discoveries in this country, the potentialities of technological advance, the practicability of conversion of hydrocarbons in other forms of gas, tar sands, etc., and the very large possibility of secondary recovery, you will have left the door wide open to your opponents to come in with an endless amount of factual data supporting their position that a shortage is not in fact imminent and that there is no basis for “scare.” (DeNovo 1989: 94)

In his remonstration of Ickes, Davies captured an enduring truth. US energy abundance was then, as it is now, largely boundless provided all hydrocarbon resources are included, technology does advance, and market actors and relative prices facilitate unconventional hydrocarbon development and enhanced recovery. Despite the technical feasibility of making fuels from tar sands, or even coal as the Germans were doing at this time, US officials focused on conventional oil reserves, production, and trade relationships as they understood them. Ickes failed in his bid for the US government to purchase the Saudi Arabian concession of Standard Oil of California and the Texas Company, and the structural power of the US oil industry was channeled into selling a vision of abundant energy for world development, absolving the need for an intrusive statist approach to the US national interest in oil (Citino 2010: 233, 250; Stoff 1980). In April 1944, US State Department petroleum adviser Charles Rayner epitomized the growing “propaganda of plenty” when he framed the postwar era as one where the “global sources of petroleum are sufficient for all needs for many years to come,” and the management task was to see to the “orderly development and orderly distribution of abundance in an economy of plenty” (DeNovo 1989: 96).

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The only real dilemma for US policymakers was balancing the growing production of cheap Middle Eastern oil with the existing high volumes of higher production cost oil by a great many politically salient actors in the Western Hemisphere. For example, unlike the more parochial domestic independent oil firms, the major international oil companies (IOCs) had vast interests in overseas oil and a long history of patterned relations with the US state. This freed the IOCs from strictly domestic US calculations, which in turn helped them pursue increased autonomy from the US state. As a result, they grew ever more indispensable, eventually becoming the formal delegated “instruments” of US policy abroad (US Senate 1975: 65–66). In broad form, after the war, US officials fused domestic considerations for independent oil companies’ interests in a protected domestic US market with the strategic need to cement the alliance with Britain in the Middle East while fulfilling allied demand in Europe and Asia Pacific. US officials forged unity among all the major Anglo-American-Dutch IOCs and protected the domestic US market from undue non-hemispheric import competition (read: cheap Middle Eastern oil) while also preventing Soviet expansion against this most vital future pumping station for the world economy (Little 2008: 48–65; Marsh 2003; Kuniholm 1980). The resulting arrangements crystallized in the early 1950s. The Korean War, the Iranian nationalization, and the subsequent coup in August 1953, all required the United States to resolve the dilemmas to the minimal satisfaction of the Western parties and, more important, strike some balance among Middle Eastern and Western Hemisphere oil producer interests. In January 1948, James Forrestal, US secretary of defense, forecast part of the operating logic of US hegemony before a Congress eager to understand how to forestall ruinous domestic price competition from imported Middle Eastern oil while also meeting dynamic growth in domestic and Allied oil demand. In a particularly American way, Forrestal noted the mutuality of interests in the US natural dominance of Middle East oil: The existence of oil in the Middle East is of consequence to the world, and its use is vital in terms of energy fuel and is of interest to the whole human society. It so happens that American business and American technique get that oil out faster than anybody else, and it should be made available not only to us; that oil will not, as you know, flow to this continent except as we bring in limited amounts. It will flow mostly to Europe and the Far East. (US Senate 1948: 25, 290)

As Figure 6.1 depicts, even in 1950, the United States was still producing 52 percent of the world’s crude oil. But it was clear to all strategic decisionmakers that the Middle East was the world’s future crude oil production and export platform. Following Forrestal, US leaders placated domestic independent oil producers and their political allies in Congress, primarily from inland regions such as Oklahoma and Texas, by raising bar-

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riers to imported Middle Eastern oil, which threatened to displace the nonIOC independent US producers in particular. Emblematic of then-Senator Lyndon Johnson’s political ascendance from this oil patch, in 1955, he implored US secretary of state John Dulles to ensure that Iranian oil returning to world markets would not “result in further increases in already heavy imports of oil into the United States . . . that care was to be taken to see that this oil did not serve to jeopardize the position of US independents in supplying domestic requirements” (US Senate, Subcommittee on Multinational Corporations 1975: 560). Unlike today, the center of the oil world’s power elite immediately after the war remained on the oceanic coasts, particularly with the Standard Oil progenitors in New York (Mobil), New Jersey (Exxon), and California (Chevron). These postwar US oil complex leaders, epitomized by John J. McCloy, could readily insulate Western hemispheric production and domestic demand to appease the independents of the mid-American continent by having the IOCs’ control over Middle Eastern oil flow to the “natural market outlets” in Europe and the Far East (Bird 1992; Isaacson 1986: 570–575). Middle Eastern oil was essential to US influence over these allied yet dependent regions, as a system of US dollar–priced Middle Eastern oil became the core of economic redevelopment in Japan and elsewhere in the US hegemonic firmament (Lehmann 2013; Stokes 1994). At bottom, the system meant dollar-priced Middle Eastern oil flowed to US allies in Europe and Asia, who redeveloped their postwar industrial and transport systems on an oil basis while also pursuing export-led growth models based on exports to the US consumer market. The United States discriminated positively in favor of these allied imports and against its own manufacturers of various goods, purposively choosing a path of US deindustrialization, trade deficit promotion, and the use of US consumerism to tie dependent ally spokes in to the US hub. As long as US consumers could purchase these imports and allied exporters earned enough dollars to pay for oil imports to fuel their own growth, the system maintained itself. The resulting “oil triangle” of industry and trade undergirded US hegemony vis-à-vis dependent allies and the Soviet and Chinese adversaries as depicted in Figure 6.2 (Sugihara 1993). In 1949, George Kennan saw the strategic benefits in controlling others’ energy imports, and in Japan’s case he noted: “If the US created controls foolproof enough and cleverly enough exercised really to have power over what Japan imports in the way of oil and other things as she has got overseas, then we could have veto power over what she does” (Hein 1990: 204). The United States enjoys the benefits of this system to this day. For example, the simple oil-based influence position explains the US military and commercial presence in the Middle East and, of course, much of the strategic reality of the Iraq wars as well as the Libyan campaign in 2011 (Kirkpatrick 2014; Cafruny and Lehmann 2013; Gilpin 2005). Despite the demonstrated US interest in influencing the disposition and intermediation

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Figure 6.2 The Oil Triangle

of oil near its production site, I argue in contrast to nearly all other international relations scholars that the strategic purpose of Middle East oil has never been a liberal-derived concern for domestic US consumption.1 In fact, in the whole of the post–World War II era, the Middle East never supplied more than 38 percent of total US crude oil imports, and the Middle East has not supplied even 25 percent since the early 1980s (see Figure 6.3). The most recent peak year of US reliance on Middle Eastern crude oil imports was 2005, when the United States consumed a postwar record 20.8 million barrels of oil per day (mbd) and imported about 2.2 mbd of Middle East crude oil. Even in this year, Middle East oil comprised only 22 percent of total US crude oil imports and 10.6 percent of total domestic US oil consumption. During the most politically significant early peak year, 1955, the Middle East supplied 35 percent of US crude oil imports, but this was only 3.2 percent of total US oil consumption. As important, the United States only took 10.4 percent of total Middle Eastern crude oil exports in 1955, less even than the fledgling Asia Pacific region, which took 11.3 percent (United Nations 1960: 94–99). In response to the potential flood of cheap Middle Eastern oil in the mid-1950s, the Eisenhower administration began ratcheting up its voluntary import quota system, which it then codified in formal mandatory terms in 1959 (Barber 1980; Bohi and Russell 1978). These “drain America first” policies remained in effect until 1974, when the United States formalized its piecemeal adaptation to higher priced and politically hostile oil players by fully supporting investment in more expensive oil resources in Alaska and the deeper waters of the Gulf of Mexico, the British North Sea, and elsewhere (Priest 2007: 191–192; Little 2008: 73; Parra 2004: 249–256, 267–

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270; Shwadran 1974: 548). These investments would take time to yield increased Western and Western hemispheric autonomy, and in the meantime, the United States permitted Middle Eastern oil imports in greater measure. But even in 1977, the peak year of US reliance on Middle Eastern oil for domestic consumption, Middle Eastern oil comprised only 13.6 percent of total US oil consumption. Simply put, despite these few individual years’ obvious salience, in the whole of the postwar era, the Middle East has not mattered inordinately to domestic US oil consumption, nor has the US market mattered that much in total Middle Eastern crude oil exports. The region’s significance inheres in others’ reliance upon it. This is particularly true now for the Asia Pacific region, which, as Figure 6.3 illustrates, displaced Europe in the middle 1980s to become the largest recipient of Middle Eastern oil. The vast stores of Middle Eastern oil have been essential to US hegemony. The United States has dominated the Middle East because the region routinely accounted for at least 60 percent of world crude oil exports from the middle 1950s forward, and even in 2012, 46 percent of the world’s traded crude oil came from the Middle East (OPEC 2014: 49, 1980: xxi). Globally, US IOCs have managed postwar energy abundance while the Figure 6.3 Middle East Crude Oil Exports by Destination, 1955–2014 70

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Middle Eastern national oil companies (NOCs) have been junior partners to these US oil majors, somewhat less integrated in the US-led system than Royal Dutch Shell and British Petroleum. Saudi Aramco’s partnership with Royal Dutch Shell in the Motiva refinery in Port Arthur, Texas, was emblematic. This is one of the largest US refineries and was formerly controlled by Texaco, until it sold its interest to its partners Royal Dutch Shell and Aramco when it formally reunited with Chevron in 2002. The recent US oil services companies’ retrofit at Motiva makes it capable of processing not just more heavy sour crude from Saudi Arabia, but also Venezuelan heavy crude and even Canadian diluted bitumen from the tar sands operations. This multipurpose heavy and unconventional crude processing capability yields the added benefit of making Motiva the largest pet coke producer in the United States (Callus 2013; Krauss 2013; Stockman 2013). In this as in many other projects, these two exemplars of potential NOC and non-US IOC market power were bound more deeply into the US market, despite their current negotiations over severing this particular ownership arrangement. Regardless of the peculiarities of the North American market, because they are still both vested participants in the US system, Aramco and Royal Dutch Shell continue to support and not seriously challenge a primary US national interest in a Western Hemisphere free from excessive dependence on extra-regional energy supplies. This is true because US partnership with these two foreign oil actors is of course far deeper than one refinery. Royal Dutch Shell is the key junior partner to ExxonMobil at the West Qurna–Mishrif reservoir in southern Iraq, which is the second largest oil and gas reservoir in the Middle East after Ghawar in Saudi Arabia. This most recent partnership in Iraq between ExxonMobil and Royal Dutch Shell flows naturally from their global leadership in developing offshore oil and natural gas. For example, in 1971, they discovered and still jointly own and operate the Brent field, and they have operated the oldest and most significant natural gas project in continental Europe at the Groningen field near Slochteren in the Netherlands (Pals 2013; Stern 2012: 54–57). Saudi Arabia’s partnership with the United States is equally long-standing. It began with Chevron’s purchase of an exclusive concession there in 1933, which President Roosevelt cemented with his seemingly permanent designation of Saudi Arabia as “vital” to US defense in the 1943 lend-lease arrangements. US superintendence of Saudi oil by corporate proxy was given full flower in the April 1947 US attorney general waiver of antitrust concerns, when the four major US IOCs (Exxon, Mobil, Chevron, and Texaco) agreed to merge their Middle Eastern operations and jointly operate Saudi oil. Notwithstanding these and a great many other global arrangements with subordinate domestic and foreign partners, US management of the world’s energy system has always had two operating principles: first, delegate global management to the leading US IOCs and ensure their dominance over Middle Eastern and other vital resource areas; second,

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insulate the Western hemispheric bulwark from undue reliance on nonhemispheric sources of oil, while simultaneously using the largest and most open domestic market in refining and distributed oil products sales to bind in others’ self-interested operations. US strategic decisionmaking in oil and the broader construct of “energy” has been conditioned by policy pursuits and trade-offs among these two cardinal principles ever since the 1950s. Delegated US Oil Majors and the Insulated Western Hemisphere

While Japanese Prime Minister Shigeru Yoshida viewed the Korean War as a “gift of the gods,” most US officials viewed it as an extension of the burgeoning rivalry with the Soviet Union, which required even greater Western hemispheric energy coordination (Hasegawa 2005; Dower 1999). The Korean War and the Iranian nationalization spurred excess domestic US oil production and exports by boosting oil output 30 percent and exports by 23 percent in 1953, from the 1949 level (Bohi and Russell 1978: 22; US House of Representatives, Committee on Interior and Insular Affairs 1968: 5–6). As important, these supply and demand shocks in the early 1950s caused US leaders to view the whole of the Western Hemisphere as one energy bloc serving the US national interest. Pursuing hemispheric energy integration and insulation always entailed a balancing act between building influence positions in Europe and the Far East by controlling their Middle Eastern wellspring and defending against undue hemispheric energy resource depletion while avoiding excessive reliance on outside energy sources. As one part of this tricky balancing act, the United States embraced Canada as part of a single North American “strategic unit.” Canada’s energy resources were developed to mutual benefit, and “security of supply” for hemispheric defense and foreign operations was constantly improved. For example, Canada benefited from the extra-regional import restrictions during the Eisenhower administration because Canada and Mexico enjoyed special exemptions for their oil entering the US market, which raised Canada’s share of US oil imports from 4.9 percent in 1958 to 18.7 percent by 1967 (Randall 2005: 266, 282; Chester 1983: 34–46, 105–108). Furthermore, the major US IOCs dominated the development of Canada’s energy (Chester 1983: 105; Shaffer 1983). Like their southern neighbors in Mexico and Venezuela, unique US dependency patterns were created or simply maintained, such as those where Venezuelan crude could be best refined only by US Gulf Coast refineries (Corrales and Romero 2013: 65–78; Boué 2002). Across the formative years of the Cold War, it is now possible to see that Canada, Mexico, and Venezuela were granted special privileges in the US system as the United States delegated management of the world’s vital energy supplies to the leading IOCs under the special condition that they retain

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US and Western hemispheric relative autonomy in energy. The US IOCs were thus dually enfranchised to both manage world energy and insulate the Americas. Under many specific US government subsidization modalities, policy elites achieved a balance among these potentially conflicting objectives. For example, to influence other actors’ need for Middle Eastern oil, they appeased US-friendly potentates at US taxpayer expense as with the Saudi Arabian 50-50 revenue arrangement in 1950 (which itself simply followed the Venezuelan arrangement made during the war). Through this unilateral executive branch rule change, the US Treasury Department reclassified the royalty payments made by the four US majors in Aramco to the Saudi state and redefined them as foreign taxes worthy of full deductible credit against their US tax burdens. In so doing, the Treasury directly shifted the necessary political cost of Saudi revenue enhancement onto the US taxpayer via its deferential treatment of the US majors (Blair 1976: 196–204). Saudi stabilization for influence over others’ demand in Europe and Asia somewhat relieved the burden on Western Hemisphere oil supplies, but the US government never stopped binding in its hemispheric partners, particularly Canada, Mexico, and Venezuela. In a 1969 paper, the US Department of Defense noted plainly: In fact, for many years, the Department of Defense has promoted Western Hemisphere oil solidarity since its mobilization studies have shown that any type of extended emergency involving the United States and its allies could not be adequately fueled by the United States alone, and therefore, reliance must also be placed upon other free-world resources such as Canada and the Caribbean area. (US Department of State 2011: 38)

Even before some Arab members of OPEC embargoed oil in October 1973, the United States reacted to growing resource nationalism by pursuing energy projects in Alaska, Canada, and the Gulf of Mexico basin. A principal obstacle to improved hemispheric autonomy was the relatively greater cost of projects, such as Alaskan North Slope oil or deeper sea Gulf of Mexico plays. The steep run-up in prices across the early 1970s helped consolidate the decision to develop these more difficult hemispheric conventional oil plays. For example, because of the increased prices and governmental desire for hemispheric oil sources, Alaskan oil and the Trans-Alaska Pipeline became viable in the early 1970s, while North American shale oil and tar sand projects were left underdeveloped across much of the 1970s, with only pilot projects completed (e.g., Syncrude Canada’s 50 kbd plant completed in 1978). A sort of strategic reserve of unconventional “oils” was thus held in abeyance, while the 1970s price increases were tolerated in part to stimulate more expensive conventional oil plays, which also improved the IOCs’ position relative to the nationalizing states in OPEC (US Department of State 2011: 199–204; Parra 2004: 202–214; Rodman 1988: 266–268). Despite the

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urgent pleadings of several industry and government players in the United States and Canada, who wished to see Alberta tar sands fully developed, unconventional oil would have to wait (Sweeney 2010: 99–127; Nikiforuk 2008: 11–35; United Nations Institute for Training and Research 1979). During the 1970s adaptation, the United States varied its modal practices in support of its IOCs, but not the twin purposes of the US-led system. For example, the United States refrained from orchestrating coups against recalcitrant oil nationalists like it had done with Mohammad Mossadegh in 1953 or Shukri al-Quwatli in Syria in March 1949 (Little 1990: 278–280) and instead bargained with nationalists such as Colonel Muammar Gaddafi of Libya and Sheik Ahmed Zaki Yamani in Saudi Arabia. The United States demanded only that these actors accept the superiority of the IOCs’ overall position in world energy as the United States gave ground on formal ownership of the oil derricks. In October 1971, Robert Hormats, then an assistant at the National Security Council, noted the retained influence position of the companies in a memo to Henry Kissinger: In any such confrontation, the companies have more leverage than last year. Fuel stocks in Europe are higher. The tanker shortage has eased. In addition, the producing countries know that the companies are the only viable instruments for marketing oil in either Western Europe or Japan, and the nationalization effort will be extremely unprofitable unless the companies agree to market the oil. (US Department of State 2011: 223)

With the 1973 embargo, the long-standing ethos and practice of US government support morphed into over-identification with the plight of IOCs. As a result, the US pursued much more robust policies bolstering the IOCs’ position in the oil world. US officials acted as natural supporters of the US IOCs, believing them to underpin its global position because influence over Western Europe and Japan depended in large part on the IOCs. This corporatist governing philosophy crested with Lewis Powell’s infamous 1971 memorandum for the US Chamber of Commerce on behalf of a besieged corporate America (Phillips-Fein 2009). In the oil world, however, the US simply increased its immunization, subsidy, and support for the IOCs’ position, as it had been doing since the end of World War II. In a key unpublished Department of State briefing document from early 1974, titled “Role of the International Oil Companies,” the Nixon administration embraced the US IOC majors as key deputies of the US state. To Nixon and his top oil geopolitics staffers, including Peter Flanigan and James Akins, these venerable US oil majors were “under heavy attack from all quarters— the nations where they produce, those where they market, and even in their home countries.” In contrast to ignoble US citizens who believed their vital fuels were “in the hands of powerful, secretive companies,” the US government had to resist unenlightened domestic populism and, more important,

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help the companies, restive US allies, and the nationalizing states themselves see the “now irreplaceable services and technology” of the US IOCs. The companies were paramount “in the finding, producing, and orderly marketing of oil,” and the US government needed to help the IOCs in “carrying out their important and efficient services” by convincing all foreign actors to “want to keep the companies in the game and refrain from actions that would exclude them” (US Department of State 1974). US officials understood that maintaining relative leverage over subordinate allies and rising oil nationalists required supporting the companies’ positions across the oil world. This was even more valid for those “irreplaceable” technologies in upstream exploration and production and downstream refining and marketing operations. At every significant juncture since the 1970s, the United States has increased both its diplomatic support abroad and domestic immunization and subsidization of the IOCs. The United States has done so because the more difficult and costly oil of the Arctic, deepwater Gulf of Mexico, and now shale formations requires increased state incentives and protections. In all these hemispheric resource areas, the United States has pursued the principles of subsidiarity with the IOCs, delegating resource management and development to them as well as insularity, seeking hemispheric autonomy for the United States. In these arrangements the United States delegated authority to the IOCs and subsidized their ongoing search for advantage in producing more expensive and technologically demanding Western hemispheric energy resources. In so doing, the companies simultaneously improved their vast influence positions within allied states such as Japan as well as over energy producers such as Saudi Arabia (Fesharaki and Isaak 1983). For example, new seismology and drilling techniques for Gulf of Mexico plays born from Houston firms’ ingenuity filtered back into US IOC–OPEC relations in the Middle East, or IOC–East Asian relations for coastal offshore oil and gas in Bohai Bay or the East China Sea (US Department of State 2011: 288; Harrison 1977). The semi-independent states of the Middle East that wanted to develop their own offshore oil and gas reservoirs would have to partner with the technology-driven US oil majors. These majors were all pursuing the more politically favorable environment of offshore oil and gas development (Johnson 2010; Priest 2007: 270–278; IEA 1996). Reinforcing the Western Hemispheric Bulwark

Since the first oil shocks and adjustments of the 1970s, the United States has responded with remarkable consistency to the ebbs and flows in the geopolitics of energy. Whether one considers the price collapse of 1986 or 1998 or the price spikes resulting from the Gulf Wars of 1990–1991 and 2003, the United States has sought to expand US IOC control of world ener-

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gy. The United States has furthered this end by helping the companies merge their operations, as with the unprecedented consolidations of the 1990s, and subsidize more directly their costly and technically sophisticated plays within the Western Hemisphere in the 1980s (e.g., the section 29 unconventional fuels production tax credit provision of the 1980 Windfall Profits Tax Act). For example, in the 1990s, the United States underwrote deeper Gulf of Mexico drilling operations with the aptly named Deep Water Royalty Relief Act of 1995, and in 2004 the Securities and Exchange Commission (SEC) waived a long-standing flow test rule for booking reserves from deepwater reservoirs. The United States also effectively blocked any end use efficiency for many decades through what can best be described as a combination of malign neglect and Potemkin village projects such as the Partnership for a New Generation of Vehicles (Kolbert 2003). US average fuel economy rates were not raised once between 1985 and 2007, and US per capita oil consumption actually increased slowly across the 1990s, from 24.1 barrels per person per year in 1985, to 25.5 in 2000. Given the lackluster effort at demand-side reduction, both in the United States and globally, hemispheric and global supplies had to be vastly increased, and so they were. Annual offshore oil production from the increasingly important Gulf of Mexico region rose from 42 million barrels in 1994 to 348 million barrels in 2004 and, in 2012, 19 percent of total US oil production was from the federally administered waters of the Gulf of Mexico. In natural gas, the current repository for the hope of a cleaner fuels future, Gulf of Mexico production increased from 159 billion cubic feet in 1994, to 1.4 trillion cubic feet in 2004; in 2012, it was 6 percent of total US natural gas production (US EIA 2013g; Humphries 2008b: 5). US assistance through direct royalty relief and reserves accounting changes was integral to this particular locale’s increased oil and gas production. With similar intent, across the middle 1990s, the United States developed Azeri oil for export to the West, which simultaneously minimized Russian and Saudi clout (LeVine 2007; Stulberg 2004; Bahgat 2003, 2002; Heslin 1997). In all of these instances the United States increased the IOCs’ relative power over world energy. The US did so even more directly when the US Department of Justice ratified the unprecedented corporate mergers of the 1990s. These mergers drove the relative scale and power of US IOCs to heights not seen since the breakup of Standard Oil in 1911. After BP and Amoco merged in 1997, Exxon and Mobil were reunited in 1998. These and other amalgamations were rationalized by the supposition that IOC scale was required to counter the outsized control of oil reserves by the national oil companies of OPEC. Critical assessment of the actual levers of power in world energy were few, or they simply obscured which actors actually dominated global hydrocarbon exploration and production processes and technology, as well as downstream refining and marketing. From inception, ExxonMobil’s domi-

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nant position with nearly 10 percent of all oil products sales globally each year belies any simple argument that the national oil companies have disproportionate power and influence. Instead, it is the US-led majors that determine world energy infrastructure and development, just as they have since before World War I. With each US choice to further subsidize and deputize these IOCs, and thus reinforce the existing infrastructure of maximum energy production and consumption, the United States has further entrenched its ossified system of petrochemical dependency. The present consequences of this system are now self-evident. The United States and Canada subsidize the development of Canadian tar sands while simultaneously extolling the many virtues of a fracking boom from the shale reservoirs of the Dakotas, Texas, and elsewhere. The United States has not remained passive while intrepid private firms brought these innovations to the fore; instead the US blundered into Iraq, dramatically raising oil prices, and then subsidized all manner of Western Hemisphere energy plays to stave off increased oil nationalists’ capacity to injure the North American bulwark. In the 2005 Energy Policy Act and the Presidential Commission report of September 2006, titled “Development of America’s Strategic Unconventional Fuels Resources,” the United States declared that unconventional resources (including shale reservoirs and Canadian tar sands) were strategically vital. They “should be developed to reduce the growing dependence of the United States on politically and economically unstable sources of foreign oil imports” (Humphries 2008a: 23; US Public Law 10958, section 369). Subsidies to these particular resource development projects were increased, and in 2007 alone, the US tax credit for unconventional fuels development was $4.5 billion, five times greater than in 1993, and three to four times greater than in recent prior years (Sherlock 2011: 29). Canadian and Albertan provincial tax credits were similarly outsized, and as a result, the torrent of Canadian tar sands “oil” production has accelerated from this time to the present (Nikiforuk 2008: 141–145; Kairos 2008). Perhaps former prime minister Stephen Harper was less a soothsayer than a marginally alert observer and cheerleader when he noted: an ocean of oil-soaked sand lies under the muskeg of northern Alberta—my home province. The oil sands are the second largest oil deposit in the world, bigger than Iraq, Iran or Russia; exceeded only by Saudi Arabia. Digging the bitumen out of the ground, squeezing out the oil and converting it in into synthetic crude is a monumental challenge. It requires vast amounts of capital, Brobdingnagian technology, and an army of skilled workers. In short, it is an enterprise of epic proportions, akin to the building of the pyramids or China’s Great Wall. Only bigger. By 2015, Canadian oil production is forecast to reach almost 4 million barrels a day. Two thirds of it will come from the oil sands. That’s why policymakers in Washington— not to mention investors in Houston and New York—now talk about

The US Energy Complex: The Price of Independence Canada and continental energy security in the same breath. That’s why Canada surpassed the Saudis four years ago as the largest supplier of petroleum products to the United States. (Harper 2006)

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Investment and production have indeed followed this most recent incantation of an interest in “continental energy security,” and the governmental inducements to develop this particular batch of unconventional Albertan “oil.” Annual investment in the Canadian tar sands industry never exceeded C$10 billion prior to 2006, but thereafter they increased exponentially. In 2013, C$32.7 billion was invested in this bounty of Albertan hydrocarbon resources, while cumulative investment since 1991 is at least C$207 billion (Government of Canada 2014: table 2.2; David Morhart, personal communication May 19, 2011). The production and export of this “oil” has followed these government and corporate commitments. In 1980, Canadian tar sands oil production was a mere 100,000 barrels/day; but by 2012, it was 1.8 mbd, making up 55 percent of Canada’s total oil production of 3.2 mbd. In 2014, it was 2.2 mbd and set to climb even higher. Much like Canada’s conventional oil development since World War II, nearly all of the tar sands oil comes to the United States. The US oil majors are heavily invested in the tar sands project, and they dispose of the oil largely as they see fit (Song 2013). The recent quibbling over particular transportation modalities belies the driving reality that this oil is being produced at accelerating rates and it is coming to the United States, regardless of temporary difficulties with one pipeline project. The deeply cynical acceptance of this point was selfevident in the conclusion of the US Department of State’s “final supplemental” environmental impact assessment of January 2014. This document found the Keystone XL pipeline would not materially alter greenhouse gas emissions profiles because the oil was being produced and distributed regardless of transportation vagaries. As important, large-scale infrastructure projects—including upgraded refineries to process this crude and heating tank terminals in faraway places such as Albany, New York—are being developed to manage this increased resource (Nearing 2017; Mouawad 2014c; Deutsche Bank 2013: 23–29). While Prime Minister Stephen Harper and President Barack Obama had a personal tiff over this and other prior entanglements, Harper’s comments that the decision was a “no-brainer,” blocked only by the puerile domestic calculations of President Obama, does not change the seemingly unalterable reality of increased tar sands oil coming into the United States (Greenspon et al. 2014). This “oil” will continue to come, whether by rickety rail lines and potentially explosive tank cars or new and improved pipelines (e.g., Enbridge’s planned doubling of pipeline capacity for the existing Line 67 “Alberta Clipper” from Hardisty, Alberta, to Superior, Wisconsin; Enbridge 2014; Snyder and Penty 2013).

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The key reasons Canada’s bitumen hydrocarbons have been developed include the official governmental and private company support for the project and the coincidentally timed massive run-up in oil prices and related geopolitical rivalry unleashed by the Iraq War in 2003. ExxonMobil is crucial in all of these adaptations toward improved hemispheric autonomy, but it is particularly invested in Canada’s tar sands because it relies on Canadian unconventional hydrocarbon resources to bolster its reserves accounting. ExxonMobil’s projections of future production—and hence its revenues, profits, and stock price—stay respectably high (and therefore useful to takeovers of other companies such as XTO Energy) only when its reserves grow continuously and more than replace annual production losses (i.e., the reserves replacement ratio is above 100 percent). Canadian and South American bitumen and synthetic oil accounted for 32 percent of ExxonMobil’s global oil reserves at year end 2012 (ExxonMobil 2013: 71). This is mostly Canadian tar sands as Venezuela evicted ExxonMobil from the Orinco belt project in 2007. The significant share of unconventional resources in key corporate oil reserves such as ExxonMobil’s helps explain the recent official shift away from conventional US accounting regarding oil reserves. Much like the US Treasury royalty-tax rule change in 1950, the SEC “modernized” its accounting standards effective January 2010, in favor of the major oil companies’ freedom to include shale, tar sands, and even coal as official oil reserves. The only hurdle is the clause stating that the unconventional resources are “intended to be upgraded into synthetic oil or gas.” The rule actually stated that there need only be “a reasonable expectation of a market,” for unconventional reserves to be booked on corporate balance sheets (US Securities and Exchange Commission 2009: 2163). Demonstrating such reasonable market expectations and the intention to upgrade a resource into synthetic oil or gas as well as US government responsibility to assess all of these was, as to be expected, underspecified in the rule. This rule change and ExxonMobil’s expanded operating footprint in Iraq and other resource locales have allowed the company to book a great deal more oil reserves, both conventional as in Iraq and unconventional as in Canada and the many shale reservoirs of the United States (Lando 2010; Ryder Scott Co. 2010). This has helped ExxonMobil increase its relative power over world energy. More important, as with the 1970s adaptations, ExxonMobil and its retinue of oil services companies in Houston have used the relative wealth boomlet from much higher priced oil to develop next-level technology drivers for unlocking the expensive oil and gas in the shale formations. Among other key Houston-based actors, ExxonMobil, Baker Hughes, and Halliburton have come to dominate hydrofracking and related technologies as well as the shale-laden properties themselves acquired through acquisitions such as XTO Energy (Gold 2014; Zuckerman 2013). Hydrofracking technology is not new or awe-inspiring,

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and the dominance of the major oil field service companies in its use in places such as North Dakota is a familiar story. The oil majors and their affiliated companies have long practiced cartelized cooperation in upstream and downstream operations, in addition to their creative destruction of rival players, as with National City Lines’s operations against electric light rail from the late 1930s through the early days of the Cold War (Snell 1995). There have already been several allegations of price fixing among the oil field services giants related to hydrofracking, and their indispensability to producing these particular resource formations is global, bridging even the relations between the Anglo-American-Dutch oil majors and Russia (Wethe 2014; Calkins 2013). With higher priced oil and the commitment of nearly every major governmental and corporate actor that counts, it is unsurprising that the oil and natural gas of the long-studied shale formations are now being exploited by the very same actors that developed most of the world’s conventional oil and gas since World War I. The Shale Revolution and the Recurring Dream of US Energy Independence

The most powerful state and corporate actors in the energy world are developing the energy resources of the North American continent. They all view the Americas as one strategic unit, as they have since World War II. With each US choice to further subsidize and deputize the leading IOCs, the energy arteries of the Americas further harden on this hydrocarbon complex. The strategic purpose of these latest developments remains the same as it was shortly after World War II, when the United States chose to control Middle Eastern oil to influence dependent allies in Europe and Asia and develop Western hemispheric resources for domestic consumption. The simultaneity of the Iraq War and the tar sand and shale revolution merely represents the latest manifestation of these dual purposes, which further limits US development of alternative and greener energy sources. The fact that leading energy experts extol the domestic development of expensive hydrocarbons with hackneyed arguments about energy independence and relative leverage vis-à-vis OPEC simply underscores just how ingrained the postwar energy system has become (Jaffe and Morse 2013; Levi 2013; Yergin 2011b). North Dakota’s rapid development as a leading producer of oil and natural gas from tight shale formations is illustrative of the misplaced optimism about energy independence and a greener energy future from an “all of the above” non-strategy. The case of North Dakota oil and gas production is truly astounding. Nearly a million barrels per day of oil production has been reached since the end of 2013, and a great deal of associated natural gas accompanies this, although much of the gas is simply flared off as an uneconomical by-product

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due to gas infrastructure deficits (Oldham 2014; EPRINC 2012; Bentek Energy 2012). According to one estimate, US flaring of ostensibly greener natural gas increased 35 percent in 2012, largely due to the increased hydrofracking of shale reservoirs (PBL Netherlands Environmental Assessment Agency 2013: 22). The waste of this natural gas and the more ruinous release of methane from hydrofracking shock the conscience and belie claims about greener energy from fracked natural gas (Caulton et al. 2014). Still today, in North Dakota alone, flared gas is approximately 30 percent of the total amount of gas produced, with an estimated value of $1.4 million/day (Arnsdorf 2014; Baltz 2014). As is obvious, the returns to investors in shale come from the oil in North Dakota, not the gas. This is also true in Iraq, where 60 percent and more of the associated gas from the large southern fields has been simply flared off (Lando and van Heuvelen 2011; Smith and Lando 2011). Investment in North Dakota shale resources accelerated beginning around 2005, with the inducements in the Energy Policy Act for hemispheric autonomy from unconventional fuels and the consequences of the Iraq War. In 2005, North Dakota produced a mere 97,697 barrels of oil a day; even in 2007, that number had only crept up to 123,446 barrels a day. The massive investment in exploration and production in North Dakota really took off in the mid-2000s, and this along with the Permian and Eagle Ford formations in Texas accounts for the tremendous growth in shale oil and gas output. North Dakota zoomed to the top of hydrocarbon-producing locales in the world, cresting at 1.23 mbd of oil production in mid-2015. North Dakota’s economic output grew 13  percent in 2012, the fastest rate in the United States, and its unemployment rate then was the lowest in the United States. The direct amount of annual spending on exploration and production from completed wells was estimated at $408 million in 2005, but this climbed to $11.6 billion in 2011. Indirect economic effects can only be estimated, but they are clearly large given North Dakota’s boom. The problem with the fracking model is that the development costs for each well in North Dakota have risen more than fivefold, from $1.7 million per well in 2005 to $9.1 million in 2011 (all figures expressed in 2011 dollars; Bangsund and Hodur 2013, tables 12 and 14; Bangsund and Leistritz 2009). More and more wells came to North Dakota, but they were chasing resources that grew more costly to extract and had much higher depletion rates than conventional oil and gas reservoirs (Doan and Murtaugh 2014; Makan and Blas 2013; Berman 2012). This is certainly the view of skeptics such as Andy Hall and Art Berman, who see shale resource yields and production longevity as highly questionable. It also appears to be the view of former Deutsche Bank lead oil analyst and recent director of the US Department of Energy’s Energy Information Agency, Adam Sieminski. After downgrading by 96 percent the entirety of reserves estimates for the Monterey formation in California, the largest shale formation in the United

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States, Sieminski observed: “The rock is there, the technology isn’t there” (Malik and Shauk 2014). A proven, recoverable hydrocarbon reserve is a malleable accounting concept determined in the end as much by technology and investment as by extensive corporate lobbying and governmental fiat. This was revealed again most recently with the modernization of SEC definitions for oil and gas, which took effect in 2010. Reserves are always a function of the political economy of technology and investment, not the base geological properties of the hydrocarbons. Coal could always be turned into gasoline. Dr. Bergius demonstrated this over 100 years ago. Now with accounting “modernization,” coal is again potentially bankable as oil reserves, provided only very thin and opaque regulatory hurdles are cleared. Sieminski simply added a small dose of reality to the overinvestment in the shale formations of the United States. The likelihood of costly capital misallocation in the shale plays is only overshadowed by the certainty of the environmental costs due to developing these and the tar sands in Canada. The destruction of carbon-capturing boreal forest in Canada and the degradation of air, water, and overall environmental quality everywhere around the tar sands and hydrofracked shale operations ensure the longevity of a dirtier hydrocarbon-based energy system (InsideClimate News 2014). It has been even more disconcerting to observe US state supplication to the production and export plans and operations of the major IOCs. First, in early 2014, the US Department of Commerce acquiesced to the oil industry’s long-standing desire to loosen the forty-year-old restrictions on US crude oil exports. Then, the Obama administration capitulated to this desire in June 2014 and began opening the floodgates for more IOC authority over the supply and demand balance for oil at all stages of refinement (Shauk, Murtaugh, and Katakey 2014; US EIA 2014d). White House press secretary Josh Earnest was so oblivious to the White House’s supplication that in the immediate aftermath of the mid-2014 decision to relax the crude oil export ban he declared: “There’s been no change to our policy when it comes to crude oil exports” (Nguyen 2014). The final, formal change codifying the US oil majors’ nearly two-year running de facto repeal of the crude oil export ban came at the end of 2015, when the entire legal structure governing crude oil exports was eliminated, among other favors to this industry (Papavizas 2015). The permanent repeal of the crude oil export ban was heralded as sufficient recompense for the mere temporary continuation of solar and wind tax credits (US Public Law 114-113, Division O, Section 101, Division P, sections 301–304). Bad bargains such as these make President Obama’s energy autonomy legacy difficult to praise, and in many ways he has been simply supine in his dealings with the petrochemical complex. In addition to his often repeated yet empty threat to repeal $4 billion in oil-related tax credits, only weeks

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before the Macondo well blowout, he declared that offshore drilling rigs “don’t cause spills. They are technologically very advanced.” At the height of that crisis on May 27, 2010, when the seabed aperture was still spewing unchecked, Obama mused publicly about the US state’s lack of relative power vis-à-vis industry: “the federal government does not possess superior technology to BP. . . . Now, one of the legitimate questions that I think needs to be asked is should the federal government have such capacity” (Obama 2010). At that moment, no one in the US would have merely posed such an odd rhetorical question, let alone answered in the negative. The real question was and remains why has the US state constantly deferred its interests and authority to those from the petrochemical complex? Why has this president, in particular, been so enamored of University of Chicago liberal regulatory dogma about properly incentivized markets that in his eight years in office he failed to build material US capabilities toward both a greener and more autonomous energy system? His desire to build a naval biofuels program exemplifies the limitations of his applied philosophy. This program has relied on temporary and de minimis contracts for batch-sized biofuel allotments, and it has done little more than ensure the lack of a sustainable buildout for this nascent sector. To be fair, the sanctions against Russia in September 2014 did halt ExxonMobil’s productive drilling partnership with Rosneft and challenged the balance of evidence for concluding that this presidency was fully servile to industry. But, it remains the only identifiable instance, while he ended his presidency with yet another regurgitation of his simple faith in “economic incentives” to alter energy patterns and save the climate (Obama 2017: 2). More starkly, President Obama did not properly administer the executive branch’s existing authority over the metastasizing oil and gas complex, particularly visible in the aftermath of the horrendous Albertan diluted bitumen pipeline ruptures (McGowan and Song 2012). The crude oil rail transport imbroglio over the last several years also supports this assessment. While Canada has moved ahead to mandate better crude oil tank cars and rail safety measures, the United States remains mired in regulatory processes that ensure very little progress in the near term (Black, Snyder, and Ali 2014; Mouawad 2014a, 2014b; Penty and Catts 2014). Despite the massive increases in oil by rail traffic in the United States and the many “unsafe at any speed” type of explosive derailments due to the chemical composition of the oil in the old tank cars, the dilatory process on transport safety contrasts markedly with that for fostering “free trade” by promoting more US oil exports. In fact, the United States now exports more oil products than at any time in its recent history. In 2005, the United States exported 1.165 mbd of crude oil and products; by 2015 this number was 4.738 mbd. The government’s acquiescence to US oil majors in repealing export restrictions neatly

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supports the argument that the US state simply ratifies what the industry is already doing and desires to do. The increase in US oil products exports since 2005 basically matches the increase in crude oil production, which went from 5.18 mbd in 2005 to 9.415 mbd in 2015. In effect, over these last several years the United States has simply exported its increased crude oil output through large increases in refined products exports, while the oil majors can now define what crude oil is and export as much of it as they see fit. Tight markets for the oil and gas of the Americas are now more likely as the freedom to balance oil supply and demand is more thoroughly in the hands of the IOCs and their financial sector colleagues (Brunsden 2013; Forden 2013; Greenberger 2013; Omarova 2013). Similar to the period around World War I when Mexican oil was used to flood or starve American markets, the US oil majors are freer again to move US, Canadian, Mexican, and other hemispheric oil products around to their advantage in controlling hemispheric energy markets and forestalling US energy independence. The increased structural power of these Houston-based oil majors and their financial sector allies was visible beyond the United States in Mexico’s 2014 constitutional amendment and effective repeal of the 1938 nationalization of Anglo-American-Dutch oil assets. Out of a simple desire to arrest the decline in output and trade from their sovereign reservoirs, Mexico gave in to the US majors’ goal of expanded control over their resources. Of course, capitulation is stated with more grandiloquence by people such as Edward Morse of Citibank, but the reality of Mexican supplication to Houston’s market superiority remains self-evident (Williams 2014; Carroll and Olson 2013). Much as it has in the definition and transport of oil, the United States has deferred to industry and its plans for the overall energy industrial grid for the Americas. The United States is transitioning to more natural gas in the energy mix, and Siemens AG’s CEO may well be correct that in future “all roads lead to gas” (Webb and Patel 2014). But, this gas will be developed by leading petrochemical actors such as ExxonMobil and may not complement but rather displace newer or greener energy players such as wind and solar in Germany’s renewable program (Lauber, Chapter 8 in this volume). ExxonMobil currently produces approximately 6 percent of total US natural gas output. The United States became the world’s leading natural gas producer in 2010 and in 2013 produced a record 24.3 trillion cubic feet of natural gas (US EIA 2014c, 2010). More important, ExxonMobil dominates global natural gas development and trade, principally from locations such as Qatar, Australia, and Indonesia (Kamrava 2013: 43–45; Stern 2012). As noted earlier, ExxonMobil is in direct partnership with Royal Dutch Shell in many global gas ventures. In the absence of concerted political will

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to the contrary, the world’s energy future will be built by them and their colleagues. Whether energy for industry and transport comes in the form of electrons or gas, ExxonMobil will be the lead actor developing the multidecadal infrastructures and political realities that support them. In the Americas this means principally more of the same. Investment and regulatory structures favor the ongoing development of more costly unconventional oil and gas. The alterations in the energy mix toward natural gas and away from coal in electrical generation do not fundamentally change which actors determine the infrastructure and outcomes for the peoples of the Americas, because ExxonMobil is not heavily invested in coal and other declining energy resources. Coal slipped to only 20 percent of total energy production across all end uses in the United States for 2015, while natural gas climbed to 31 percent of energy production for 2015 (US EIA 2016c: table 1.2). More narrowly, coal supplied 50 percent of US electrical generation and natural gas only 18 percent in 2002, but, in 2015, coal’s share dropped to 33 percent and natural gas climbed to 33 percent of US electrical generation (US Department of Energy 2016a). Here again, if ExxonMobil is the largest natural gas producer in the United States, then it gains from the shift from coal to gas for electricity. It also gains leverage even if transport becomes more electrified and less reliant on petroleum-based liquids, because it will hold sway over the price of electricity, while also holding a large hand in whatever becomes of natural gas liquids as transportation fuels. The much anticipated increase in exports of US natural gas, like oil before it, reaffirms the structural power reality wherein ExxonMobil and company control the energy autonomy of powerful states, even the United States. While affirming the post–World War II object of maintaining hemispheric autonomy relative to the Middle East, increased US oil and gas production does not mean the United States will ever achieve energy independence. In fact, Rex Tillerson decried such a goal at his Secretary of State confirmation hearing when he held: “I have never supported energy independence” (Tillerson 2017). Conclusion

Standard Oil of California’s Ralph Davies was right in 1944 when he remonstrated Harold Ickes for prematurely declaring an end to the oil era. But Ickes was also correct in highlighting that cheap and easy oil would eventually run out and the geopolitical rivalry that might commence thereafter would make the world wars look quaint. As much as our era’s apostles of abundance want us to believe in an immutable right to meet growing energy demand with more unconventional and dirty hydrocarbons, the

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truth is that something has to give. Conventional oil resources are running out, but the “oil” era continues because the most powerful petrochemical actors in the world are developing unconventional hydrocarbon resources to feed the existing societal infrastructure predicated on excess energy consumption. Despite the pleas from Bloomberg New Energy Finance analysts (among others), the entrenched complex of hydrocarbon hegemonists maintain their political dominance over most alternative energy sources, and they are controlling the global rollout of natural gas as a “bridge fuel” (Roca 2014). The United States does not challenge the concurrent retrocession to dirtier and more unconventional energy resources, such as Canadian tar sands and hydrofracked shale. The United States does not challenge these actors’ interests because it is heavily invested in the defense of its global position, which is based on petrochemicals derived from oil and gas and these delegated oil majors’ dominant role in these sectors. The United States has always ruled the Middle East indirectly through the IOCs, and it will continue to do so even as this indirect subsidiarity gives way to outright direction with a Secretary of State from ExxonMobil. But, the United States has done so to influence other actors’ energy consumption patterns and relative dependency. Despite the legions of false prophets of energy abundance and US independence who claim US Iraqi interests have nothing to do with oil because the United States imports so little oil from there, the United States does not control the oil of the Middle East to fuel domestic US consumption. As this chapter demonstrates, the United States has never consistently imported significant amounts of Middle Eastern crude into its sequestered hemispheric market. Instead, the United States controls the Middle East to gain leverage over others’ hydrocarbon dependencies. These embedded hydrocarbon dependencies are promoted and sustained both inside the United States and abroad in other powerful actors, even with rivals such as China and Russia. To be sure, the United States seeks energy autonomy for the broad North American hemisphere, but the US has always recognized that relative power, wealth, and influence all flow from the simultaneous pursuit of both ends of the hegemonic imperative—insulating the home hemisphere and controlling the Eastern Hemisphere’s energy base in the Middle East. Unfortunately, US political elites seem unwilling or unable to avert the calamitous consequences from pursuing this path-dependent approach to maintaining global dominion. Notes

1. Unsurprisingly, Iraq is an outlier to this regional property, as it has sent significant amounts of its crude oil exports to the United States in recent years. For

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example, the US share of Iraqi oil exports during the 2006–2012 period was 26 percent, approximately twice the regional average of 13 percent. In 2006 alone, 38 percent of Iraqi crude oil exports went to the United States, while the more vital control of Iraqi oil reservoirs illustrates clear US dominance. ExxonMobil is the operator of the West Qurna site, but more important, it is the lead developer for the Mishrif reservoir, which straddles the Rumaila and West Qurna fields. In 2010, Michael Daly, head of exploration, for BP, stated it tersely: “The Rumaila/W. Qurna oil field is one of these old structures with both sandstone and carbonate reservoirs. Looked at as a single structure, it ranks second in the Middle East in terms of oil originally in place after the great Ghawar Field of Saudi Arabia” (Daly 2010).

7 China’s Resource Drive into the South China Sea Andrew S. Erickson and Austin M. Strange

China’s consistently high economic growth in the postreform era has been accompanied by burgeoning energy demands that make Beijing increasingly dependent on external energy sources. As a result, Beijing increasingly looks beyond its (land) borders for energy resources and must balance energy-related economic interests with geopolitical factors to an unprecedented degree. Oil and gas account for less than half of China’s aggregate energy consumption, and sovereignty and energy transit issues in the South China Sea (SCS) far outweigh the significance of potential oil and natural gas resources there. Nonetheless, China’s approach to and development of the latter offers an instructive lens for observing the interplay of economic and geostrategic forces. It is precisely the considerable uncertainty as to the nature and scope of energy resources in this area that make it a compelling geostrategic case: the SCS offers an opportunity for analyzing how China’s pursuit of new energy sources fits within its larger energy security equation and how Beijing balances economic and geostrategic concerns in the twenty-first century. Like many states in regions such as the SCS, China’s quest for energy security is part of a larger calculus that involves other dimensions of Chinese national interests. While China and other nation-states would benefit from pragmatic, mutually beneficial solutions to energy needs amid a backdrop of complicated, persistent geopolitical security challenges, Beijing’s recent actions suggest that it is increasingly taking a more unilateral, coercive approach. Introduction: Beijing’s Energy Security Backdrop

China’s consistently high economic growth in the postreform era has been accompanied by growing energy resource demands. As the largest natural resource–consuming and greenhouse gas–emitting nation on Earth, China faces mounting energy needs and must address increasingly complicated 131

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energy security challenges. Such challenges include managing environmental concerns while remaining the world’s largest energy consumer, securing new sources of domestic and overseas oil and gas supplies to meet national supply and demand imbalances, and securing new sources of energy outside of China without tarnishing Beijing’s image abroad. China’s economic, political, and military ascendance in recent years has resulted in greater scrutiny vis-à-vis its internal and external policy behavior; Beijing’s energy security policies are thus unfolding in front of highly interested domestic and international audiences. The ramifications of energy policies on Chinese diplomatic and geostrategic interests are relevant from a general foreign policy standpoint. From the perspective of Chinese leaders, China’s twenty-first-century energy security policies are occurring under formidable domestic growing pains, including growing economic and social inequality, waning (though still high) economic growth, and a range of internal political challenges such as restive border regions. Decisionmakers also face a complex international environment in which perceptions of China remain mixed, particularly among its neighbors. From a broad energy perspective, China’s consumption and sourcing trends are moving in an unfavorable direction. While various resource discovery and extraction technology breakthroughs are steering developed countries such as the United States, Australia, Japan, and EU members toward higher levels of energy self-sufficiency—and thereby greater energy security—China is becoming more reliant on stable overseas energy supplies.1 No state looks favorably on increased dependency on foreign states and companies for its national energy supply. Here, the United States has recently encountered more positive conditions, whereas China is on course to experience challenges similar to those the United States faced in the mid- to late twentieth century. China is particularly wary of volatility in international oil markets and their frequent inability to provide stable supplies at relatively predictable rates. Moreover, reliance on other states for critical energy supplies creates negative diplomatic leverage.2 After relying on crude oil imports from Middle Eastern and African states—including so-called rogue states—for decades, many Western states, the United States among them, are well versed in energy politics. By contrast, China previously enjoyed relatively low oil import dependency before becoming a net importer in 1993 and is just beginning to experience the challenges of sharper reliance on external oil supply during the twenty-first century. Another element of this development is greater Chinese dependence on sea lines of communication (SLOCs) security through rising oil and gas import dependency. Like other major energy consumers, China already depends increasingly on importing energy supplies by tanker from sometimes unstable overseas regions, including Southeast Asia, Central Asia, the

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Middle East, Africa, and South America. Incidents in which Chinese workers are endangered or harmed abroad continue to challenge Beijing as Chinese state-owned enterprises, especially national oil companies (NOCs), develop outward to exploit such supplies. Other factors, such as the challenge for China’s enormous NOCs in securing resources for national energy security while trying to make prudent investments, further complicate energy security policies.3 Accelerating energy demand has long concerned Chinese and international observers. Coal has been the linchpin of modern Chinese energy consumption for decades, and continues to serve as the backbone for electricity generation. Oil, on the other hand, is indispensable for China’s transportation sector, which has burgeoned as a result of major structural transformations over the previous two decades including feverish private car purchases. Since 2009, China has been the world’s largest automobile market. More broadly, even as overall consumption habits remain relatively conservative on a per capita basis, Chinese consumers are driving demand for conventional fuels such as coal and oil.4 Although there is a growing consensus that Chinese economic growth is slowing, China’s average annual gross domestic product (GDP) growth has been higher than 7.5 percent for twentytwo consecutive years beginning in 1991 and averaged 10.3 percent during the same period (World Bank 2013). In other words, potential declines in future economic growth notwithstanding, much of the growth needed to drive game-changing increases in energy demand have already occurred. Sobering consequences accompany these macro-level trends. Aggressive burning of fossil fuels has severely damaged China’s natural environment and economy, perhaps represented most succinctly by reports in 2013 that the rapidly deteriorating air quality could cause respiratory diseases and other consequences detrimental to the workforce (Chen et al. 2013). Besides the environment, there are striking regional imbalances within China in terms of energy supply and demand. Despite long-standing and intensive efforts to develop oil and gas reserves in northwest China’s Tarim basin and Shandong and Heilongjiang Provinces to the east, the domestic oil reserve base appears insufficient to meet more than a minority share of the country’s energy needs (Collins 2015). While the state continues to promote the development of new, cleaner energy sources such as solar, wind, and hydropower, these channels are likely too expensive or otherwise limited to make a revolutionary impact on the midterm structure of Chinese energy consumption. In recent years, shale gas has also received great attention as a partial solution for burgeoning energy demand in China. According to a report published in June 2013 by the US Energy Information Administration (EIA), China has the world’s most abundant technically recoverable onshore shale gas resources at over 1,115 tril-

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lion cubic feet. Chinese shale gas deposits are primarily spread over seven basins in the southeast and northwest regions (US EIA 2013e). China is aiming to boost shale gas production by approximately 60 percent to 9.7 billion cubic feet per day (bcfd) by 2020; however, rapid commercialization might be challenging for many reasons: China’s typically complex geologic structure (faulting, high tectonic stress), location of deposits in often hilly, lessdeveloped terrain with severe water limitations, restricted access to geologic data, and the high costs and rudimentary state of in-country horizontal drilling and fracturing services that characterize China’s shale gas industry. Because China’s oil demand and extraction has already been documented and analyzed more extensively, and its gas demand and extraction represents a limited but growing area, this chapter focuses disproportionately on the latter. Collectively these trends represent a decisive test for Chinese energy planners: China must find ways to use energy that supports sustained economic growth while managing the negative by-products of heavy reliance on traditional fuels. Passing this test requires a multipronged approach. For instance, no less-intensive energy sources—including renewables such as hydro, solar, or wind as well as natural and unconventional gases—can be developed on a scale (or cost efficiency) sufficient to shift the balance in China’s overall energy portfolio. Growing reliance on external energy supply for economic growth has made Beijing’s energy security strategy particularly complex since its economic interests overlap with overseas Chinese human, political, and security interests to an unprecedented degree. Given its economic and geopolitical significance, the SCS offers one possible case for assessing the overlap of these issues. Following this introduction, the chapter begins by briefly surveying political, economic, and technological trends in Chinese energy security and related fields that are driving an increased demand for offshore oil and particularly natural gas. The prospects for offshore development of these resources in East Asia are then briefly explored. Natural gas development in the SCS provides a case study through which we analyze the broader impact of Chinese energy security on strategic regional energy competition and cooperation. As its role in Asian energy security gradually expands, natural gas and the way neighboring states work with or against each other to obtain it from disputed areas such as the SCS could potentially serve as barometers for larger global themes of strategic cooperation and competition for scarce resources that cross economic, political, and technological dimensions.5 That said, we cannot emphasize enough that the most strategically important issues in the SCS are the overlapping sovereignty claims of China and various other states and the maintenance of secure, stable maritime transport. Despite their economic and strategic differences,6 oil and liquefied natural gas (LNG) are the two energy sources with inherent naval sig-

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nificance: to the extent that domestic supplies or overland pipelines are insufficient, they must be transported by sea. Actual energy reserves in the region are relatively limited and remain poorly understood. This case study is provided to explore how larger geopolitical concerns interact with economic issues such as domestic energy needs. The Economic Significance of Chinese Offshore Oil and Gas Development

Given the challenges outlined in the previous section, China is seeking to elevate offshore oil and natural gas in its energy mix hierarchy, even if these sources remain secondary compared with more traditional ones. Aside from developing its own continental reserves, China seeks to secure previously unavailable supplies of oil and natural gas through imports and offshore development. Because of the undesired risks generated by growing oil import dependency, offshore oil and gas development is of particular interest in the context of Chinese and East Asian energy security. Given its supply of natural gas reserves, the SCS offers a rare window for analyzing the interplay of China’s domestic energy needs and geopolitical considerations. The SCS is of great importance across the dimensions of geopolitics, trade, and energy. Two-thirds of world oil shipments transit the Indian Ocean, with more than 15 million barrels of oil transiting the Strait of Malacca daily in 2014. The Asia Pacific boasts eight of the world’s ten busiest container ports; nearly 30 percent of global maritime trade transits the SCS annually, including about 1.2 trillion in shipborne trade bound for US ports. Home to 10 percent of global fisheries production, the SCS is estimated by the EIA to contain up to 11 billion barrels of oil and up to 190 trillion cubic feet of natural gas.7 A combination of political, economic, and geographic forces is driving China’s demand for offshore natural gas. At roughly double the rate of domestic production growth, Chinese natural gas demand has grown by more than 15 percent every year since 2003. In particular, during 2010, national natural gas demand increased by 22 percent to 107 bcm, making China the fourth largest global gas user behind the United States, Russia, and Iran (Xu 2011). In 2011, China produced 3.6 trillion cubic feet (tcf) of natural gas and consumed roughly 4.6 tcf. From 2010 to 2011 gas imports as a percentage of aggregate national consumption increased from 12 percent to 22 percent (US EIA 2013h). In 2013, meanwhile, China was the world’s largest growth market for energy overall in absolute terms and for natural gas in percentage terms (8.6 percent). The fact that its natural gas imports rose even more rapidly (10.8

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percent) reflects increased import dependence (British Petroleum 2014: 4). In 2014, mainland China had 122.2 tcf proven reserves (1.8 percent of the world total); it produced 134.5 bcm, or 121.0 million metric tons oil equivalent (up 7.7 percent from 2013). It consumed 185.5 bcm, or 166.9 million metric tons oil equivalent (up 8.6 percent from 2013) (British Petroleum 2015: 20–25). The fact that gas consumption as a proportion of China’s energy mix remains roughly five times under the global average of about 24 percent suggests that there is significant room left for growth (Ma 2014: 168). Damien Ma estimates that “China’s dependence on natural gas imports could easily reach 50 percent over the next five to ten years” (2014: 154). BP goes so far as to project that “China will become the world’s biggest LNG importer after Japan by 2035” (Almeida 2015). Consequently, Beijing is feeling increasing pressure to develop long-term answers to its energy challenges, and natural gas offers one such answer. Beijing’s policy goals further suggest rationale for increased natural gas imports and consumption. China has repeatedly stated its official commitment to reducing greenhouse gas emissions and has identified natural gas as an important pillar of their twenty-first-century “low-carbon economy.” Recent data suggest that residential gas use and industrial power generation will be increasingly vital structural components of Chinese natural gas consumption. Moreover, as demand increases, China’s domestic natural gas supply deficit is likely to continue its incremental growth. Consequently, to the extent domestic onshore sources are unable to meet demand, imports or offshore development of natural gas will need to increase to offset this imbalance. Of course, overall importance of natural gas, particularly to China, must be kept in proper perspective. Natural gas is one of several energy sources perceived by Beijing as significant for energy security, and its role should not be overstated. While natural gas is sometimes viewed as the favored “alternative” fuel at present, it is unclear whether Chinese planners favor it over other hydrocarbons. For example, natural gas represented 5.6 percent of total primary energy supply in China for 2014 (BP 2015: 41), still less than hydroelectric. Despite its significant potential to use more gas, China surprisingly has a “gas glut” at present and is struggling to effectively use the gas to which it currently has access.8 This glut is driven by a number of factors, including higher domestic conventional production and Central Asian gas and LNG. In addition, the demand simply is not there at current prices. When coal remains so cheap (Rmb 400/ton) relative to other options, it is admittedly difficult to incentivize shifts in behavior, such as converting boilers to gas-powered alternatives, for instance. These factors—plus significant quantities of new renewables, nuclear and hydro plants coming on line—are likely to prolong China’s relatively low gas penetration rate. It is indeed possible that China will never

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become a highly gas-intensive economy like the United States and Russia.9 In any case, China will not be ready for gas “prime time” until prices come down considerably relative to other options, and although that may happen over time (with new supplies), it will be a long process. For the foreseeable future, therefore, the ratio of natural gas use to China’s aggregate energy use is and will remain low in comparison with many other large states, as Table 7.1 shows. For example, as of 2010 major energy consumers such as the United States, Japan, India, Russia, and Brazil relied on natural gas to a higher degree than China. In the United States, Japan, South Korea, and Russia, natural gas plays a much more central role in national energy supply than it does in China. Despite its modest role in the nation’s persistently coal-centric energy consumption structure, however, China’s natural gas supply and demand still offer an interesting demonstration of how energy needs fit into larger geostrategic overlays. More specifically, the trajectory of China’s natural gas development explains why offshore oil and natural gas development in the SCS and other maritime regions is, aside from geopolitical implications, significant for Beijing’s energy security future. In the government’s energy security calculus, the aforementioned geopolitical and environmental drivers are enhancing the role of natural gas, especially offshore. Even if gains are modest and incremental, the challenging position of growing external dependence means that every potential channel of supply matters to some degree. Growing concerns about ecological degradation in China have intensified searches for alternative energy sources to coal and oil. Despite retaining one of the world’s lowest levels of energy consumption per capita, China infamously became the world’s largest emitter of greenhouse gases in 2006 and the largest total energy consumer in 2009 (Swartz and Oster 2010). The Environmental Policy Concerns

Table 7.1 Percentage Share of Natural Gas in Aggregate Energy Consumption, Selected Countries in 2015 Country

Share of Natural Gas (%) in Total Energy Consumption

Russia United States Japan Germany South Korea India China Source: British Petroleum (2016: 41).

52 31 22 20 14 6 5

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Chinese government has acknowledged the urgent need to improve environmental conditions and lessen China’s dependence on coal, especially as air quality in cities deteriorates with high-carbon and high-sulfur fossil fuel burning and as environment-related rural unrest mounts as a result of heavily polluting development projects in inland China. On March 28, 2011, the Ministry of Industry and Information Technology set China’s carbon emission and energy intensity reduction targets at 4 percent in 2011 and 18 percent in 2015, relative to 2010 levels. This corresponds with China’s broader agenda to reduce the carbon emission intensity per unit of GDP by 40–45 percent by 2020 (Xinhua, March 28, 2011). Of course, the merits of natural gas (which is essentially methane) as a clean fossil fuel are highly questionable. Considered a “bridge fuel” by some experts, it emits less than half the CO2 produced by burning coal, but in some cases natural gas produced through fracking can release excessive amounts of methane into the air, which has a significantly higher impact than CO2 (Schiffman 2013). Additionally, shale gas extraction through fracking creates formidable risks to regional water quality (Vidic 2013). Natural gas is ultimately a fossil fuel, and its precise implications on the environment are still relatively ambiguous. China’s shale geology is very complex; fracking is currently not economically competitive and likely will not be for at least another half decade. Given the dubious cost efficiency and potential detrimental effects of hydrofracking natural gas, the other aforementioned Chinese limitations, and the high greenhouse gas emissions associated with creating synthetic natural gas from China’s abundant coal supplies, offshore gas development extracted using other techniques is arguably an option with less uncertainty in terms of unintended environmental consequences. While “dirtier” than renewable energies such as hydro, solar, and wind power, natural gas is still considered to be relatively environmentally friendly because it emits roughly 40 percent and 30 percent less carbon dioxide than coal and oil, respectively (Natural Gas 2010). Chinese policymakers have taken clear steps to enhance its role in China in the context of mitigating negative environmental effects of energy consumption. The eleventh Five-Year Plan for Energy Development (2006–2010) submitted to the 2006 National People’s Congress reaffirmed China’s ambition to boost natural gas consumption to 10 percent of total energy use by 2020, a target originally set in the tenth Five-Year Plan (2001–2005) (Higashi 2009). In the twelfth Five-Year Plan, released on January 1, 2013, Beijing expressed plans to make natural gas fulfill 7.5 percent of national energy consumption by 2015 (Ma 2013). Clearly, Beijing has recognized the important if modest role that natural gas can play in alleviating China’s heavy reliance on coal, potentially reducing air pollution, and helping satisfy growing demand in its most vibrant regions.

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Structural Consumption Trends in China’s Gas Market

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Although natural gas was historically used for fertilizer production and industrial applications, it is now increasingly used for city gas and power generation. 10 In 2000, urban gas consumption and power generation accounted for only 18 percent and 4 percent of total natural gas use, respectively, according to Goldman Sachs (Goldman Sachs 2011; Duan 2010). These proportions increased to an estimated 43 percent and 12 percent by 2008, the first time that the residential and power sectors accounted for more than half of total gas consumption in China. In 2009, city gas alone represented a greater share of consumption than the industrial sector, which accounted for 26 percent. This trend is not surprising, since the National Development and Reform Commission labeled both sectors as priorities for natural gas use in 2007. Increased penetration into coastal urban areas is a large reason for this shift. Power generation is also an emerging area of application for natural gas in China. In 2006 the total capacity of gas-fired power plants was 15.6 gigawatts (GW) and accounted for just 2.5 percent of China’s power generation capacity (Higashi 2009). However, the twelfth Five-Year Plan (2011–2015) called for significant increases in gas-fired power plants. In recent years such plants have been constructed in coastal areas such as Shanghai, Jiangsu, Guangdong, and Zhejiang. These are concrete commitments to growing gas consumption. Compounding these structural market shifts is the reality that China’s demand for natural gas is quickly outpacing domestic production. This is exacerbated by China’s pipeline infrastructure, which remains underdeveloped relative to demand growth in the gas-poor East Coast. China became a net natural gas importer in 2007. Import dependence has subsequently increased and is expected to increase substantially further, as unconventional gases such as shale gas and coalbed methane (CBM) remain in relatively early stages of development. Geological surveys have discovered abundant reserves of CBM and shale gas in China, prompting speculation that China’s LNG demand boom might slow as domestic production rises. China began developing its CBM reserves during the 1990s, yet did not begin producing shale gas until 2009. CBM faces considerable obstacles to development in the immediate future. Most CBM resources lie in northern China, yet no pipeline infrastructure existed before 2009. This has led to underconsumption of CBM by regions with relatively high natural gas demand. Moreover, several obstacles are impeding shale gas from becoming a relevant source of energy in China’s natural gas mix in the immediate future (Brennan 2013). Chinese shale gas reserves are located deep underground, and some contain high levels of nonhydrocarbon gases, which require additional extraction procedures and

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will lead to higher development costs (Beveridge and Lou 2011; Fu 2011). Hydrofracking to facilitate shale gas development can require 100,000 barrels of water, a problem given water shortages in northern China, where most reserves are located. Rugged terrain in these regions raises procurement and transportation costs; reports speculate that shale gas may be extractable by 2023 at the earliest (Beveridge and Lou 2011; Gascoyne and Aik 2011).11 All these factors underscore LNG’s appeal for China. Geographic Supply Dynamics: Gas Pipelines and LNG Terminals

For now, then, imports and offshore supplies can help bridge the gap between China’s natural gas supply and demand. Here it is important to emphasize that gas geopolitics differs from oil geopolitics in ways amenable to Chinese security perceptions. Whereas a dearth of large-volume oil suppliers has drawn Chinese NOCs to unstable frontier markets as part of a “Go Out” policy, a diverse portfolio of potential suppliers—many relatively stable (Qatar, Australia, Turkmenistan, Papua New Guinea)—are willing to sell China gas (Ma 2014: 162). Another important distinction concerns overland versus overseas supply, both of which China continues to pursue actively. Imported gas enters either inland from the west as pipeline natural gas or from the east in the form of LNG at receiving terminals located in coastal regions. Currently, China imports pipeline natural gas from several nearby nations. In 2014, China imported 31.3 bcm of natural gas by pipeline: 25.5 bcm from Turkmenistan, 3.0 bcm from Myanmar, 2.4 bcm from Uzbekistan, and 0.4 bcm from Kazakhstan (British Petroleum 2015: 28). China National Petroleum Corporation (CNPC), China’s largest NOC, has been in negotiations with Russia’s Gazprom for over seven years concerning the construction of a Sino-Russian pipeline. In late 2015, their respective executives signed a memorandum of understanding to support research to determine the project’s technical and commercial details.12 China’s domestic pipeline network has expanded rapidly, and some assessments expect China to construct over 300,000 km of additional gas pipelines between 2010 and 2022 to service and distribute overland gas domestic and imported supply (Economides and Xie 2010). Despite this rapid progress, Chinese analysts and policymakers retain concerns about the security of pipelines, including routes being considered under the aegis of Beijing’s heralded One Belt, One Road infrastructure development and trade initiative. A senior Chinese government think-tank expert with whom one of the authors spoke in early 2015 emphasized in particular concern by Beijing that the pipeline through Myanmar was vulnerable to

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ethnic minority guerrillas. Given the possibility of long-term deterioration in Sino-Russian relations, Chinese planners likely seek to avoid overreliance on pipelines from Russia. Meanwhile, sabotage or terrorism concerns could extend to China’s pipeline from Turkmenistan. Clearly, overland pipelines have significant limitations and vulnerabilities. Pipelines are more vulnerable to sabotage and military interdiction than is seaborne shipping, which is very flexible and can be routed around disruptions. Seaborne imports, by contrast, offer more diverse supply options, with far less risk in many respects, and are virtually always cheaper than overland alternatives thanks to the cost-efficiency of tanker shipping. In 2014, China imported 27.1 bcm of LNG by sea from more than sixteen nations, from a far greater variety of nations than the four pipeline supplier nations listed above. Of this, China imported 9.2 bcm from Qatar; 5.2 bcm from Australia; 4.1 bcm from Malaysia; 3.2 bcm from Indonesia; 1.4 bcm from Yemen; 1.0 bcm from Equatorial Guinea; 0.4 bcm from Papua New Guinea; 0.3 bcm each from Algeria and various European countries; 0.2 bcm each from Trinidad and Tobago, Norway, the Russian Federation, Oman, Angola, Egypt, and Brunei; and 0.1 bcm from South Korea (British Petroleum 2015: 28). LNG imports thus represent a wave of the future for China. This supply diversification has been facilitated by an uptick in LNG terminal construction in recent years.13 After China National Offshore Oil Corporation (CNOOC) opened the Guangdong Dapeng terminal in 2006, for instance, the energy giant completed two more terminals in Fujian and Shanghai within three years. CNPC and Sinopec have also entered the market. China currently has more than ten LNG receiving terminals in operation—an impressive feat for a nation that did not consume LNG until 2006, when it opened its first terminal. Terminal construction in the past decade has likely been facilitated in part by the geographic reality that China’s coastal urban areas lack natural gas resources. The majority of domestic reserves are located in western regions and hinterland provinces such as Heilongjiang, Inner Mongolia, Shaanxi, Shanxi, Sichuan, and Xinjiang. Though coastal regions are the primary drivers of natural gas demand, only about 10 percent of China’s domestic gas reserves are located along the coast (Ni 2007). Thus, most cities in China’s coastal provinces must rely on some form of transported natural gas, either pipeline gas or LNG. Purchasing natural gas via pipelines, as opposed to nearby terminals, is often relatively uneconomical for coastal cities because the gas must be transported long distances to reach end users (Kang and Wang 2009).14 Conversely, LNG from China’s trading partners arrives directly at coastal terminals. Once regasified, it can be shipped via regional pipeline networks to urban centers along China’s eastern seaboard at prices that are

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likely to be competitive with pipeline gas from Central Asia and Western China. At the very least, overland transportation distances can be significantly reduced. With lower transport costs from terminals to city end users along the coast, LNG is increasingly attractive to a modest but growing share of coastal Chinese consumers. Furthermore, at less than 1/600 the volume of natural gas in the gaseous state, LNG is also very convenient to store, which is beneficial given seasonal fluctuations in residential gas demand. This is especially advantageous for crowded coastal regions with peak energy use seasons and thus the need to store energy reserves locally. LNG’s modest market capture is not unique to China. Its role in global and regional markets has risen in recent decades. LNG’s role in global gas trade has increased considerably throughout the end of the twentieth and beginning of the twenty-first century. While LNG accounted for just 10 percent of all gas traded worldwide in 1975, nearly 30 percent of all internationally traded gas was in the form of LNG by 2010 (Stern 2012: 41). Between 1982 and 2010, Asian imports of LNG accounted for an average of approximately 70 percent of total world imports. In 2010, Asian countries combined to make up 60 percent of global LNG imports (Stern 2012: 41– 43). Although maritime gas imports may be more convenient for China’s coastal economy for the above-mentioned reasons, offshore gas development holds more attractions. It allows China to avoid the risks of relying on land-based natural gas development outlined above while lowering dependence on other states to provide reliable gas supplies. All of these facets of China’s intricate energy security outlook have motivated Beijing to diversify the sources of its energy supply, albeit incrementally. This is one reason that pursuing energy and security interests in the SCS and other geopolitically volatile regions is important for China. As the following section demonstrates, core strategic issues such as national sovereignty remain paramount. It is thus important to consider the moderate rise of natural gas as a fuel source in China within regional and global contexts. The interplay of energy economics and geostrategic forces can create both opportunities and constraints on China and other states; so far, it is largely China that is enjoying opportunities, and its neighbors that are constrained. The Geopolitics of Chinese Oil and Gas Development in the SCS

From China’s perspective, the SCS demonstrates to some extent the geopolitical value of local hydrocarbons. It is important to note that Chinese oil and gas development in the SCS is only one of many ways Beijing could

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develop or obtain new sources of energy, and the energy gains from this region are comparatively modest. Examples of alternatives include working to expand pipeline gas and oil supplies from neighboring states such as Myanmar, Turkmenistan, Kazakhstan, and Russia; developing offshore oil and gas in other regional waters such as the East China, Bohai, and Okhotsk Seas; securing greater import volumes from current LNG suppliers such as Australia, Malaysia, Mozambique, and Qatar; and pursuing higher levels of gas development from primary domestic reserves such as the Tarim basin.15 The significance of the SCS and China’s offshore development therein lies not in the size of energy gains Beijing can secure form the region but in the interplay of pragmatic economic and energy concerns and Beijing’s longterm geostrategic interests in Asia. Beijing’s overseas initiatives to secure pipeline gas and seaborne LNG imports are one component of China’s push to diversify its energy stocks. From a strategic perspective, these initiatives may be less than ideal because they increase China’s reliance on external partners. This logic is by no means unique to China. Beijing is thus understandably interested in finding new sources of natural gas closer to home, including in the maritime regions surrounding China in which it has unresolved sovereignty claims and calls the “Near Seas,” which allow Beijing to achieve greater energy diversity and security without increasing dependency on distant trade routes. As this section argues, offshore LNG development in its current emerging state is but a small component of long-standing regional geostrategic complexities; however, it has the potential to create distinct security challenges and opportunities for China and neighboring states as natural gas development here expands in both scale and intensity. China will likely be at the heart of regional gas engagement, since it has the best technology and largest investment capacity among SCS coastal states needed to sustain long-term natural gas development and LNG conversion offshore in the SCS. Because the notion of an East Asian unified gas grid remains a pipe dream for the foreseeable future due to strategic mistrust among regional states,16 shipborne LNG will likely be a useful channel for distributing offshore gas to consumers. What is unique to China among SCS coastal states is its overwhelming power and willingness to brandish that power to pressure and coerce its neighbors. China’s behavior in the SCS is arguably the strongest example of increased assertiveness in Chinese foreign policy since 2010 (Johnston 2013). Nearly all analysts accept, to varying degrees, the notion that Chinese policies in the SCS have grown bolder in recent years, reflecting the economic and strategic significance Beijing attaches to this region. The SCS thus offers a rare glimpse into how China behaves when “core” political interests intersect with strategic economic opportunity.

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China is one of several states in the region with escalating energy security concerns. The majority of East and Southeast Asian states are relatively poorly endowed with energy resources and currently have economic systems characterized by high energy intensity and trade dependency (Schofield 2011: 3). States such as the Philippines, Vietnam, and Indonesia are industrializing and otherwise developing their economies from a low baseline, resulting in greater expectations by citizens in these countries for higher standards of living and more modern amenities. The Philippines and Indonesia are now net oil importers, and during 2000–2012 Vietnam experienced a 100 percent oil products demand increase (US EIA 2013i). Similarly, developed Asia Pacific states such as Japan and South Korea are enormously import-dependent with regard to energy and other inputs to their economies. They rely on stable maritime commerce through regional waterways, including those of the SCS. Indeed, IEA figures suggest that Southeast Asian and Chinese demand growth, coupled with maturing production there, are likely to quadruple net oil imports by 2030. If that is indeed the case, imports would account for 74 percent of Southeast Asia’s oil demands, compared with 25 percent in 2008. More broadly, according to the IEA, Asian states collectively accounted for 12 percent of world energy supply in 2010, up from just 5.5 percent in 1973 (IEA 2012c: 8–9). In 2011 Asia produced just 4.2 percent and 9.6 percent of world crude oil and natural gas, respectively, and has consumed over three times the amount of oil it produces throughout much of the twenty-first century (IEA 2012c). In 2009 SCS states relied on imports for nearly 60 percent of their oil consumption. Concerns about sea lane security and other supply security issues are driving forces behind East and Southeast Asian states’ desires to secure more domestic oil and gas resources, including in offshore territories (Owen 2011). Brunei became the only East/Southeast Asian crude oil net exporter. Regional Perceptions on Energy Development in the SCS

The SCS has long been viewed as a maritime region fertile with offshore resource stocks. Others have argued that energy, minerals, and fish are the three resources that will most likely affect SCS states’ behavior (Rogers 2012: 86–87). Energy stocks in particular have resulted in the region being dubbed hyperbolically as a potential “new Persian Gulf” (Rogers 2012: 88) or, as some People’s Liberation Army (PLA) and other Chinese government sources have called it, a “second Persian Gulf.” 17 Wu Shicun, director of China’s National Institute on South China Sea Studies, states, China’s Natural Gas Aspirations in the SCS

China’s Resource Drive into the South China Sea The South China Sea is one of the most important economic assets in the eastern hemisphere. Not only is it the main economic lifeline between the Pacific and the Indian oceans, but its rich natural resources are strategically significant to all surrounding nations. Its underlying reserve of petroleum and natural gas is so enormous that the South China Sea has been dubbed “the second Persian Gulf,” drawing the attention of countries beyond its immediate area. (Wu 2014: xv)

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The PLA’s first English-language volume on strategy goes so far as to state that the SCS possesses “rich oil reserves equivalent to that of [the] Middle East” (Peng and Yao 2005: 441). Two analysts state, “oil and gas reserves could reach 3.5 billion tons [or more than 25 billion barrels of oil equivalent] . . . [and is] extremely important for China’s economic development” (Zhang and Zhang 2003: 47). In terms of their ability to secure East and Southeast Asian economies’ growing energy requirements, however, these resources’ scale and significance has been exaggerated in several major dimensions, including volume and ease and efficiency of extraction. Although substantial resources exist, Asian economies that would potentially develop more energy resources from the SCS face common energy challenges whose magnitude outweighs potential SCS seabed energy gains, such as burgeoning domestic economies spurred by industrialization and productivity declines in existing onshore energy resources. As Nick Owen argues, secure energy imports are more important to the energy security of China and other states in the region than are SCS energy deposits (Owen 2011: 11–14). This makes the security of the SCS as an energy transit corridor considerably more important than its role as a source of energy supply, for China and other Asian states alike. To be sure, an important dimension of China’s “Going Out” policy is to secure regime legitimacy through sustained economic prosperity. One component of economic growth has been acquiring resources—including energy supplies, raw materials technology, and human capital—outside of China. Energy security is certainly a notable subcomponent of this broad calculus, as all modern economies rely on fuel, electricity, and various forms of power generation to operate and expand. Thus, energy development in the SCS is not simply a matter of fulfilling energy needs. The highest priority for states in the region, including China, is upholding and consolidating national sovereignty. The second priority is arguably securing stable maritime transportation routes. Diversification of supply makes actually exploiting these energy stocks less pressing than upholding sovereignty and safeguarding transit. For instance, any one of the three pipelines running in parallel from Central Asia (Turkmenistan, Uzbekistan, and Kazakhstan), or two LNG terminals combined, can each bring in roughly as much gas as the SCS and East China Sea fields combined.

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If local geology and reserves were as significant as some Chinese sources claim, the private sector would be pushing harder to get in; in fact, most international energy analysts remain deeply skeptical about the size and extractive efficiency of SCS reserves. Rather, security- and other state-connected forces in claimant states (China first among them) tend to hype reserves to generate domestic support for such activities as sovereignty promotion and (para)military presence expansion in the SCS. Generally, Chinese estimates of potential SCS oil and gas reserves are far more optimistic than those of other governments or Western oil corporations, reflecting the high value China places on sovereignty and SCS energy potential and its NOCs place on controlling local resources. Some Chinese analysts also see SCS energy stocks as a way to lower dependency on stable SLOCs in the Far Seas. China’s oil reserve-to-production ratio is 9.9 years, according to BP, and as such SCS production could more than double China’s reserves (Owen 2011). Estimates range from 1.6 to 21.3 billion recoverable barrels of oil. As has been noted previously, significant extractable oil and gas in the SCS would shift a portion of China’s energy assets from the Middle East and Indian Ocean to areas more accessible by Chinese air and naval military forces. Manifold factors such as political tensions and technological constraints have prevented major transitions from speculation to actual development. In terms of actual discoveries to date, the SCS is yielding considerably more recoverable natural gas than crude oil. However, it is misleading to equate potentially valuable offshore energy resources with onshore oil and gas deposits. Offshore surveying and extracting know-how and technology is expensive. As one analyst put it, SCS extraction “will depend not only on countries’ claims to offshore deposits but also on the technological capacity to access such deposits” (Rogers 2012: 86–87). One regional investment analyst with whom the authors spoke in August 2015 adds, “The oil guys I talk to agree that geologically SCS is exciting but they are skeptical that vast offshore gas pipeline networks a thousand clicks off China’s coast would be viable. In other words, a ‘pipe dream.’ Hong Kong is supplied from a CNOOC offshore gas field but it’s only 30 or 40km away.” While China possesses the capabilities to produce oil and gas from deepwater reserves, it is equally important to avoid the assumption that technological capability will prompt immediate action. Another common trend is energy diversification. Many Asian states strive to develop energy sectors besides oil as part of their long-term sustainable energy security strategies. Beijing will have to decide the most cost-effective and politically desirable methods for protecting its assets. Thus far, Beijing’s calculus is weighted heavily in favor of sovereignty- and security-supporting over money-making per se.

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Given burgeoning domestic resource demands and sensitive regional territorial sovereignty disputes, speculation and confusion over the precise quantity and quality of SCS hydrocarbon resources is not surprising. For years, debate persisted among Chinese strategists over how to proceed in the SCS. One end of the mainstream policy debate spectrum held that China, after enduring the “Century of Humiliation” and its various embarrassing naval defeats, should forcefully use its regional maritime superiority to pursue its claims assertively. The other end of the spectrum advocated the prioritization of joint development amid claims disputes; while members of this camp share the ultimate goal of recovering island and maritime claims, they were “more patient and more flexible with regard to means” (Raine 2011: 77). Since about 2009, however, the first school of thought is clearly prevailing. China’s official stance regarding SCS disputes is quite clear: Beijing will only work through disputes using bilateral communication and has no desire for multilateral discussion or international arbitration. At the enterprise level, China’s record on SCS energy development appears similarly to be hardening. While it previously appeared that Chinese energy companies were interested in development over disputes, Beijing is increasingly using its NOCs to assert China’s maritime claims. CNOOC CEO Wang Yilin, for instance, has made a series of statements about how his enterprise is pressured to perform operations that are less profitable than political. In 2012, he publicly declared the degree to which his profits are less important that CNOOC’s service as a strategic arm of state sovereignty: “Large-scale deep-water rigs are our mobile national territory and a strategic weapon” (Spegele and Ma 2012). China’s desire to sustain naval and other maritime developments in regions of the SCS, such as near the Spratly Islands, is already well-documented. Moreover, China has bolstered its regional security presence by deploying maritime law enforcement vessels and even state-controlled fishing vessels operated by maritime militia, as well as enhancing its intelligence collection efforts (Erickson and Kennedy 2016). Such activities are further supported by industrial-scale dredging and construction that has yielded well over 3,000 acres of land and transformed rocks and reefs occupied by China—primarily its seven Spratly features—into artificial islands now undergoing fortification (Erickson and Bond 2015). Shortly after Xi Jinping assumed leadership of China’s civil, political, and military governance, Beijing announced that four of China’s five separate maritime law enforcement bodies would be consolidated under the State Oceanic Administration into the China Coast Guard (CCG). A broad objective of the reform is to ensure that Beijing can more effectively control and consolidate its paranaval forces’ activities to better support national policy. Prior to the CCG’s establishment, ships from among its

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component forces engaged in multiple coercive activities to strengthen China’s energy-related positions in the SCS. According to the US Office of Naval Intelligence, the State Oceanic Administration’s China Maritime Surveillance was responsible for “protection of Chinese oil and gas survey ships operating in contested waters and preventing other countries’ exploration of similar areas.” Specifically, in 2011, China Maritime Surveillance “ships severed the cable towing sensors of a survey ship contracted by PetroVietnam.” In 2011 and 2012, Chinese maritime law enforcement ships cut survey cables of Vietnamese seismic survey ships Viking II and Binh Minh 02 (US Navy, Office of Naval Intelligence 2015: 44, 46). Most recently, China’s navy, the CCG, and China’s maritime militia have coordinated efforts in the May 2–August 15, 2014, Haiyang Shiyou 981 standoff; an event that was specifically initiated and guided by PLA organs (Kennedy and Erickson 2016). Here CNOOC deployed its billion-dollar HYSY/HD-981 oil rig much as the “mobile national territory and a strategic weapon” that Wang Yilin envisioned, moving it into waters roughly 12 nautical miles from Triton Island, disputed with Vietnam, and only 120 nautical miles from Vietnam’s coast. There China announced a security radius six times the 500-meter safety zone allowed by the UN Convention on the Law of the Sea. It deployed the maritime forces coercively to maintain an exclusion zone and thus frustrate Vietnamese efforts to prevent it from establishing a fixed position. China used CCG cutters, a fishing trawler, and commercial ships to fend off Vietnamese vessels with water cannons and ramming, while navy ships conducted “overwatch” and PLA fighter and reconnaissance aircraft and helicopters patrolled above. Beijing has thus removed previous “stovepipes” frustrating coordination and made assertive action to promote its claims. In a dedicated section of its annual report on China security issues titled “Using Hydrocarbon Rig as a Sovereignty Marker,” the US Department of Defense (DOD) documents that Chinese paramilitary ships frequently resorted to ramming and use of water cannons to deter Vietnamese ships and enforce the security cordons around the rig. In mid-May, anti-Chinese protests over the rig’s deployment erupted in Vietnam and resulted in at least two Chinese deaths and more than 100 injured, after which more than 3,000 Chinese nationals were evacuated from Vietnam. China also suspended some plans for bilateral diplomatic exchanges with Vietnam. (US Deparment of Defense 2015b)

The Department of Defense offers the following timeline:

• May 3: China’s Maritime Safety Administration announced that HD981 would conduct drilling operations off the disputed Paracel Islands.

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• May 4: China announced the start-date of drilling operations; Vietnamese Foreign Ministry protested China’s actions. • May 3–July 15: Ramming/harassment between Chinese and Vietnamese ships near HD-981.

• May 11–14: Anti-China protests erupt in Vietnam over drill rig; foreign factories are damaged.

• May 17–19: China evacuates citizens from Vietnam after two citizens die in anti-China protests.

• May 26: Vietnamese fishing boat capsized after collision with Chinese fishing boat.

• May 27: China’s Ministry of Foreign Affairs reports that HD-981 completed the first phase of exploration and was transitioning to the second phase.

• June 18: Chinese State Councilor Yang Jiechi held talks with Vietnamese officials in Hanoi; first high-level direct official contact since standoff began; no substantive progress over tensions.

• July 15: China announced the completion of HD-981’s drilling activities one month earlier than scheduled; departure of rig.18

Coming after several years of other Chinese energy-related coercion against its neighbors, the HD-981 oil rig incident suggests the lengths to which Beijing will go to use energy extraction–related activities to shore up its sovereignty claims. To a CNOOC employee who spoke with one of the authors in 2014, Beijing managed the incident as an exercise in sovereignty assertion and pressuring Vietnam, with actual energy extraction activities being minimal and exaggerated in their portrayed substance. He described Chinese reports of normal drilling benchmarks (e.g., “spud down”) as being merely a “paper drill” contrived for geopolitical purposes. He likewise emphasized the substantial Chinese maritime forces escort that the rig received. In June 2015, Beijing once again dispatched HD-981 near waters disputed with Vietnam (Panda 2015). Although SCS hydrocarbons have offered a convenient domestic rationale for actions such as those surrounding the HD-981 oil rig incident, the importance of the SCS for China may lie less in gas and oil than in controlling a maritime bastion large enough to protect its SLOCs and submarines and ultimately to develop greater potential to achieve sea control closer to the Malacca and Hormuz Straits, which really are a bottleneck for hydrocarbon imports. As a regional investment analyst told the authors in 2015, “Whether or not  China  succeeds is another matter, but I believe  they are

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much more concerned about protecting their Persian Gulf imports than hoping to discover ‘a new Persian Gulf’ within its claimed waters. I’ll be proven wrong if there are gigantic, unexpected new discoveries—but I’m not holding my breath.” Control of the SCS is like an “option” play, the analyst opined—sovereignty and security and politics first, plus a possible additional bonus of resources. How China uses its burgeoning shipbuilding industry to supply its sea forces will telegraph its evolving approach to energy opportunities and security at sea (Erickson 2016). Conclusion

Massive amounts of energy supplies are transported via the SCS in the form of maritime commerce, a dynamic on which all regional nations rely. For China, too, the SCS is important first and foremost as an energy transit corridor. Against this larger and far more important backdrop, however, offshore energy resources (real or assumed) help support geostrategic behavior by China and its neighbors to support sovereignty claims while providing some energy supplies in the process. Regardless of its regional supremacy with respect to offshore energy investment capacity, China cannot achieve total self-sufficiency across all energy sectors. This suggests that in some cases Beijing may be favoring mutually beneficial energy security gains, even with some of its largest adversaries, over more unilateral approaches. This rationale for cooperation would appear to apply far less in the context of the SCS, where sensitive overlapping territorial claims currently represent an important geopolitical flashpoint. Here, as in so many other areas, China is sovereignty-focused and coercive in the Near Seas, while potentially more cooperative in its behavior in areas beyond where it lacks sovereignty claims. Currently natural gas represents a small fraction of Chinese energy use. While this proportion and the weight carried in China’s long-term energy security strategy will continue to increase during the twenty-first century, natural gas and specifically LNG will not replace coal and oil as the pillars of China’s energy supply. This does not mean, however, that valuable lessons about China’s energy development path cannot be learned from studying these alternative sources. Moreover, as this chapter has documented, analysis of coastal China’s growing demand for LNG is a lens for examining fundamental issues that China is facing as it is increasingly forced to obtain energy supplies beyond its continental borders. This introduces a complex calculus and may yet yield new areas for cooperation. Unfortunately, in recent years in the SCS, China has been attempting to beggar and coerce its neighbors.

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The views expressed here are solely those of the authors, who thank Gabriel Collins, George Gilboy, Benjamin Purser, an anonymous investment analyst, and several anonymous reviewers for useful inputs. 1. As Yang Yufeng, senior researcher at China’s Energy Research Institute (ERI) explains, “The United States already is heading toward energy independence. China is just beginning to work on it. . . . We need to strengthen international cooperation and increase energy sources with more bilateral arrangements” (Snow 2013). There is strong sentiment among Chinese observers that global energy markets are controlled by the United States, which, as the world’s lone superpower, can manipulate the market at will to constrain China and other competitors (Herberg and Zweig 2010). 2. For example, the ongoing US shale boom is reducing its dependence on imported energy supplies (Jaffe 2013). Lower reliance helps states in many ways: it mitigates the impact of higher oil prices and reduces the need to sustain a military presence in energy-rich but unstable regions. Conversely, rising import dependency increases a state’s vulnerability to shocks that could result from economic, political, or security instability abroad, presumably beyond its control. Greater foreign energy reliance might also produce relative benefits for rivals who would presumably benefit from a greater portion of a state’s forces being deployed outside of regions central to its national interests. 3. For example, it is difficult to ascertain precisely the degree of autonomy with which these organizations operate, and the extent to which their overseas operations are tied to state interests and the pursuit of corporate profits. As Bo Kong of the University of Oklahoma puts it, “The global expansion of these Chinese NOCs will be like a symphony without conductor” (Kong 2010: 158–159). Moreover, increased international exposure ineluctably subjects China and its NOCs to greater risks, such as legal penalties incurred as a result of operating in relatively unfamiliar regulatory environments. 4. See, for example, Erickson and Collins (2011). 5. Given the unpredictability of natural and technological discoveries in this sector and alternative energy markets that affect demand for gas, strategic analysis on Chinese gas demand has been limited and inconsistent. For example, following the Fukushima nuclear disaster in 2011, Japan halted nuclear energy usage, resulting in increased demand for natural gas imports. Conversely, Japan’s recent discovery of significant methane hydrates in its southern coastal seabed could reportedly yield 40 trillion cubic feet of methane, equivalent to eleven years of current gas imports, though it is unclear whether initial optimism will be followed by gains of that size. Similarly, it is unclear whether Chinese shale gas will satiate the country’s gas demand by 2020. These game-changing events could have effects on regional gas prices, which influence the behavior of all regional states, including China. Rather than forecasting Chinese demand for natural gas, this chapter focuses on broader and presumably more stable trends that help explain Beijing’s strategic gas development. 6. Oil and LNG differ fundamentally in commercial and strategic significance. There is a single world oil market, because transport is inexpensive and the import infrastructure is ubiquitous. The trade of LNG, by contrast, is shaped by a series of bilateral agreements and regional markets because LNG is costlier to store and to move on and off ships. For cogent discussion of the strategic implications of China’s small but increasing LNG imports, see Herberg (2008: 61–80).

Notes

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7. EIA estimates for the East China Sea are 200 million barrels of oil and 1–2 trillion cubic feet of natural gas. See US Department of Defense (2015a: 5). 8. “Reforms Urged as Natural Gas Glut Falls on China,” Want China Times, August 11, 2015, http://www.wantchinatimes.com/news-print-cnt.aspx?id=20150811000029 &cid=1202. 9. Author’s interview with regional investment analyst, August 13, 2015. 10. City gas usually includes gas consumed for residential use, public service facilities, vehicles, and heating and cooling systems in urban areas. 11. Furthermore, vested Chinese energy majors’ interests in alternative energy supplies may be a significant barrier to a shale gas boom. Many believe that even if production of CBM and shale gas increased enough to be able to alter LNG demand, its presence may actually have a complementary effect. Although alternative gas sources may have potential to affect LNG demand in the long run, prospects for such a shift in domestic gas supply are unlikely in the foreseeable future. See Gascoyne and Aik (2011). 12. “Gazprom, CNPC Ink Gas Supply MoU,” LNG World News, September 3, 2015, http://www.lngworldnews.com/gazprom-cnpc-ink-gas-supply-mou/. 13. Infrastructure development, relatively expensive, was long a limiting factor. 14. Transport tariffs rise incrementally with distance, and coastal cities are often over thousands of kilometers away from the source of natural gas. As China continues its strategy of energy diversification, these distances are likely to increase—as with imports from Turkmenistan. In many cases the pipeline transport tariff expenditures can even exceed original natural gas wellhead prices for coastal cities purchasing energy from western China via the West-East Pipeline. See Kang and Wang (2009: 2–7). 15. The SCS is not the only major body of water surrounding China. Other maritime regions, though also rife with contentious island and maritime disputes, are less strategically relevant in the context of natural gas development. The East China Sea (ECS), for example, has relatively fewer gas reserves. Moreover, while the Bohai Sea has yielded substantial offshore oil, natural gas reserves are much smaller there than in the SCS. This discussion thus focuses on potential Chinese gas and subsequent LNG development in the SCS. 16. Unfortunately, energy security is not the only factor driving tensions in the SCS. National sovereignty issues, including claims disputes, are arguably far more important. 17. One Chinese government website page elaborates: “There are rich oil and gas resources in the South China Sea. Some experts call it ‘the second Persian Gulf.’” “Rich Resources in the South China Sea,” http://webcache.googleusercontent.com /search?q=cache:erOp5U7cn9wJ:www.coi.gov.cn/scs/introduction/ziyuan.htm+&cd =3&hl=en&ct=clnk&gl=us. See also Chen and Ming (2004: 12). 18. Timeline inputs taken verbatim from report. See US Department of Defense (2015b: 7).

8 Germany’s Transition to Renewable Energy Volkmar Lauber

In the field of energy policy, Germany occupies a special position among large industrial countries. It is the country of Energiewende—the radical transformation of energy supply through a shift to renewable sources, particularly in the field of electrical generation. Unlike Japan, which restarted some nuclear electricity generation in August 2015, and despite substantial fossil fuel imports of its own, Germany has opted to phase out nuclear power by 2022 (Schreurs 2014). Germany’s policies might go further still and have renewable energy replace all nuclear and most fossil fuel generation by 2050. This electricity generation transformation underpins any possible transition in electrified transport (e.g., e-mobility), which could close the loop in transforming the electrical generation and transportation systems, which in Germany were built largely on fossil fuels. This chapter focuses primarily on Germany’s changed landscape for electrical generation. In 2015, Germany obtained 29 percent of its electrical generation from renewable energy sources, but saw less than 1 percent of its new car registrations that year go to hybrid or all-electric vehicles. Germany remains behind other advanced industrial states in electrified transportation but could quickly gain ground as it did with electrical generation based on renewables. This electrical generation success has been the outcome of a grassroots movement that questioned the high priority given to new nuclear and coal plants beginning in the mid-1970s (Mayer and Ely 1998). The movement began to influence policy decisions in the 1980s and was reinforced by the Chernobyl disaster in 1986 and by growing public awareness of acid rain and climate change quandaries. The movement contributed to the global advancement of wind and photovoltaic (PV) power, helping industrialize those technologies through the German citizenry’s investment, against the wishes of the corporate monopolies operating the bulk of the electricity system (E.on, RWE, EnBW, Vattenfall; hereafter referred to as electricity incumbents). Twenty-five years ago, these electricity incumbents were a 153

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small group of rich and powerful monopolists. After electricity liberalization in 1998, they became oligopolists. Over the past few years, their position has been seriously eroded. Their survival is no longer assured. Germany made a key contribution to Energiewende by empowering civil society to conduct this transformation, developing a unique policy and regulatory framework that empowered German citizens. The government also played a key role in derailing the early and persistent European Commission efforts to ban one of the central instruments of this framework—feed-in tariffs. These played the central policy role in industrializing renewable power technologies. Over the past several years this policy framework has been weakened by German governments who have pursued the goal of slowing the energy transition. Supposedly in an effort to make Energiewende affordable and German industry even more competitive, policy has accommodated the vested interests of the electricity incumbents, who largely held on to energy types and technologies in decline. After a brief history of energy and geopolitics in Germany, this chapter explores the institutional context of the shift to renewable power. Then it analyzes the rise of Energiewende through the development of an ambitious framework to promote renewable power and detail the first efforts of an ideologically different governing coalition to constrain it. I examine the clash between renewable power and the electricity incumbents and detail the policies of the current government to rein in renewables deployment. The closing section offers reflections on the significance of Energiewende. A Brief History of Energy and Geopolitics in Germany

The unification and founding of the German Empire in 1871 promoted industrialization and the increased use of coal. Domestic coal was the main source of energy in Germany until the 1950s outside of transport, and its explosive growth coincided with Germany’s comparatively late and domestically driven industrialization at the end of the nineteenth century. Soon large corporations emerged and dominated the economy. One of the favorite themes of public discourse in this authoritarian era was geopolitics—the “German Problem.” Being a new power in both politics and industry, how should Germany secure its place in the world? This was similar to the debate in Japan in the decades before World War II (Liberman 2000; DeWit, Chapter 9 in this volume). There was wide agreement in Germany that industrial countries needed a steady flow of imported raw materials and exports of finished products to secure their wealth and power. One side of the debate argued that Germany should strive to acquire colonies of its own for this purpose. Efforts to this end were made in Africa and the Asia

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Pacific. Another side argued for autarky through territorial expansion into contiguous lands, particularly in Eastern Europe and the Caucasus. This inspired official policy in World War I and during the later period of National Socialist rule (Eichholtz 2012). A third group proposed that Germany emulate Britain, which they viewed as relying on free trade for resources and exports. Because this could expose supply lines and export routes to military challenges, the advocates of this approach argued for building up a fleet able to stand up to the British navy (Calleo 1978). Although much of this debate was about scarce resources (e.g., nitrogen needed by both agriculture and the military), energy was not as big a topic then. Germany had abundant domestic coal resources and navies were still fueled by coal. While industrial growth and political logrolling in imperial Germany led to the emergence of large and powerful corporations (e.g., the marriage of iron and rye), electricity generators and suppliers were still mostly municipal, often publicly owned, and regional in operation. Only in the 1920s did interregional, vertically integrated electric company monopolies emerge and acquire a growing share of the business, relying on larger coal generation units to fuel their grids. Their position was further strengthened by the 1935 Electricity Act of the National Socialist government, which aimed at reducing competition in the power sector. This law also favored the interregional companies without much interference from national regulation, leaving them to coordinate their own affairs through cartels and similar constructions. Nonetheless, many municipal electricity companies survived. In 1937, another law allowed expropriation of private land for the surface mining of coal. This law is still relied on today for lignite mining and led to displacing entire villages (Curry 2014; Friederici 2013). After World War II, the United States attempted to end the cartels prevalent in Germany through the first half of the twentieth century. The United States succeeded in some areas but was resisted by the electricity sector, which was successful in defending its exemption from competition in the name of its “natural monopoly.” Thus, the 1935 Electricity Act remained intact until the start of EU-driven electricity liberalization in 1998, which abolished legal monopolies except for the grid operators. A series of mergers eventually reduced the number of big incumbents to four companies, an effective oligopoly (Becker 2011; Zängl 1989). These companies were not sensitive in recent decades to grassroots political initiatives or popular majorities in favor of abandoning nuclear and coal-based generation. From the beginning, domestically mined coal played the dominant role in German electricity generation. Some wind power existed until after World War I in northern Germany, and some hydropower was developed through World War II, but they played only a small role. During World War

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II, coal became scarce because it was also used for producing motor fuels for the military (conquering oil fields in Romania and the Soviet Union’s Caucasus region was insufficient to cover transport fuel needs). After World War II, coal production was essential to reconstruction. For this reason, coal mining—and coal miners—were privileged in the first postwar decade. About 650,000 miners of hard coal and lignite were at work in 1950 (Statista.de 2015a, 2015b). In the 1950s, domestic hard coal was challenged in the power sector by cheap imported oil and later by imports of hard coal. The domestic coal sector (owners, managers, and labor unions) persuaded the government to introduce subsidies and quotas in favor of domestically mined coal. Nevertheless, oil as a fuel for electricity grew in the 1960s. Oil was 13 percent of German electricity generation in 1973, but it began to be phased out due to the oil crises of the 1970s (Auer 2014: 2). Oil still dominated in transport and heating and held a 47 percent share of total primary energy supplied in 1973 (IEA 2012d: 4). Due to the oil crisis, a new domestic coal subsidy for generators was introduced in 1974, financed by a new surcharge on consumers’ electricity bills. In 1994, the Constitutional Court held this surcharge to be unconstitutional; these subsidies were then paid from the government budget. By 2015, they reached a cumulative amount of about €200 billion (Storchmann 2005; Kuechler and Meyer 2012). For two decades, the European Commission has pressed for the reduction of coal subsidies with some success, although new ones were introduced just recently (i.e., as side payments to electricity generators for closing down lignite plants). When nuclear power developed in the 1950s, the electricity incumbents showed little inclination to build such plants. This was one of the rare occasions in which the government intervened decisively against these corporations (Radkau 2008). The government saw nuclear as an energy of the future, but some (at least in the days of Defense Minister Franz Josef Strauss) also viewed it as a strategic asset for possible nuclear weapons development. To motivate electricity incumbents to embark on nuclear power plants, the federal government practically took over their direct investment costs, while regional (Länder) governments set high sales prices for their output. In fact, quite a few of the early nuclear plants failed on technology. The electricity incumbents eventually accepted a growing share for nuclear power, and the first oil crisis caused an ambitious nuclear program to reduce German dependence on OPEC oil for electrical generation (Becker 2011). Even before the oil crises of the 1970s, Chancellor Willy Brandt (1969–1974) launched Germany’s policy of détente with the Soviet Union and its Eastern European satellites. Brandt’s Ostpolitik sought better strategic relations through energy interdependence, and imports of Soviet oil and natural gas were viewed as economically beneficial to both sides

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and likely to reduce political tension. The oil crises simply added the general motive of diversification of sources of supply through increased ties to Russia. The political risk of dependence on Russia and loss of supply due to Russian diplomacy was justified as codependence favorable to détente, which also improved Germany’s relative autonomy from the United States, United Kingdom, and the Netherlands. Prior to the outreach to Russia, these actors controlled all German oil supplies and most of its natural gas supplies (Högselius 2013: 105–125; Newnham 1998; Jentleson 1986). The gas supply disruptions from conflicts between the Ukraine and Russia began only in 2006; in the late 1970s and early 1980s, they were not seen as risks worthy of constraining cheap oil and natural gas imports from Russia. This was geopolitically motivated all around, and Germany took advantage of Russia not having many alternatives for its gas exports. Nonetheless, even in retrospect, national policy concerns for energy security played only a limited role in German post–World War II energy politics. The Cold War system answered Germany’s prewar geopolitical debate, and in effect resolved the German Problem, allowing German industrial and commercial performance to thrive with unfettered access to markets for its energy imports and industrial exports (Stokes 1994; Calleo 1978). Access to oil was guaranteed by the United States, and détente with the Soviets created diverse supplies of natural gas for Germany, solving the German dilemma through energy dependence on both superpowers. As to electricity generation, nuclear energy was favored as a technology of the future more than for reasons of autarky, with breeder and fusion reactors on a more distant horizon. Only after the onset of the oil crises did the German government also start a comparatively modest research program in renewable energy. The relative absence of energy security concerns made energy policy almost exclusively the province of the Ministry of Economic Affairs. This ministry was also the main governmental patron of the electricity incumbents, who enjoyed considerable freedom from competition and supervision. Its insular and apolitical focus may have created an opportunity for groups invoking the public interest to challenge the ministry on key social and political issues. Beginning in the 1960s, social movements developed in Germany that were concerned with the environment. Numerous citizen initiatives challenged public policy at many levels. This was quite unusual for German politics. When the 1973 oil crisis occurred, the government overestimated future demand, as in France, and planned to greatly expand nuclear and coal power to reduce dependence on OPEC. This met with protests and proposals for alternatives, and renewable energy became a popular topic. This is when the term Energiewende was first coined. Opponents of nuclear power became a large majority after the Chernobyl disaster in May 1986 (Jahn 1992). The four major German political parties

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addressed energy with renewed seriousness of purpose, and due to the proportional representation electoral system, even small parties could play a significant role in parliament. The opposition Green Party demanded an immediate shutdown of all nuclear plants, while the Social Democrats demanded a gradual phase-out. The Green Party advanced its share in the 1983 election, when they received 5.6 percent of the total vote, and in 1987, they claimed 8.3 percent. Despite internal dissent, the leaders of the governing Conservative and Liberal parties insisted that German nuclear plants were the safest in the world. Coal became controversial at first due to acid rain, an issue to which climate change was added in the mid-1980s. Driven by the public discourse and mobilization, the lower house of parliament, the Bundestag, set up a very effective committee on climate change whose many proposals included one to introduce a feed-in tariff for renewable power (Jacobsson and Lauber 2006). However, the Ministry of Economic Affairs rejected this particular proposal, arguing that renewable power would need perpetual subsidies. The Bundestag then took matters into its own hands, a highly unusual procedure in German politics. The Context of Electricity Policy

After liberalization in 1998, the former electricity incumbent monopolists engaged in a series of mergers. Today, four large corporations dominate: Rheinisch Westfälische Elektrizitätswerke (RWE), E.on, Energie BadenWürttemberg (EnBW), and Vattenfall (a Swedish subsidiary). Their electrical generation relies almost entirely on conventional fossil fuels and nuclear power. In addition to these electricity incumbents, there are hundreds of municipal electrical enterprises. Some of these are owned by an electricity incumbent or maintain a privileged relationship with one. They operate smaller power and combined heat and power plants, and they are responsible for power distribution. Their share in renewable generation is similarly modest, but some of them have supported renewable power. There are also about 1.5 million independent renewable generators, about half of which are owned by citizen investors or farmers and the rest by banks, developers, insurance companies, and so on (trend:research 2011). They operate under the framework of the 2000 Renewable Energy Act (EEG) and its many subsequent amendments (e.g., EEG 2014). Political governance of the renewable power sector currently lies largely within the Ministry of Economic Affairs. Between 2002 and 2014, governance resided with the Environment Ministry. Although Economic Affairs has been the main political actor in the power sector, parliament, not the Main Actors

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executive, has been the key actor in founding renewable power policy, and it has been much more committed to renewables deployment than the executive (Jacobsson and Lauber 2006). Several versions of the EEG (2000, 2003, 2004) and its predecessor laws from 1990 and 1997 were adopted against the express preferences of various coalition governments and their Economic Affairs Ministries. The German people have played a key role in this atypical parliamentary governance pattern, as an overwhelming majority has embraced Energiewende. Engaged citizen participation in renewable energy has created hundreds of local and regional initiatives and a passionate electorate whose representatives long reflected this popular will. The European Union has been another key actor because the European Commission has been focused on market liberalization and (most of the time) on the removal of German-style feed-in tariffs. However, the Commission was usually countered effectively by the German Parliament and the EU Council. The Evolution of Germany’s Power Mix

Figure 8.1 shows the shares of various energy sources for generating electricity. Between 1990 and 2014, there was a clear shift away from conventional fossil fuels. Nuclear power declined beginning in 2008, well before the Fukushima disaster and the second German phase-out decision in 2011. Since 2007, hard coal use has also decreased. Natural gas use increased until 2010, but then went into decline despite more nuclear plants being closed after Fukushima. In 2016, it experienced a considerable surge, partly because of lower prices (Toptarif 2016). Lignite use declined slowly and, like hard coal, experienced a resurgence around 2009. During the same period, renewables grew from some 20 terawatt-hours (TWh) in 1990 to about 160 TWh in 2014, from 3.6 percent of gross domestic electricity consumption to 28 percent. This exceeded the ambitious targets laid down in successive EEG amendments through 2009. All new renewable sources were deployed in the same time frames, but their periods of greatest annual installations varied. Wind was the first to take off, then it declined a little after 2002, then grew to an even higher peak in 2014–2015. It was followed by biomass, then PV, whose annual installations peaked in 2009–2012 (see Figure 8.2). The EU Emission Trading System and Power Plant Construction

The EU Emission Trading System (ETS) started in 2005. It was expected to curb carbon-intensive coal use and encourage natural gas, reducing overall

Figure 8.1 Gross Electricity Generation in Germany by Sources, 1990–2014

Source: Adapted from AGEB (2015).

Figure 8.2 Renewable Power Generation by Energy Source, 1990–2014

Source: Adapted from AGEB (2015).

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greenhouse gas emissions. Until 2008, this expectation led electricity incumbents to build many new gas-fueled power plants. But overallocation of carbon allowances in the early years of ETS soon created lower carbon prices than expected, making them almost irrelevant. During the short period of high certificate prices, utilities adopted the practice of selling allowances, which they had received free of charge. This created windfall profits in the billions, while the provision of free grandfathered emission permits for new coal plants created incentives to invest those profits in new coal plants (Pahle 2010). The boom in fossil fuel power plant construction, the overall stagnation of electricity demand, and the rise of renewables all contributed to excess generation capacity in recent years (Fraunhofer ISE 2015a, 2015b). Germany also became a net exporter of electricity, with exports amounting to about 8 percent of total generation in 2015. It is often claimed that natural gas plants could help reduce the intermittency problem for wind and solar generation, but since 2010, German utilities have actually reduced natural gas generation, favoring lignite instead. Lower prices for emission allowances and higher gas prices relative to coal contributed to this unhealthy remix to coal (see Table 8.1). The Rise of Energiewende

The debates about a new energy paradigm in the 1970s and 1980s led to the first legislative act in 1990 introducing a feed-in law. Another ten years went by until a Red-Green majority government adopted the EEG in 2000. This ambitious act foresaw a complete shift to renewables, but had no specific targets beyond 2010 and little practical understanding of how to boost renewables from 6 percent of the energy mix in 2000. After another decade, in 2010, a Conservative-Liberal government laid down long-term targets for the transition to renewables (i.e., 80 percent by 2050), but this was already an effort to moderate the so far exponential speed of energy transformation. Only EEG 2014 brought a far-reaching reorientation toward slower, indeed muted renewables deployment, a trend reinforced by EEG 2016. From R&D to the First Feed-in Law

In the late 1980s, and after more than a decade of research and development (R&D) support for renewable power technologies, it became clear that these needed market support if they were to progress. The form and extent of this support has been controversial ever since. Inspired by Denmark’s experience with voluntary tariffs paid by electric companies (Van Est 1999), the Bundestag recommended a legally based feed-in tariff for small renewable

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Table 8.1 Gross Electricity Generation (TWh) by Energy Source, 1990–2015 Energy Source

Lignite/brown coal (% total generation) Hard coal (% total generation) Natural gas (% total generation) Nuclear (% total generation) All renewables (% total generation) Offshore wind (% total generation) Onshore wind (% total generation) Photovoltaic (% total generation) Hydroelectric, biomass, other renewables (% total generation) Total generation Electricity exports Net electricity exports

1990

1995

1998

2000

n/a

1.5 (0.3) 0

4.5 (0.8) 0

9.5 (1.6) 0

19.7

23.6

21.7

28.3

−0.8

−4.8

0.6

−3.1

170.9 (31.1) 140.8 (25.6) 35.9 (6.5) 152.5 (27.7) 19.7 (3.6) n/a

n/a

142.6 139.4 148.3 (26.6) (25) (25.7) 147.1 153.4 143.1 (27.4) (27.5) (24.8) 41.1 50.7 49.2 (7.7) (9.1) (8.5) 154.1 161.6 169.6 (28.7) (29.1) (29.5) 25.1 26.3 37.9 (4.7) (4.7) (6.6) n/a n/a n/a

549.9 536.8 31.1 34.9

Source: AGEB (2016).

557.2 576.6 38.9 42.1

2005

2010

2011

2012

2013

154.1 (24.8) 134.1 (21.5) 72.7 (11.7) 163 (26.2) 62.5 (10) n/a

145.9 (23) 117 (18.5) 89.3 (14.1) 140.6 (22.2) 104.8 (16.6) n/a

150.1 (24.5) 112.4 (18.3) 86.1 (14) 108 (17.6) 123.8 (20.2) n/a

160.7 (25.5) 116.4 (18.5) 76.4 (12.1) 99.5 (15.8) 143.8 (22.8) n/a 50.7 (8) 26.4 (4.2)

160.9 (25.2) 127.3 (19.9) 67.5 (10.6) 97.3 (15.2) 152.4 (23.9) 0.9 (0.1) 50.8 (8) 31 (4.9)

34

55.3

55.3

56.8

69.6

8.5

17.7

27.2 (4.4) 1.3 (0.2)

37.8 (6) 11.7 (1.8)

622.6 633.1 61.9 59.9

48.9 (8) 19.6 (3.2)

613.1 56 6.3

630.1 67.3 23.1

638.7 72.2 33.8

2014

2015

69

69.3

155.8 155 (24.8) (24) 118.6 118 (18.9) (18.3) 61.1 61 (9.7) (9.4) 97.1 91.8 (15.5) (14.2) 162.5 187.4 (25.9) (29) 1.4 8.3 (0.2) (1.3) 55.9 70.9 (8.9) (11) 36.1 38.7 (5.7) (6)

627.8 74.5 35.6

generators. The Ministry of Economic Affairs and the big utilities were hostile to such a measure. By the late 1980s, many German members of parliament (MPs) were frustrated by Economic Affairs, and in 1988, two Conservative MPs took things in their own hands. They submitted a private members’ bill for a feed-in tariff—clearly a rebellion against their own Conservative-Liberal executive. Although the government warded off this bill, it gave in when a second bill was submitted in 1989. Chancellor Helmut Kohl’s government wanted to avoid conflict over a popular issue before an upcoming election. For their part, the electricity incumbents were preoccupied with absorbing East German utilities during reunification. Thus, the 1990 Feed-in Law passed parliament unanimously but “by accident” (Laird and Stefes 2009; Jacobsson and Lauber 2005; Kords 1993). The 1990 Feed-in Law required all German utilities to grant access to the grid and pay supportive prices for renewable power tendered by small generators that were not utilities and not publicly owned. Support was expressed as a percentage of household electricity prices, then fixed by reg-

645.6 85.2 51.8

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ulated tariffs. These are payments from the utilities to these new nonutility renewable energy generators (NREL 2010: 9). Despite widespread expectations that the law would add only a few percentage points to the power supply, it initiated remarkable growth. From 1990 to 1999, wind power generation increased by a factor of seventy-eight, from 71 gigawatt-hours (GWh) to 5,528 GWh. This was crucial for the wind turbine industry’s development. Solar power generation grew by a factor of thirty, from 1 GWh in 1990 to 30 GWh in 1999 (BMU 2013: 18). The big utilities affiliated with the electricity incumbents challenged the law in various German courts, the European Commission’s Directorate for Competition, and eventually before the European Court. They had no success (Hirschl 2008). By the middle of the 1990s, the new law had attracted significant political backing beyond its original supporters: the metal workers’ labor union, farmers, church groups, and the influential Verband Deutscher Maschinen und Anlagenbau (the Association of German Machinery and Plant Industries). On the recommendation of the EU Commission in 1997, the Conservative-led government tried to get the Bundestag to reduce feed-in tariffs but was rebuffed by some of its own MPs. This was a remarkable rebellion within the governing coalition’s own ranks, in a legislature with a tradition of very strong party discipline (Jacobsson and Lauber 2006). In September 1998, a coalition government of Social Democrats and Greens replaced the Conservative-Liberal government. This was the Greens’ first turn in government. A radically different energy policy had been central to the Greens since their beginning in the 1970s. After Chernobyl, they committed themselves to the immediate phase-out of nuclear power, and their new partners, the Social Democrats, committed to a gradual phase-out of nuclear power. The Social Democrats also had a strong “coal faction” within the party, which supported coal power and coal subsidies. In the governing coalition, the two parties adopted key reforms such as the EEG of 2000, its 2004 amendment, and a nuclear phase-out within about two decades. The adoption of EEG in 2000 created friction between the executive and the Bundestag. The nonpartisan minister of Economic Affairs (a former utility executive) and some top Social Democrats favored a quota-and-certificate system that would only support cheap energy technologies (essentially a renewable portfolio standard). The European Commission also advocated a quota system in an upcoming directive and had already attacked German feed-in tariffs. But the Greens prevailed with their philosophy of supporting renewable power technologies across the board, with fixed and differentiated tariffs, to accelerate the learning curve and support initially more expensive technologies early on. EEG 2000

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The Social Democrats accepted this to build up a new wind turbine industry and shield it from potential falling electricity prices that might result from liberalization. They also extracted concessions to protect coal power against “excessive” growth of natural gas plants. The EEG of 2000 was a major policy innovation. It created an unlimited purchasing obligation for utilities to accept all renewable electricity tendered to them. They were required to pay generators fixed tariff amounts for twenty years based on the current cost of a given renewable technology and a small profit—recalling the “fair return on investment” regulation of the preliberalization era. Tariff amounts were differentiated by technology, size, site quality, and so on, making a whole range of renewable power technologies profitable at modest rates of return, which proved attractive to citizen investors but not to incumbents (Morris and Pehnt 2015: 35–38). Regular tariff reductions for each year’s vintage of new installations were written into the act to limit windfall profits, incentivize innovation, and lower costs. This policy intended to break the vicious circle of high prices, small production runs, and limited rollout, which were key hurdles for renewable power. Bigger demand would industrialize this sector’s equipment industry, drive innovation, and reduce costs (EEG 2000, Explanatory Memorandum). The act also meant to at least partially compensate for external costs, that is, those costs not paid by conventional generators, which distorted competition (Lauber and Jacobsson 2015). The extra cost caused by feed-in tariffs was to be borne by electricity consumers through a surcharge on electricity bills. It was low at first, even tiny compared with the billions of euros that had gone to nuclear and coal (Kuechler and Meyer 2012). It was expected to stop growing when the declining cost curve for renewable power intersected with the expected upward cost curve for fossil-based power. The purpose of the law went far beyond creating small niches for green power. Its long-term intent was quite simply the replacement of nuclear and fossil-generated electricity. Nuclear power’s 30 percent of total electrical generation was to be phased out within about two decades. The mediumterm goal was to reach at least 12.5 percent renewable power by 2010 (Lauber and Jacobsson 2016; Jacobsson and Lauber 2006). Renewable electricity was prioritized and fossil fuels were to provide only “residual load,” although no coal phase-out was stipulated in the law. Conservatives, Liberals, and others in the Bundestag rejected both the nuclear phase-out and EEG, which they viewed as overly expensive (excessive feed-in tariffs, no direct price competition, etc.). Some Conservative MPs wanted to fund R&D but not effective market creation for fear of perpetual subsidies (Deutscher Bundestag 2000, 1999). They did not, however, question the planned doubling of renewable electricity generation to 12.5 percent by 2010 (Hirschl 2008: 142). All but a few Conservative MPs rejected the bill and lamented

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the 1990 Feed-in Law, but several Conservative-led Länder voted in its favor in the Bundesrat (the upper house of parliament). For their part, the Liberals argued that support should be smaller, focus on innovation, and come from the budget, not consumer surcharges. Both opposition parties wanted a smaller protective space for renewable power, and this only as a temporary exemption from eventual market discipline (Smith and Raven 2012). The constellation of actors outside parliament in 2000 was similar to 1998. Public opinion was highly supportive. The incumbent-dominated electrical utilities association and the Federation of German Industry strongly condemned the bill for exorbitant costs. They placed their hope in the European Commission’s Energy and Competition directorates, which opposed feed-in tariffs as incompatible with state aid regulations and liberalization. A case addressing the 1990 Feed-in Law was then pending before the European Court (PreussenElektra v. Schleswag). German opponents to the law hoped that a court decision in their favor would annul the law, or that a new government would repeal the act. At the same time the electricity incumbents abstained from investing in renewable power generation in their own utilities even though they were now eligible for EEG support. The 2000 law created a chance for modest profits and a high level of investor security through predictable feed-in tariff revenue streams. This made it easier to obtain bank financing. Although many utilities rejected such investments, these became popular with private citizens, farmers, and various businesses. The Red-Green coalition welcomed this reallocation of economic power. By 2010, nonutilities had financed nearly 90 percent of cumulative renewable generation capacity, which stood at 57 GWh of installed capacity in 2010 (BMU 2013: 20). Fifty-one percent of this came from private citizens and farmers, for a total of nearly a million citizen-investors. In 2010, the electric utilities’ share in this development was small, with all electric utilities making up only 13.5 percent of the total renewable generation (trend:research 2011: 45; see Table 8.2). By 2012, this electric utility share was reduced even further to 12.5 percent, as the installed capacity of renewables soared to 77 GW. While the citizens’ cumulative ownership share fell only slightly to 46.6 percent, the share of institutional and strategic investors rose to 41.5 percent from 34.8 percent in 2010 (trend:research and Leuphana Universität Lüneburg 2013: 42). EEG 2004 and EEG 2008: Market Expansion and Political Fragmentation

Building on the tremendous societal support for renewables, in 2003, a special amendment extended full cost tariffs to solar PV. This was adopted unanimously by all Bundestag parties to ward off a crisis in the solar power

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Table 8.2 2010 Ownership Share in German Renewable Power Generation by Investor Type Owner Types

Private persons Farmers Project developers Investment funds/banks Industry Contracting firms Four biggest electric utility incumbents International electric utilities Other electric utilities Regional generators Other

Percentage Share 39.7 10.8 14.4 11.0 9.3 0.1 6.5 2.7 2.7 1.6 1.2

Source: Adapted from trend:research (2011). Note: Total installed capacity in 2010 was 53.0 GWh in the trend:research count (lower than BMU 2013).

industry. A comprehensive amendment (EEG 2004) followed and brought more favorable tariff rates for biomass and offshore wind. This served chiefly Conservative and Liberal clienteles—farmers, landowners, and electricity incumbents. Nevertheless, the Conservative-Liberal opposition rejected the bill’s target of 20 percent renewable power by 2020. The Conservatives wanted the law to expire by 2007 and be replaced by a bonus or tender system compatible with the ETS (Deutscher Bundestag 2004). Some of these MPs proposed to terminate all financial support at the 12.5 percent renewable threshold or limit it by an annual cap, supposedly to make technologies competitive more quickly and make them decline if they faltered. The Liberals demanded a technology-neutral quota system, unaware of its poor performance in the United Kingdom (Deutscher Bundestag 2004: Brunkhorst/Fell exchange). Thus, both opposition parties were eager to restrict renewables’ protective space in terms of the extent and duration of support. Between 2000 and 2004, the political alliances around EEG support changed. In 2002, jurisdiction over renewable power was transferred from the Social Democratic Party–controlled Ministry of Economic Affairs to the Green Party–controlled Ministry of Environment, which built up a dynamic team of strong EEG advocates (Buschmann 2011). The coalition favoring EEG grew to include the giant confederation of small and medium enterprises and the trade union of service workers. As usual, the electricity incumbents, now reduced to four, rejected the feed-in tariff system. E.on warned of grid destabilization and increased blackouts (Hirschl 2008: 161). These warnings became a permanent though unwarranted feature of the electricity incumbents’ narrative, which was reflected in

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Conservative and Liberal opposition MP circles. The increase in wholesale electricity prices after a few years of competition held down renewable energy surcharge increases, weakening the cost argument against renewables (see Figure 8.3). While Conservative and Liberal MPs voted against EEG 2004 in the Bundestag, six out of nine Conservative-ruled Länder supported it in the Bundesrat (upper chamber). The 2005 election brought in the “grand coalition government” of the two major parties, that is, the Conservatives and the Social Democrats. In view of their nearly equal strength, the two parties agreed to continue previous policies regarding EEG and the nuclear phaseout. Consensus on EEG seemed to emerge, and electricity incumbent opposition met with increased skepticism. Polarization between the Economic Affairs and the Environment ministries decreased (Buschmann 2011). With support from agrarian and other interests, some Conservatives embraced EEG as their ecological wing formed an alliance with the Social Democrats. Having rejected in 2004 a renewable power target of 20 percent for 2020, in 2008 the Conservatives supported one of “at least 30 percent” for the same year. Nonetheless, Conservative MPs did demand steeper future cuts in

Figure 8.3 Quarterly Average Baseload Power at EPEX Spot, per Quarter, 2000–2015

Source: EEX Leipzig (http://www.eex.com/de/marktdaten/strom/spotmarkt/kwk-index/kwk -index-download).

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feed-in tariffs and “direct marketing.” They wanted renewable power generators to sell to the spot market, not to distributors or suppliers, as they had done until then on better terms. For their part, Social Democrats agreed that fluctuating wind and solar power needed to become “base load capable,” as if this were a mere matter of legal regulation (Deutscher Bundestag 2008; interventions by Gabriel, Becker, and Hempelmann). True to his party’s industrial roots in coal and steel, Social Democratic Party Environment Minister Sigmar Gabriel planned new coal plants through 2030, but without carbon capture and storage technology. Disharmony in this governing coalition arose in 2008, when the Conservatives’ business wing objected to what it considered to be excessive support for solar power. PV was then the technology furthest away from market competitiveness, and its support soon entered a phase of rapid decline, as Table 8.3 shows. Conservative Party business leaders also favored nuclear and coalbased carbon capture and storage and questioned the logic of renewables’ capacity to replace this residual load. They sought to stop the growth of solar in particular. In 2008, they argued for a radical 30 percent PV tariff cut, an annual installation cap of 600–700 MW, and a shift of support from deployment back to research. When they were thwarted, they looked for revenge via a future alliance with the Liberals (Podewils 2008). Only the Greens were confident that renewables deployment would render both nuclear and new coal plants unnecessary. Interestingly, Hans-Josef Fell, a key Green MP for matters regarding EEG, also argued for a flexible PV tariff reduction scheme that would adjust feed-in tariffs automatically and prevent excessive costs from accelerated PV installations. For its part, the European Commission remained passive, as EU directive 2001/77/EC on renewable electricity left member states free to choose among different types of support, including feed-in-tariffs. The EU Court’s 2001 PreussenElektra v. Schleswag decision rejected the Commission’s claim that German feed-in tariffs violated EU state aid and internal market regulations. In 2007, EU Energy Commissioner Andris Piebalgs did not support another attack on German feed-in tariffs. For the first time it seemed that the EU might end its active resistance to Germany’s feed-in tariffs. Table 8.3 Evolution of German Feed-in Tariffs for Photovoltaics, 2004–2013 Feed-in Tariffs in Eurocent

January 2004 January 2008 January 2012 October 2013

Rooftop < 10 kW

Source: Adapted from Chabot (2013).

57.60 46.75 24.40 14.25

Ground Mounted < 10 MW 45.70 35.49 17.90 9.88

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From 2000 to 2005, Conservatives and Liberals had argued that EEG’s costs needed to be reduced and the nuclear phase-out reversed. Beginning in 2009, the Conservative-Liberal coalition combined these goals and proposed to slow renewables deployment on the grounds that Energiewende was unaffordable and nuclear power was indispensable until about 2030. This was welcomed by the nuclear and coal electricity incumbents. In 2010, the government’s Energy Concept laid down specific long-term renewables targets for the first time (Bundesregierung 2010). Renewable power was to reach 35 percent in 2020 and then grow in linear fashion by 15 percentage points each decade so as to reach 80 percent of total energy by 2050. Overall power consumption was also to be reduced by 25 percent in 2050. These targets seemed ambitious, but the 35 percent goal was lower than the 38.6 percent target communicated by the same government to the EU just months earlier (Bundesrepublik Deutschland 2010), and until then growth of renewable power had been exponential rather than linear. In the end, the Fukushima disaster in March 2011 and Länder resistance in the Bundesrat soon reversed the “nuclear life extension” project. Also in 2010, new PV installations surged to about 7 GW of capacity. Conservative Party Environment Minister Norbert Röttgen sought to moderate PV growth, and reduce its cost, by linking solar tariff decreases (i.e., the “degression rate”) to the volume of annual installations as compared to a reference target (Morris and Pehnt 2015: 38–39). If the annual target of 2.5– 3.5 GW were exceeded, the degression rate for the annual tariff reductions would be increased in line with the deployment overshoot, thus curtailing the subsidies for solar’s growth. A few months after the government rammed its ten-year delay of the nuclear phase-out over a reluctant parliament and a protesting public, the Fukushima disaster occurred and led to a major policy reversal. As after Chernobyl, public opinion virulently became antinuclear. Chancellor Angela Merkel reinstated the nuclear phase-out against the preferences of some important members of her coalition. Eight old reactors were shut down immediately, and an ethics commission was set up to consider the future of nuclear power. Merkel more or less adopted the Social Democratic–Green government’s 2000 phase-out policy in effect and committed to the acceleration of Energiewende. However, the new restrictions on solar remained in place, and the new nuclear phase-out was presented as requiring new coal plants. The big amendment to the EEG in 2011 stipulated full nuclear phase-out by 2022 and an ambitious reduction in greenhouse gas emissions (80–95 percent reduction by 2050) but did not

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increase the renewable power target values set in the 2010 Energy Concept for 2020, 2030, 2040, and 2050. Within the governing majority there was an unresolved tension between the Conservatives’ business wing and the Liberals on one hand, and the Conservatives’ ecological wing and Conservative Länder governments on the other. The former accepted the full nuclear phase-out in the aftermath of Fukushima, but rejected accelerating renewables deployment. By contrast, most Länder governments responded to Fukushima with plans to step up deploying renewable power. Together these plans had a target of 45 percent or more of renewable power by 2020, much higher than in the 2010 Energy Concept, but they were hamstrung in implementation. For solar PV, under EEG 2011, the flexible cap for PV installed in 2010 saw the installation of 7.4 GW in 2010, followed by about 4.5 GW in the first eleven months of 2011. When news came that PV installations had widely exceeded the target of the Energy Concept, Röttgen’s flexible cap approach to bring down PV support seemed to have failed. Merkel ordered Röttgen to come to terms with his chief adversary, Liberal Economic Affairs Minister Philipp Rösler, who wanted to cut annual PV installations by about 90 percent. The resulting compromise proposal would have lowered the flexible cap from 2.5–3.5 GW for 2012 and 2013 to 0.9–1.9 GW in 2017 and cut tariffs dramatically. Actual installations were about 7.4 GW in 2010, 2011, and 2012. The compromise was supposed to force PV to become fully competitive within a few years (Deutscher Bundestag 2012a, 2012b). Nonetheless, Röttgen was dismissed, and the Social Democrats attacked the “chaotic cuts,” which made PV unprofitable while ignoring market integration needs (e.g., solar fluctuation). Social Democrats, Greens, and the new (since 2007) Leftist Party (LINKE) criticized this curtailment of PV just when it had become significantly cheaper. They also criticized the government’s passive stance in the face of Chinese PV dumping and export subsidies, which were leading to the demise of the German PV industry. LINKE MPs added that the collapse of PV producers would lead to a second wave of deindustrialization in East Germany. Most PV cell and module producers were located in the east, and they were the first new big industry and source of employment since 1990 (Deutscher Bundestag 2011). The government ignored the opposition in the lower house but had to compromise with the Conservative Länder delegations in the Bundesrat. Thus, the annual flexible cap for PV of 2.5–3.5 GW was reinstated; the dramatic cut in PV feed-in tariffs was reduced; EEG support for PV was guaranteed until a total capacity of 52 GW was reached; and a €100 million fund for renewables research and development and distributed energy storage was set up. The government also promised to bring the issue of unfair competition from China before the World Trade Organization.

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Previously it had simply dismissed these complaints coming from the solar industry. But this assistance came too late for many firms. Conflicts in the governing coalition intensified in 2012. The Liberals accused the Conservatives of betraying needed reforms and attacked EEG’s basic principles, such as priority dispatch, unlimited take-off obligations, and twenty-year-fixed tariffs. Through 2014, the discourse about EEG was increasingly dominated by the theme of excessive costs supposedly threatening the German economy. Günther Oettinger, EU Energy Commissioner and a former German politician favoring conventional and nuclear power, asked the German government in 2012 to stop electricity price increases by capping the EEG surcharge (Die Welt 2012; Photon 2012). His proposal would have stopped renewables deployment in its tracks. When a 50 percent surcharge increase took effect in January 2013, Economic Affairs Minister Rösler insisted on an immediate moratorium on all renewables deployment. Conservative Environment Minister Peter Altmaier was more moderate but could achieve no consensus with the Liberals that would also have satisfied the heads of the Länder in the Bundesrat. The surcharge debate led to a highly chaotic discussion on EEG reform, and myths dominated the debate. The rising surcharge was blamed mostly on PV. It is true that past commitments to pay PV tariffs greatly increased the extra cost of renewable electricity as redefined in 2010 (i.e., the difference between spot prices and feed-in tariff payments to renewables generators), but many politicians ignored that PV tariffs had decreased steeply after 2011 (see Table 8.3). Furthermore, the growing share of wind and solar power with near-zero operating costs had begun to displace the more expensive forms of fossil fuel generation under the merit order of the power exchange. Falling electricity demand, excess generation capacity and the growth of renewable power led to a reduction of wholesale electricity prices on the exchange (see Figure 8.3). This benefited industry but increased the difference between spot prices and feed-in tariffs, and thus the “extra cost” of renewables. If passed on to consumers, the lower electricity prices should have benefited them by the same amount. But only big industrial customers buying their power directly on the exchange benefited from lower electricity prices (BMU 2013; Tveten et al. 2013; BEE 2012). Households and small- and medium-sized enterprises did not see these gains. It was ironic at best to find the chief subsidizers of the spread of renewables (household electricity consumers) now deprived of the benefits of falling electricity prices on the exchange. Adding insult to injury, since Paralysis in Renewable Power Policy (2012–2013)

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2012 surcharge exemptions accorded to large energy-intensive firms facing international competition grew at consumers’ expense. Rösler multiplied these exemptions fourfold, to reach some €4 billion annually. To make up for the shortfall, the surcharge on households and small and medium-sized enterprises was increased substantially. Populist simplifications of the “heavy burden” on the German people resulting from the extra costs of EEG usually passed over these technical details. Also, external costs of conventional fossil fuel generation—particularly for carbon emissions—were ignored entirely. If these costs, as taken from official government figures, were added to the generation costs, coal power could no longer compete with renewables (Lauber and Jacobsson 2015; Alberici et al. 2014; Kuechler and Meyer 2012). In yet another irony, surcharge-exempt German industry associations who complained that EEG caused high electricity costs were in fact the beneficiaries of the law. Rather than a threat to German industrial competitiveness, EEG has been a boon to many large industrial firms who benefit from lower prices on the exchange and from surcharge exemptions viewed by the European Commission as state aid to German industry. Simplistic narratives on the theme of high EEG costs bore fruit anyway, and during the 2013 national election many Social Democratic leaders accepted the deindustrialization critique of feed-in tariffs, the energy insecurity resulting from supposed disruption of the grid and the “cost tsunami” argument regarding the need for new power lines, the three central myths in the debate (Kemfert 2013). These charged narratives enjoyed the support of the electricity incumbents as they reshaped public focus on the short-term costs and affordability of renewable power. These manufactured criticisms studiously ignored: falling wholesale power prices; industry benefits from lower electricity costs; reduced climate change costs; reduced dependence on imports; and greater supply security, particularly with respect to Russian natural gas. EU Commissioners Oettinger (Energy) and Joaquín Almunia (Competition) supported the electricity incumbents and national governments who turned to the defense of nuclear, coal, and gas against encroachment from renewables (e.g., Enel et al. 2013; Guardian 2015). In 2013, the Commission started yet another attack on feed-in tariffs, this time via state aid guidelines. Surprisingly, despite anti-renewables politicking at the national and EU levels, popular support for Energiewende remained strong in Germany. Surveys over many years show strong public support for the continued shift to renewable energy, despite some increasing cost concerns (e.g., EMNID 2013). All surveys up to the time of this writing (2016) show strong support for a decentralized transition to renewable energy.

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The electricity incumbents’ allegation that their difficulties result from EEG and the growth of renewable power ignore the history of their own corporate mismanagement (Bontrup and Marquardt 2015). Their desire to constrain renewable power reflects their growing rivalry with independent renewable electricity generators who were empowered by EEG. Historically, the German electricity incumbents invested little in renewables, and usually only abroad as in the United Kingdom or the United States, where profits were bigger and the installations did not threaten their local or regional market share in conventional fossil fuel generation (Lauber 2012, 2011). After 2010, their efforts to control renewables intensified. They sought to curtail renewables deployment by new entrants or to secure the lion’s share of the business for themselves (e.g., via a quota system). Even though they blamed their difficulties on the inordinate growth of renewables and on nuclear phase-out, other factors played a bigger role in their decline. Since 2014, they have made efforts to catch up, but they are handicapped by the problems accumulated over the past decade. The electricity incumbents did not take renewables very seriously until recently. They underestimated their potential and overestimated their own clout in securing favorable regulation. They were too steeped in their own management cultures, business paradigms, and post-liberalization mergers and acquisitions to realize the challenge from renewables. The electricity incumbents did well when operating under generous government subsidies and little competition. Liberalization in 1998 brought increased competition and the phase-out of subsidies but also permitted expansion via acquisitions. The affluent electricity incumbents embarked on an international shopping spree. E.on and RWE at one point divided the Eastern European market between the two of them (Becker 2011). Soon after the start of liberalization, Steve Thomas predicted that E.on and RWE were on the verge of becoming globally leading electricity oligopolists (Thomas 2003). Today, both firms struggle for survival. How did this come about? The mergers and acquisitions created problems. With the decline in electricity demand and intensified competition after 2008, many of these firms became unprofitable. Foreign takeovers turned out to be even more disastrous and brought, by 2010, over €10 billion in losses for both E.on and RWE (Kungl 2015). More losses and market withdrawals followed, as in Italy and Spain (IWR 2014). The 2005 ETS introduced new costs as carbon prices were expected to rise to €20–30/MWh. The electricity incumbents reacted by building a wave of natural gas plants with higher operating costs but lower carbon emissions costs than coal (natural gas plants emit

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about half as much carbon per kWh as do coal plants). But prices for emission allowances soon dropped precipitously while gas prices increased, upsetting these calculations. In turn, the electricity incumbents greatly benefited in the short run from the ETS and Germany’s 2005 National Allocation Plan for carbon permits. It granted free emissions allowances for the estimated lifetime emissions of new coal plants and allowed the electricity incumbents to escape taxation on profits from any resale of these emissions allowances, which they had received free of charge. These extra windfall billions of euros were then invested in a wave of new coal plants starting in 2008, while natural gas–based electrical generation fell by 32 percent during 2010–2014 (see Figure 8.1; AGEB 2015; Pahle, Fan, and Schill 2011; Pahle 2010). The result of these two investment shifts led to overcapacity within a context of shrinking demand and the deployment of renewables which by themselves overcompensated the closure of nuclear power plants, even the sudden retirement of eight nuclear plants after Fukushima. As a result, since 2012 many gas plants have been mothballed, including the most efficient natural gas plants in the world, while capacity factors fell for hard coal plants. Wholesale electricity prices for conventional fossil fuel and nuclear plants have declined since 2010 and were still doing so in 2015. Electricity incumbent revenues also fell with the retirement of nuclear reactors in 2011, and they will shrink further as nuclear phase-out progresses. By 2014, nuclear generation had already fallen by more than 40 percent from its peak level in 2001 (see Table 8.1). The growth of renewables has simply compounded these trends. The PV generation curve coincides with the daily peak of the electricity demand curve and now covers much of peak load. In the past this had been the most lucrative part of conventional fossil fuel generation for the incumbent utilities. Demand peaks are now often price troughs. With negligible operating costs, PV and wind displace substantial parts of declining fossil fuel generation under the merit order (Lauber and Jacobsson 2016). After 2010, the electricity incumbents responded with cost-cutting and big divestments. In 2012, they admitted problems in their corporate strategies just as the new coal and lignite plants started to go online. Since 2008, wholesale prices have dropped, intensifying the sector’s difficulties. Future payments for nuclear dismantling and storage will seriously drain corporate coffers (€30 billion at least), raising even greater doubts about electricity incumbents’ ability to foot these bills. With low stock values, little cash on hand, high debt, and credit ratings under stress, German electricity incumbents are hard-pressed to increase investments in renewables. In recent years they actually sold many investments to raise cash (Financial Times 2014; Downing 2013; Economist 2013c). One of the few bright spots is profitable offshore wind, where they dominate. Dismantling

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nuclear power plants and final waste storage will become a burden soon. Gas-based generation seems unprofitable so far. Coal power faces an inevitable phase-out, even if the government does not want to admit this yet. There is no support for future coal-based carbon capture and storage. This option comes too late and is too expensive with few storage sites and no acceptance by the public. Under these circumstances, electricity incumbents’ plea for government help is understandable. The Conservative-Liberal government accommodated demand for slowing renewables’ deployment willingly. It was more surprising, just before the 2013 elections, to see the Social Democratic Party’s top candidate, Sigmar Gabriel, declare that EEG had served its purpose. Gabriel joined the alarmist chorus and argued that without EEG’s dramatic reorientation, Germany was “facing the biggest deindustrialization program in its history” (Wirtschaftswoche 2013). Curtailing Energiewende: The EU and the 2013 Conservative–Social Democratic Coalition Government

Prior to the 2013 election campaign, opposition Social Democratic (SPD) leaders and MPs criticized the Conservative-Liberal government for abandoning Energiewende and currying favor with the electricity incumbents. With the 2013 elections, many of them fell for the myth that electricity incumbents’ distress was due to excessive growth of expensive renewables, which threatened the stability and security of the grid as well as German economic competitiveness, employment, and social welfare. The SPD always had its own strong coal faction and supported new coal plants until recently. Internal SPD lobbying came via the coal miners’ union (IG BCE), a potent force within the SPD structure despite coal sector employment having declined by 90 percent since 1950. Electricity incumbent RWE has close ties to many Social Democratic towns in North Rhine-Westphalia, which rely on the company’s profits for their budgets. Within a short time in 2013, the coal faction gained the upper hand in the SPD, just as the Conservatives’ business wing became dominant on energy issues in its own party. Also, the SPD lost the 2013 election, with only 25.7 percent of the vote compared to the Conservatives’ 41.5 percent, and they were in a poor negotiating position. Before the 2013 election, the SPD had argued for a 75 percent share for renewable electricity by 2030. After the election, Hannelore Kraft, governor of coal state North Rhine-Westphalia and an outspoken advocate of new coal plants, became chief SPD negotiator for energy issues in the coalition talks. The 75 percent target soon shrank to 50 percent. At the same time, increased pressure, or support as the new German governing coalition now saw it, came from the European Commission’s

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most recent effort to ban feed-in tariffs through new state aid guidelines (European Commission 2014). The Commission’s unambitious goal of 27 percent renewable energy by 2030, after 20 percent in 2020, was put forward after heavy lobbying by Europe’s major energy incumbents (Guardian 2015; Enel et al. 2013). The new state aid guidelines required tendering as the chief instrument of support for renewable power. The European Commission held leverage over Germany with its veiled threat to make German industry pay for past surcharge exemptions, which it viewed as state aid. Germany insisted that EU final rules reduce surcharge exemptions for German industry only marginally and accepted the principled ban on feed-in tariffs, affecting all member states. Germany had been the main bulwark against European Commission attacks on feed-in tariffs in the past, and the 2014 EU rules on state aid now provide additional legitimacy to their replacement by tendering (except for small generation units) in the most recent EEG reform in 2016, to take effect in 2017. The coalition agreement and the subsequent EEG 2014 were quite clear on reining in renewable power, and this is even clearer in EEG 2016. Renewables’ prior de facto exponential growth was to be slowed to a mere linear development path, providing predictable phase-out tracks for fossil fuel plants. Tendering means that deployment of all technologies (wind, solar, etc.) will now be firmly capped, as in a quota system. Caps were further reduced from the targets of the 2010 Energy Concept. Thus, for PV, 2.4 to 2.6 GW a year was allowed, instead of the 2.5 to 3.5 GW set in 2010. Most important, the end of feed-in tariffs may mean the end of a decentralized Energiewende by citizen-investors and other small actors who made up the driving force behind it and for whom participation in tenders is a risky affair. These measures are expected to help big electricity incumbents and some municipal utilities regain ground in the electricity market. In EEG 2014, a government priority was grid expansion for centralized, large-scale generation, allowing long-distance transfer of regional wind and solar power surpluses. This was an unlikely answer to fluctuation, and there were no efforts to incentivize a better geographic distribution of renewable generation (Solarförderverein 2015). The potential of electrical storage to reduce the need for long-distance power flows was deemphasized. The new story on storage was that it would not be needed for another decade or two. Fluctuation could be handled by expanding power distribution and giving greater flexibility to conventional fossil fuel power plants. The new authority to shut down large renewable power plants without compensation at times of negative wholesale prices also improved the position of the fossilladen incumbents. Today the biggest obstacle to further growth of renewables is not cost but the existing overcapacity of fossil generation. So far the government

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rejects the idea of a coal phase-out before the end of nuclear power. Consulting firms such as PIRA in New York see significant excess capacity in Germany’s coal plants. Yet when the government in 2014–2015 announced regulatory plans to phase out a few gigawatts of lignite generation, this led to intense protests by most electricity incumbents, other coal sector firms, and their labor unions, who are determined to fight a rearguard battle by invoking deindustrialization. Even though the coal labor force only amounts to about 0.15 percent of German employment, they were successful on this occasion. They managed to secure the support of Economic Affairs and Energy Minister Gabriel, who promised that this was not the beginning of a coal phase-out (Photon 2015). The government is not eager to face this issue head-on. It also has to keep in mind the issue of financing nuclear clean-up (after the phase-out), for which the incumbents may have to pay some €30 to 40 billion. Still, a coal phase-out must start soon if German climate policy is to reach its targets and particularly if the 2015 Paris Agreement will come to fruition. This position is supported by Environment Minister Barbara Hendricks, with some support also in parliament (Hendricks 2015; Koch 2015). The current government approach is to pay coal plant operators for shutting down their plants and take time for this so as not to endanger security of supply (Morris 2014). This position is also supported by the Conservative business wing. But two thirds of the public are in favor of early coal phase-out by 2040 at the latest (Statista.de 2015c; YouGov 2015). The prospect of a complete coal phase-out unnerved coal’s many defenders, and they were successful in reviving old myths and defensive reactions in support of coal. Chancellor Merkel has delayed any decision on a coal phase-out until after the next election in 2017, and she did not dare to use special fossil fuel levy authority on inefficient coal plants. Yet these short-term measures remain out of touch with German public and expert opinion. Thus, coal power was in effect subsidized again for failing to reduce the overcapacity its own managers had created. More distressingly, in recent years, the use of hard coal has remained roughly constant, while that of lignite has increased. In 2015, German lignite and hard coal produced 273 TWh of electrical generation for 41.9 percent of Germany’s total, only down slightly from 274.4 TWh and 43.7 percent of the total in 2014 (AGEB 2016). More ominously, REN21 figures showed that while overall European renewable energy investments were down 21 percent in 2015, Germany’s $8.5 billion in renewables investment in 2015 was down 46 percent from 2014 (McDonald 2016; REN21 2016: 25, 102). However, the German Ministry of Economic Affairs showed only a 20 percent decline (AGEE 2017). The ongoing use of coal and the current decline in renewables investment since 2010 pose serious problems for

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Germany’s continued progress on renewable energy transition and climate policies. Energiewende’s Significance

Germany’s energy and geopolitical positions in the world have always been influenced by considerations of domestic and foreign policy, as the nation has accommodated itself to or challenged its external resource dependencies. The country is now facing difficult choices. Increasing the reliance on natural gas imports from Russia will enhance mutual codependence and weaken its position in confrontations with Russia. More ambition on Energiewende will increase energy autonomy, cool relations with Russia, and probably lead to greater involvement with Chinese solar firms. It would also strengthen Germany’s credibility and position as a leader in the struggle against global climate change. Despite many decades of effort, its share of domestically generated renewable power in gross electricity consumption ranked Germany only twelfth among the European Union’s twenty-eight member states, in 2013, while Austria and Sweden had renewables shares several times as high (Eurostat 2016). Austria and Sweden rely mostly on legacy hydropower, which can be problematic in terms of intermittency, including climate change’s long-run threat to the generating source of available mountain snowpack. Even with regard to the share of wind power in domestic generation, Germany is sixth in the EU, after Denmark, Spain, Sweden, Portugal, and Ireland. But in absolute terms, Germany certainly does have the biggest installed capacities in Europe for onshore wind, solar PV, and biomass and a high rate of growth of those installations in the past. This was one of the factors that allowed it to approach Energiewende from the angle of national industrial policy. With regard to the speed of transformation, Germany occupies a special place. In 1990, it had one of the lowest renewables shares in Europe, on a par with the United Kingdom. Between 2002 and 2012, it increased its renewable power generation by approximately 200 percent, while the EU average was only 67 percent (Rosenkranz 2015; Table 8.1). Germany also stands out because its civil society not only advocated renewable energy consistently but also drove it forward by investing in a significant percentage of renewables generation itself (Moss, Becker, and Naumann 2015). This grassroots commitment has carried the day in domestic politics over about three decades, despite hostile domestic political factions, governing coalition changes, and EU intransigence. Germany is also unique in its long-term support for and practice of feed-in tariffs. Combining guaranteed

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grid access for renewables generation with fairly predictable revenues for twenty years, these feed-in tariffs have empowered ordinary citizens to invest in distributed renewable power generation, drive deployment across the country, and challenge powerful electricity incumbents and the European Commission (Morris and Pehnt 2015: 35–38). Up to now, feed-in tariffs have motivated nonutilities to finance the biggest part by far of all distributed renewable power generation investment. All this allowed Germany to play a key role in the global industrialization of renewable power equipment through innovation, mass production, deployment, and lowered prices. German firms still hold dominant global market shares in certain components aspects within the PV industry (production equipment) and across much of the wind industry (Pegels and Lütkenhorst 2014). Partly due to demand from Germany, Chinese firms have come to dominate the production, domestic deployment, and trade of much of the solar industry (Spiegel Online 2011). For example, Chinese firms produce over 70 percent of the world’s PV cells and modules (Bloomberg New Energy Finance 2016: 53; Stearns 2016; IEA 2015b: 346– 347). For its part and because the United States was an early leader in solar and other renewables under President Jimmy Carter, the United States retains certain advantages in aspects of green power innovation and patents control (Deutch and Steinfeld 2013; Bierenbaum et al. 2012). But highly variable US tax credits, renewable portfolio standard caps, and potentially volatile renewable portfolio standard certificate prices have long discouraged turbine or cell manufacturers, domestic and foreign, to set up shop there and also deterred bankers seeking steady returns on invested capital. Similarly, the UK Renewables Obligation was too unambitious, its certificate system too insecure, and British electricity incumbents too ambivalent about renewable power to encourage the rise of such industries domestically. As a result, both the United Kingdom and the United States imported their renewable generating equipment for many years. In the 1990s and early 2000s, only Denmark and Spain (and at times Japan) played a role similar to Germany’s in industrializing these new technologies. Germany’s greatest comparative strength today is in producing offshore wind turbines and developing the machinery and factories for PV production, most of which now occurs in China. These ties bind Germany and China in a transnational division of labor in renewables research, development, and production that is more complicated and may be more broadly beneficial than is commonly acknowledged (Quitzow 2015). Germany’s machinery and manufacturing expertise helped reduce the cost of PV for the rest of the world, and through Siemens, Germany is also a leader in producing offshore wind turbines. In other areas, such as solar cells and modules, German producers have succumbed to a combination of hostile domestic fac-

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tions and elites and unbridled international production rivalry by the lowcost Chinese juggernaut. For example, in 2013, Economic Affairs Minister Rösler opposed European Commission anti-dumping measures against China on imported solar panels. He called them a “grave mistake” (EurActiv 2013). This served his party’s interest in protecting electricity incumbents and domestic automakers such as BMW, who sold more in China than in Germany, and also affirmed his neoliberal free market ideology, all of which effectively contributed to pass the solar panel production baton to China. As a result, Germany lost most of its leading firms in the PV cell and module sector to competitors from other countries. Partly as a result of this faltering policy commitment at the top of the German state, Germany added only 1.5 GW of solar capacity in 2015, even though its politically reduced target had been 2.5 GW (Quaschning 2016). Before its recent shift to tendering, Germany played a key role in defending feed-in tariffs, for some time the most effective and efficient renewable support system, against European Commission short-term, neoliberal approaches to climate and energy policy (Lauber and Jacobsson 2015; Toke and Lauber 2007; Lauber and Schenner 2011). Paradoxically, the EU, facing rising energy dependence, stressed ineffective support systems for renewables. The German results stand in contrast to the United States, for example, which languishes in single-digit renewables shares in electricity generation from new renewables, that is, once legacy and depleting hydroelectric is stripped out. Taking a broader geopolitical view that includes conventional fossil fuels, Germany is about to step up its natural gas relationship with Russia, despite political strife over recent Russian aggression in its near abroad. In 2015, 60 percent of Germany’s net natural gas imports—amounting to 40 percent of total German use—came from Russia (Bundesverband der Energie und Wasserwirtschaft 2016; British Petroleum 2016: 28–29). The contentious politics associated with Russian gas in Germany’s domestic and foreign policies remain as stark now as when the Red-Green coalition exodus from power saw Joschka Fischer and Gerhard Schröder represent rival natural gas pipeline enterprises in league with Russia (Neukirch 2010). Schröder’s felicity with the Russians and ongoing work for Gazprom on Nord Stream 2 has attracted the ire of EU officials and Eastern European states bypassed by the new pipeline. Russia is increasingly able to supply gas to Germany directly without traversing any third country and withhold it from Eastern Europeans, whether in Ukraine or Poland, for example (Rettman 2016). Chancellor Merkel and others in her cabinet strongly support the deals, remaining faithful to the spirit of the first natural gas pipeline deals with the Soviet Union in the late 1960s. Stressing the difference in perception, Gabriel stated that Nord Stream 2 was “a business issue for Germany and a political issue for Poland” (EurActiv 2016).

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Germany’s ability to become more autonomous in energy may be constrained by the geopolitics of gas, but it is even more constrained by its inability to make e-mobility a larger reality in its transport sector. For example, in early 2016, 98.4 percent of all cars on Germany’s roads were still exclusively powered by refined oil products, and only 0.7 percent of new car registrations in 2015 were for fully electric and hybrid electric vehicles (Heymann 2016: 8). Greening Germany’s electrical grid only slightly changes the country’s position relative to the other major powers, and the greenhouse gas emissions from the transportation sector in Germany have not been reduced at all since 1990. Recognizing the minuscule gains from more green-powered electrified transport, in May 2016, Merkel’s government began a new €4,000 tax credit for all-electric vehicle purchases under a price cap of €60,000. While aiming to exclude Tesla vehicles with this price cap, the German government and German automobile firms are beginning to move more quickly into this e-mobility space, and they may progress as fast as the electrical generation sector once did. Conclusion

Over the past several decades and until recently, Germany had become a missionary for renewable energy in the international community by organizing conferences, financing big renewables projects all over the world through its Reconstruction Bank, drumming up support for the International Renewable Energy Agency, and providing technical assistance to many countries, including China, which usurped its position in solar panel production. Germany’s renewables development and position within Europe drove the EU forward on renewable energy. The German government used to play a key role in defending feed-in tariffs against EU Commission attacks in the first (2001) and second (2009) EU renewables energy directives (Lauber and Schenner 2011). Some of these things have changed greatly since 2012, and an end to this change is not in sight. But if the spirit of the 2015 Paris Agreement on climate change policy should prevail, Germany may well return to a more prominent role as advocate of a swift Energiewende. As renewables are taking off throughout the world, the EU, once an early leader, is now a laggard in the effort to mitigate climate change via deploying renewable energy. Notwithstanding EU complacency, German civil society may yet come up with other unusual initiatives. For example, in 2014, the citizens of Hamburg voted in a referendum that the city take over the electricity grid from incumbent Vattenfall and make the electricity supply more sustainable and renewable. In 2015, Elektrizitätswerke Schönau, a former village utility that turned all-renewable after Chernobyl and managed to acquire about 160,000 consumers, organized a cooperative

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to acquire insolvent wind power firm Prokon, holding 500 MW of installed capacity, even though electricity incumbent EnBW offered better financial conditions to the former owners (Gipe 2015). The commitment and contagious enthusiasm behind these and similar initiatives should not be underestimated. They carry greater conviction and promise a more sustainable future than the stolid defense of energy policies that have reached the end of their legitimacy.

9 Energy Transitions in Japan Andrew DeWit

The 2010s found Japan emerging as an energy-transition innovator. The world’s fourth-largest economy, Japan is an outlier that has the developed countries’ lowest levels of foreign investment, immigration, and other indicators of internationalization. Precisely the opposite holds, however, when it comes to energy, the “master resource” (Zencey 2013). Japan exhibits an unparalled dependence on imported fuels and geographical distance from their sources of supply. In 2014, Japan was the world’s largest importer of liquefied natural gas, the second largest importer of coal, and the third-largest importer of oil (US EIA 2015). Japan is also perhaps most distinctive in its record of costly reliance on particular sources of energy, especially oil and nuclear power. These energy extremes afford powerful, latent incentives for revolutionary change. The first few years after Japan’s March 11, 2011, nuclear disaster at Fukushima led to a protracted struggle over nuclear versus renewable energy and a new extreme. In 2015, fossil fuels accounted for 93.7 percent of Japan’s total primary energy supply, versus 80.9 percent in 2010 (IEA 2016f: 18). This very high dependence on imported and carbon-intensive energy dramatically exposes Japan to depletion risks, price volatility, and geopolitical shocks while undermining its ability to play a leadership role in fighting climate change. At the same time, Japan became one of the world’s largest solar markets. It also accelerated its diffusion of information and communication technology (ICT)–enabled distributed generation, district heating, microgrids, and other network infrastructures that are key to the ongoing rollout of “smart cities” (URENIO 2014; Townsend 2013), the “resource revolution” (Heck and Rogers 2014), and sustainability (Koomey, Matthews, and Williams 2013). Japan had a potent combination of objective incentives to pursue energy autonomy and robust policies to achieve it. Properly managed, Japan’s transformation could outpace paradigmatic energy transitions occuring elsewhere. 183

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Prewar Japan’s Rise and Its Energy Dependence

Meiji Japan’s (1868–1912) elites met the perceived threat of colonialization with rapid industrial and military modernization. Within a few decades, Japan transformed itself from an isolated feudal economy to a rising, resource-intensive global power. But geography and geology had dealt the nation a poor hand. The country was neither a resource-rich continental power such as the United States, nor—like Germany then or China now—the core of a continental region. Nor was it an established colonial island power such as the United Kingdom, whose rich endowment of coal reserves and far-flung markets for manufactures fueled the first industrial revolution (Miller 2005: 32). Japan was an archipelago, distant and detached from its region, with comparatively poor endowments of conventional energy resources. Even so, Japan’s domestic energy sources sufficed during the initial decades of its catch-up modernization and, indeed, provided a surplus for exports. In 1880, wood, charcoal, and other traditional and domestically sourced biomass supplied just under 85 percent of Japan’s primary energy demand. Coal followed at 13.8 percent, with oil accounting for only 1.3 percent. Coal overtook biomass in 1901, and quickly became the pillar of Japan’s energy supply, its share in primary energy demand reaching 77 percent in 1917 (Smil 2010: 93). Prior to the 1920s, Japan’s coal production was sufficient to fuel its own needs as well as leave roughly 40 percent for export to Southeast Asia, providing an important source of foreign exchange (Iwama 2011). Coal still supplied 66 percent of Japan’s primary energy in 1940, just prior to the Pacific War of 1941–1945 (Odano 2007). Coal helped motivate Japan’s fateful imperial adventures, but oil delivered a catastrophic lesson in extreme energy dependence. Japan’s energy use increased by 261 percent between 1920 and 1940, with oil’s role growing from 2.2 percent to just over 7 percent (EDMC 2016: 316). Oil’s small share belied its strategic significance, especially in such crucial military applications as fuel for warships, aircraft, and tanks. Moreover, Japan’s military power was based on oil that the US government and business interests worked to ensure largely came from US sources rather than Dutch and British possessions in what is now Indonesia. Japan’s total demand for oil and oil products more than doubled from about 2.5 million kiloliters (15.7 million barrels) in 1931 to 5.7 million kiloliters at the 1937 outbreak of the second Sino-Japanese War (1937–1945). US exports supplied 74 percent of Japan’s 4.8 million kiloliter demand for imported oil in 1937, a figure that increased to 90 percent in 1939 (Iwama 2010). Japan’s severe rationing of civilian use cut total consumption in 1941 to 4.1 million kiloliters, with military demand being half of this total (Iwama 2011). Japan was thus able to

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reduce its reliance on imports from the US to about 60 percent in 1940 (Maechling 2000). But Japan was unable to make further progress on either reducing oil consumption or diversifying sources of supply (Miwa 2004). On July 25, 1941, the United States implemented a financial freeze on Japanese assets in the United States, a move that soon became an effective embargo on oil exports to Japan (Moran 2016; Miller 2007). The December 7, 1941, attack on Pearl Harbor followed as the Japanese “sought to preserve some hope of future economic and military autonomy in the face of their economic dependence on the United States, which was purposefully created by the United States and based primarily on oil” (Lehmann 2009: 143–144). High Growth and Japan’s Postwar Energy Policy

Atom-bombed into surrender and occupied by a power at first bent on deindustrializing it, Japan’s postwar years began with severe privation. More than a decade of warfare, beginning with the invasion of China, had cost roughly one quarter of national wealth. Even working capital and infrastructure untouched by the US strategic bombing was badly depleted and obsolete after long years of underinvestment. Conventional economic activity itself was moribund. Japan’s exports had plunged to roughly one ninth, imports about one sixth, and the production of industrial inputs down to a mere 8 percent of prewar levels. Per capita energy supply (measured in 1,000 kilocalories) had plummeted from a peak of 8,874 in 1940, reaching a low of 3,744 in 1946. Desperate, Japanese policymakers determined to revive the economy through an emphasis on domestic coal. At war’s end, production of this core commodity had dropped to 36 percent of its prewar peak (Hein 1990: 64). Between 1947 and 1948, a priority production system sought to ramp up coal production as an input for the steel industry. Priority production then used the expansion in steel output as inputs for the production of more coal, in a reciprocal cycle of capacity expansion. The system was enlarged to include more industries—such as electricity generation—in its ambit (Nakayama 2013). The entire country was galvanized by the slogan “Dig 30 million tons of coal.” Daily output levels were posted in large cities, and the minister of Commerce personally stripped down to a fundoshi loincloth and went into Sendai’s Joban Mine in Fukushima Prefecture to cheer on the workers, who were further encouraged in evening radio broadcasts (Ohno 2006: 153–154). Japan’s high reliance on coal in its energy mix continued into the 1960s, with 65 percent of expanded supply coming from the United States

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and 14 percent from Australia (Yanotsuneta 2006: 355). In 1952, energy consumption grew by 11.1 percent, with coal providing 49.7 percent of primary energy. Oil’s contribution of 11 percent was just ahead of the 10.8 percent afforded by traditional biomass and well behind the 28 percent of energy derived from hydropower (EDMC 2016: 318). Japan’s Oil Boom

It was oil that fueled postwar Japan’s economic miracle, more spectacularly than any other country in the industrialized world. Between 1948 and 1972, US oil consumption tripled and in Western Europe it rose by fifteen times. During the same period, Japan’s consumption increased a staggering 137 times, from 32,000 barrels per day to 4.4 million (Yergin 1991: 543–546). Table 9.1 shows that in 1948, oil provided 4.6 percent of Japan’s primary energy, far less than the 11.1 percent share of that era’s renewable energy from firewood. Yet by 1970 oil’s share had rapidly escalated to just under 70 percent. The swift pace of Japan’s transition from coal to oil is testament to oil’s utility. Cheap, abundant, and seemingly risk-free oil supplies for Japan were delivered largely from a Mideast region dominated by the United States, through an industry largely controlled by US firms, and over sea lanes patrolled by US warships. Japan’s energy self-suffiency—measured as the share of domestically sourced fuel in total primary energy—tumbled from 58.1 percent in 1960 to 15.3 percent in 1970 as massive volumes of imported oil displaced domestic coal (METI 2015: 110). The extreme in Japan’s oil dependence arrived in 1973. Table 9.1 shows that oil supplied fully 75.5 percent of Japan’s primary energy in this initial year of the first oil shock, when OPEC countries deployed “the oil Coal

Oil

Gas

Hydro

Nuclear

Renewable

Table 9.1 Changes in Japan’s Primary Energy Supply Share, 1948–2014 (%) 1948 1960 1970 1973 1980 1990 2000 2010 2013 2014

52.6 41.2 21.3 15.5 17.6 17.3 18.4 23.2 25.8 26.3

4.6 37.6 69.9 75.5 64.7 56.6 49.9 41.2 43.9 42.0

0.1 0.9 1.3 1.6 6.4 10.6 13.7 18.6 24.1 25.1

Source: Adapted from EDMC (2016: 38, 316).

31.7 15.7 6.0 4.4 5.4 4.4 3.6 3.5 3.5 3.6

0.0 0.0 0.4 0.6 4.9 9.8 12.9 11.8 0.4 0.0

11.1 4.6 1.1 1.0 1.1 1.4 1.4 1.7 2.3 3.0

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weapon” (Yergin 1991: 608–609). This acute reliance on oil thus matched coal’s 1917 peak in Japan’s energy mix. Japan was also importing the bulk of its oil from the Middle East, especially Iran, Saudi Arabia, and Kuwait. Being the most vulnerable among the big economies, Japan reacted with great alacrity to the supply and price shocks. Among other measures, Japan dramatically cut its dependence on oil in its electricity-generation power mix, increased efficiency, and sought to diversify its sources of supply. In 1973, fully 71.4 percent of power generation was oil-fired. Afterward, as in most other countries, oil’s role in Japan’s power mix was largely substituted for by coal, natural gas, and nuclear power. By 2011, Japan’s oil-fired power generation had fallen to 10.5 percent of the power mix, when it was deliberately restricted to a back-up role in meeting peak demand rather than as base-load capacity (WNA 2013). Table 9.1 shows that in just under two decades, between 1973 and 1990, oil’s dominance in Japan’s primary energy mix dropped from 75.5 percent to 56.6 percent. Over the same period, coal increased from 15.5 to 17.3 percent. Both natural gas and nuclear energy went from being negligible sources to contributing roughly one tenth of primary energy supply. Japan also made significant gains in energy efficiency, but the incentives soon flagged (DeWit 2013a). One prominent cause was plenty: the 1980s saw a flood of oil from non-OPEC sources, such as the North Sea, Prudhoe Bay (Alaska), and the former Soviet Union. Correspondingly, OPEC’s share of world production dropped from 52 percent in 1973 to 30 percent in 1985. The Saudi and US elite had also forged stronger bonds, which encouraged the Saudis to use their ample surplus production capacity to moderate oil prices and stabilize supply. The effects of post-1973 conservation and the shift to alternatives—such as natural gas—wherever possible also led to lower oil prices and enhanced security. Japan’s per barrel cost for oil declined from US$35.38 in 1981 to US$16.91 by 1989. The 1990s brought even cheaper oil, aside from a brief price spike in the lead-up to the First Gulf War. By 1998, Japan’s average per barrel cost was US$12.76 (EDMC 2016: 52). The Intense Commitment to Nuclear Power

Even as oil prices declined, the experience of supply and price shocks kept energy security very prominent in Japan’s energy policymaking. From the mid-1950s, policymaking circles had featured a growing nuclear village, a coterie of concentrated benefits that came to include monopoly utilities, power-unit makers (Hitachi, Toshiba, Mitsubishi), compliant regulators, collaborative scholars, cooperative media, and other players (Samuels 2013:

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118–122; Kingston 2012). This village made nuclear power central to Japan’s plans for displacing oil and enhancing domestic energy self-sufficiency. One measure of the nuclear village’s influence is the extent to which the Japanese state’s fiscal and regulatory tools were used to develop and deploy nuclear power following the first oil shock, as seen in Table 9.2. The table compares Japan’s nuclear fission research, design, and development (RD&D) investment with other International Energy Agency (IEA) member countries in the wake of the first oil shock and up to 2014. The IEA was formed in November 1974 as an oil consumer country response to the oil shocks. Japan quickly became one of its most avid members. From the start of the 1980s, Japan took over from the previous leaders of nuclear RD&D investment, the United States, the United Kingdom, and Germany. The table shows that by the mid-1980s Japan had surpassed them. A decade later, in 1995, Japan’s spending on nuclear fission RD&D represented 62 percent of all IEA spending, a figure that had only declined to 54 percent in 2010, just before 3-11 (the Fukushima accident). Japan’s RD&D spending on nuclear in fact rose to 61 percent in 2014, in the wake of 3-11, but the focus had turned to plant safety, decomissioning, nuclear waste management, and related research. The Nuclear-Centered Energy Environmental Policy Regime

Prior to 3-11, Japan’s massive RD&D and other investment in nuclear energy saw it become the central pillar of the country’s energy environmental policy regime. In the latter decades of the twentieth century, Japan had drafted and adopted a string of energy plans focused on raising the level of nuclear in the power mix (OECD 2003). But Japan’s first comprehensive energy environmental policy was enacted in June 2002 and emphasized the three principles of “security of supply,” “environmental compatability,” and

Table 9.2 Nuclear Fission RD&D Expenditures by IEA Countries, 1975–2014 (2014 US$ millions) 1975 1985 1995 2000 2005 2010 2014

UK

1,027 702 19 0 5 31 n/a

France

0 1,071 729 812 682 530 n/a

Japan

682 2,139 2,363 2,283 2,307 2,124 1,145

Source: IEA Energy Technology RD&D Statistics.

US

2,533 1,462 121 46 565 503 370

Germany 1,246 1,078 105 37 33 101 101

All IEA 6,416 8,695 3,803 3,468 4,221 3,936 1,864

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“free-market principles.” The policy was clearly designed to increase the fiscal and other resources devoted to nuclear energy, which had achieved a 39 percent share in Japan’s power generation by 2001. As part of this pronounced policy shift, the government “gained greater authority . . . in establishing the energy infrastructure for economic growth” and revised its fiscal tools to expand nuclear power and disincentivize fossil fuels (WNA 2013). Japan’s 2002 policy also created the legal authority to draft an Energy Basic Plan (kihon enerugii keikaku). This planning exercise was to be a comprehensive and long-range assessment of energy supply and demand, led by the Ministry of Economy, Trade and Industry (METI). The plan was also to be revisited and, if necessary, revised at least every three years. Its first version was adopted in October 2003 and emphasized the role of nuclear power as clean, secure, and reliable energy whose safety and public support required significant effort (METI 2003). As the 2000s progressed, rising conventional energy prices coupled with geopolitical turmoil led to increased energy insecurity. Adding to Japanese concerns were competition for energy resources from the rapidly growing and heavily populated Chinese, Indian, and other developing economies of the Asian region. In May 2005, Japan drafted a New National Strategy focused on energy security, compiling a Nuclear Energy National Plan in August 2006. The core aspect of the 2006 nuclear energy policy was its clear commitment to thirteen new nuclear reactors at existing and greenfield plants by 2030, while raising the capacity utilization ratio of existing nuclear reactors from 60 percent to 90 percent. These ratios had plummeted in the early 2000s due in part to a string of scandals concerning falsified damage reports and safety violations at nuclear facilities. Less than a year before the 3-11 Fukushima shock, Japan adopted the Energy Basic Plan in June 2010. The policy aimed at ramping down reliance on fossil fuels by getting 53 percent of the nation’s electricity from nuclear power by 2030, compared with 26 percent in 2010. Realizing that scenario was estimated to require nine additional nuclear reactors by 2020 and more than fourteen by 2030. The 2010 Energy Basic Plan and its predecessors underplayed the potential for sustainable forms of renewable energy, such as solar and wind, as well as energy efficiency. Even so, the 2010 plan did include some relatively ambitious targets for efficiency and renewables. Japan’s capacity in these fields was evident in the goal of making LED lights 100 percent of the lighting sales market by 2020 (and 100 percent of all lighting by 2030), increasing renewables (including hydro) to 21 percent of power by 2030, diffusing electric and other second-generation cars to 50 percent of new car sales by 2020 (and 70 percent by 2030), as well as making all new homes net zero energy by 2030 (METI 2010).

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The explicit targets for renewables and efficiency in the 2010 Energy Basic Plan showed that the nuclear village was not able to dominate all aspects of energy policy. Indeed, the framework of Japan’s power and energy governance was flexible enough to include a liberalization of power markets (in 1995) that encompassed the large-lot (over 500 kilowatts) sector. That limited liberalization satisfied the major industrial interests in encouraging lower power costs, while maintaining Japan’s unparalleled (among the developed countries) monopolization over power generation, transmission, and sales (Scalise 2009). The incumbent power monopolies clearly wanted renewable generation limited as much as possible as well as closely contained within a stable framework of power and energy institutions that maintained their role (DeWit, Iida, and Kaneko 2012). As of 2011, the monopolies owned about 80 percent of Japan’s installed generating capacity (US EIA 2015), dominating a power market worth roughly ¥16 trillion. The incumbents evidently preferred to maintain that centralized generation and the income streams it entailed. Their ability to shape policy is a major reason that Japan’s official target for diffusing renewable power via a 2002-implemented renewable portfolio standards incentive scheme was a minimalist 1.35 percent for 2010 and 1.63 percent for 2014. At the same time, such prominent firms as Toyota, Toshiba, and Hitachi also wanted to be leaders in smart grids, solar power, wind turbines, storage, and other emergent energy systems. Japanese assessments indicated these technologies could total a cumulative US$40 trillion in investment between 2010 and 2030 (Nikkei BP 2010). Energy policy thus confronted the additional challenge of balancing the security afforded by power monopolies while also fostering world-class innovation. The core vehicle for achieving this otherwise contradictory aim was smart city initiatives that allowed for green innovation in a context that encompassed the legacy players along with their business models and infrastructure (Samuels 2013: 145). The Fukushima Shock

On March 11, 2011, Japan’s energy policy and energy economy were dealt a severe blow by one of history’s largest and most expensive natural and nuclear disasters (Lochbaum, Lyman, and Stranahan 2013). The total damage from the earthquake and tsunami has been assessed at ¥16.9 trillion (Cabinet Office, Japan 2015: 9). The shock from the disasters continues to restructure Japan’s energy and environmental policy regime. The cost of the nuclear accident itself, including the meltdown of three reactors at TEPCO’s Fukushima Daiichi plant, remains uncertain. Much

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depends on the extent to which radionuclides are removed from affected areas, how much land is purchased, decisions on levels of compensation, and other factors. The Japan Center for Economic Research suggested that a comprehensive accounting of the costs is likely to be between ¥40 trillion to ¥50 trillion (Economist 2015). It soon became evident that TEPCO was incapable of covering even a portion of these clean-up, compensation, decomissioning, and other costs. The firm’s total market capitalization, on the eve of the disaster, was ¥3.2 trillion and its assets of ¥13.2 trillion netted out at ¥2.5 trillion after the subtraction of debts (Ramseyer 2011). TEPCO was soon rendered effectively bankrupt. It was nationalized in June 2012 via a ¥1 trillion injection of public capital, “the biggest state intervention into a private non-bank asset since America’s 2009 bail-out of General Motors” (Economist 2012). Some specialists question whether Japan’s other nuclear-dependent utilities are viable as well (Kaneko 2013). Back to the Nuclear Paradigm?

The December 16, 2012, national elections saw the Liberal Democratic Party (LDP) elected with a massive majority under Prime Minister Shinzō Abe. Abe’s rhetoric suggested that he would seek to return as much as possible to the status quo before the Fukushima shock. He aggressively promoted nuclear exports, declaring himself Japan’s “top salesman” for nuclear-centered infrastructure exports (Sekiguchi 2013). The Abe regime’s statements reflected the continuing influence of the nuclear village and the durability of the argument that nuclear power offers Japan the only credible alternative to fossil fuels. Indeed, even the previous center-left Democratic Party of Japan (DPJ) government (2009–2012) had generally cooperated with the nuclear village. The nuclear-centered 2010 Basic Energy Plan was, after all, decided during the DPJ’s tenure. Moreover, after 3-11, the bail-out of TEPCO and other measures had put the state in a powerful position vis-à-vis the utilities to press for much-needed reform of the entire power sector. But the DPJ opted not to use this authority as aggressively as it might have. The TEPCO bailout thus saw government officials, TEPCO, and its politico-bureaucratic allies engaged in protracted negotiations over salaries and other minutiae. The process was “bewildering” to outsiders and “underscored the depth and resilience of Tepco’s influence, and that of the ‘nuclear village’ of utility executives, bureaucrats and lawmakers that built Japan’s atomic power industry” (Soble 2012). Hence, the return of the center-right LDP, led by a prime minister and cabinet explicitly committed to nuclear restarts, suggested to some observers that the weight of sunk costs and other factors would drive Japan’s energy

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policy and the political economy back to the trajectory it was on prior to the Fukushima crisis (Kilisek 2014). Certainly, there are powerful political, geopolitical, pecuniary, and other incentives to adopt this course of action. As noted in the introduction to this chapter, Japan largely turned to fossil fuels to fill the gap in generation caused by the post-Fukushima shutdown of nuclear capacity. Japan’s share in the consumption of globally traded liquefied natural gas (LNG) rose from 33 percent in 2011 to 37 percent in 2012, a level that continued through most of 2014. That expansion of LNG imports represented a 24 percent increase over the amount imported in 2010, from 3.3 trillion cubic feet (tcf) to 4.2 tcf (US EIA 2015), and LNG’s share of Japan’s power mix rose from 29.3 percent in 2010 to 43.2 percent in 2013. Moreover, many mothballed oil-fired power systems were returned to service and run full blast. Oil’s role in the power mix went from 7.5 percent in 2010 to 18.3 percent in 2012, before dropping back to 14.9 percent in 2013 and 9 percent in 2014. Hence, as seen in Table 9.1, Japan’s dependence on oil as a share of overall energy supply in 2010 was 41.2 percent, but rose in the following two years to 44.4 percent in 2011 and 45.7 percent in 2012, before declining to 43.9 percent in 2013 and 42.0 percent in 2014. Japan’s reliance on coal increased as well, rising from 25 percent of the power mix in 2010 to 34 percent in 2015 (IEA 2016f: 17; Ishida 2015a). In terms of primary energy, Table 9.1 shows that coal rose from 23.2 percent in 2010 to 26.3 percent in 2014. Because coal is the cheapest fossil fuel, there is a risk that Japan will burn even more of it to generate power to reduce the share of more costly oil and LNG. The surge in imports of fossil fuels was expensive. Japan’s 2014 Energy White Paper argued that the extra cost of fossil fuels, to replace idled nuclear power, totaled ¥2.3 trillion in 2011. This sum then rose to ¥3.1 trillion in 2012 and ¥3.6 trillion in 2013 (METI 2015). By way of comparison, Japan’s central government spending on public works in the fiscal year 2015 budget totaled ¥5.4 trillion. Between 2010 and 2014, Japan’s extra imports of fossil fuels, in place of idled nuclear power, helped lead to a 25 percent increase in the average price of power for households and 38 percent for industrial users (Ishida 2015b). Moreover, about 30 percent of Japan’s total imports of all items consists of fossil fuels, and the extra imports to substitute for idled nuclear capacity came at a time when the country’s trade balance seemed to be shifting from structural surplus to deficit. Japan’s amplified geopolitical risks and extra costs for fossil fuels were compelling arguments that the country would return nuclear power to a significant role. Explicit policy offered a further indicator that Japan would undertake multiple nuclear restarts, if not new build. For example, the June 1, 2015,

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METI “Long Term Energy Supply and Demand Outlook” supplemented the April 2014 Basic Energy Plan, with specific targets for 2030. These targets included a projection that between 20 percent and 22 percent of power will be supplied by nuclear generation. Other elements of the projected power mix included a 27 percent share for LNG; 26 percent for coal; 3 percent for oil; between 8.8 percent and 9.2 percent for hydro; and between 13.4 percent and 14.4 percent for solar, wind, and other renewable sources. The new targets saw fossil fuels declining to 56 percent of the power mix by 2030. Moreover, the previous 2010 Basic Energy Plan’s aim of securing 21 percent of power from renewables by 2030 was only marginally increased, to a maximum of 24 percent, with greater detail on the composition. The new plan projected intermittent solar and wind at just 9 percent of the power mix, whereas small hydro, geothermal, biomass, and other nonintermittent renewables were slated to be as much as 15 percent of the mix (Nikkei Asian Review 2015). These numbers are hardly the stuff of a paradigm shift away from nuclear and toward renewables. Adding yet more substance to the image of a return to nuclear was the August 11, 2015, restart of a nuclear reactor by Kyushu Electric at its Sendai nuclear plant in Kyushu Prefecture. This action brought nuclear power back into the mix after nearly two years of being absent due to a complete shutdown of all capacity. The Sendai restart was followed by others, leaving three in operation at the end of 2016. Some analysts project a further two to three restarts per year, leading to perhaps twenty reactors in operation by 2024 (BMI 2015). Or Toward Yet More Disruptive Change?

In spite of the foregoing developments, nuclear power’s prospects in Japan seem poor. For one thing, even were it to be achieved, the new 20–22 percent nuclear target for the 2030 power mix would represent a significant reduction in nuclear power. This reduction is both relative to the 28.6 percent share held by nuclear before 3-11 as well as to the over 50 percent share nuclear was to achieve by 2030 under the 2010 Basic Energy Plan. Moreover, few experts expect even the new energy targets to be met, as the targets reflected the furious lobbying of the nuclear village rather than an objective assessment of Japan’s best options on energy (Kikkawa 2015). As noted, it is likely that only twenty reactors will be restarted between 2015 and 2024. That would leave nuclear power providing perhaps 10 percent of total power generation (BMI 2015). Yet Japanese policymakers seem unlikely to acquiesce to continued extreme reliance on imported fossil fuels. Thus a scenario of disruptive

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change has to be considered, based on public opinion, policy, and growth opportunities. For one thing, Japanese public opinion on nuclear restarts remained stubbornly opposed several years after Fukushima. An October 17, 2016, opinion poll revealed that 57 percent of the Japanese public opposed restarts, versus 29 percent in support (Asahi Shimbun 2016). While this opposition did not stop several reactor restarts, it is a major force in Japanese energy policy in spite of the absence of an effective opposition party. In 2013, the Abe cabinet declared itself keen to revive the fortunes of nuclear industry. Yet the cabinet soon became cautious in the face of public opinion and the ever-present risk of new revelations concerning problems at Fukushima Daiichi and other reactor sites. The potential for disruptive change in Japan’s energy economy thus starts with the Fukushima shock and the delegitimation of nuclear power in a very seismically sensitive country. Diffusion of that awareness produced a sustained antinuclear shift in public opinion. This public opinion lacked an effective party to voice it at the central government level, but was expressed via regional and local governments’ opposition to restarting nuclear capacity. The German case also became a model for much of the Japanese energy policy debate, both within the central and subnational governments and more broadly in civil society and the private sector (Tsubogu 2013). After Fukushima, the Japanese public debate underwent an accelerated course of instruction on how other countries were adopting renewable energy in response to the risks of resource price increases and climate change. Renewable energy came to be seen as an opportunity to develop new primary, manufacturing, and service industries. Japan’s public debate also made people aware of just how far behind the country was in its deployment of energy efficiency and renewable energy. Policy also played a large role. For example, local governments became increasingly eager to seize opportunity in the emergence of distributed energy alternatives to highly centralized and concentrated nuclear power. The centralized power assets of the incumbent monopolies led to concentrated economic benefits for a few communities, whereas the risks of accident were distributed among a much broader range of communities (DeWit 2014a). Moreover, by June of 2015, Japan’s ¥16 trillion power market featured over 600 new power producers and suppliers (PPSs), including such new entrants as Toyota (Nikkei Ecology 2015). In September 2012, that number had been sixty-four (Sheldrick 2013). This rapid growth of new entrants anticipated the April 2016 deregulation of the retail power market. Most of these new power firms will not survive, but some will. Among them are an increasing number of local government PPSs and tie-ups between local governments and private-sector PPSs.

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In addition, Japan’s feed-in tariff policy support for diffusing renewables, effective from July 2012, saw over four gigawatts (roughly four large nuclear reactors’ worth) of new renewable capacity deployed in the initial year (Ishida 2013). By the end of August 2016, Japan’s renewable generation capacity had increased to 31.6 gigawatts, of which over 95 percent was solar (Ishida 2016). Indeed, the authoritative Pew Charitable Trusts’s Who’s Winning the Clean Energy Race? 2013 noted that Japan’s renewable investment grew fastest in the world through 2013, increasing 80 percent to roughly US$29 billion (Pew Charitable Trusts 2014b). The destabilization of the nuclear village thus saw the diffusion of new ideas. Also, deregulation and other policies spread influence out among a larger range of actors in the central and regional governments. In the wake of 3-11 many of these actors used regional blocs (such as the Kanto and Kansai regional associations) and other organizational vehicles to collaborate, applying pressure on central government agencies to accelerate the rollout of distributed generation and other modernizations of the power economy. By the summer of 2015, with Japan’s Abenomics growth policy faltering badly, renewable energy and efficiency became key elements of a new “local Abenomics” effort to revive Japan’s regional economies (Shibayama 2015). According to influential (and resolutely antinuclear) LDP Diet member Kohno Taro, there were even indications that Abe himself was moving toward a very strong commitment to renewable energy and greatly reduced nuclear (Kohno 2015). Thus, arguments that were beyond the pale before Fukushima—such as ambitious initiatives for smart grids, renewables, and efficiency— became common sense. They also attracted significant fiscal and regulatory support. From 2014, a “National Resilience” paradigm centered on distributed energy was adopted by the central government, all forty-seven prefectures, and a growing list of cities and towns. Fiscal 2016 funding for the National Resilience emphasis on bolstering critical infrastructure against earthquakes, climate change, and other hazards was ¥4.34 trillion, including the initial budget plus supplementary budgets. Spending for FY 2017 on national resilience was projected to be ¥4.46 trillion, based on the fiscal request for the initial budget. The ¥4.46 trillion 2017 fiscal request for the initial budget was an 18.5 percent increase over the 2016 initial budget for national resilience, which was ¥3.67 trillion (NRPO 2016). In addition, April 19, 2016, saw the adoption of METI’s “Energy Innovation Strategy.” Funded at a projected ¥271.1 billion in fiscal year 2017, the strategy centered on deep energy efficiency, local-government-led renewable energy, and the restructuring of the energy system via microgrids and smart cities. It aimed at achieving ¥28 trillion of investment in these items by 2030 (METI 2016).

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Smart Cities

Recent Japanese policies therefore embrace the smart cities, smart grids, and other ICT-centered infrastructure that the nuclear village was quite wary of and able to contain prior to 3-11. But the post–3-11 rebuild of the devastated Tohoku (northeast) region afforded a significant foothold to expand smart city projects in order to bolster resilience. The projects also became increasingly diverse and ambitious in their deployments of renewable power and efficiency (DeWit 2014b). Japanese policymakers understood the immense economic opportunity. For example, the Ministry of Internal Affairs and Communications (MIC) 2016 White Paper on Communications determined that the role of ICT in the Japanese economy was already large and afforded an avenue for sustained growth. The White Paper indicated that nominal output by the various sectors of the Japanese economy totaled ¥964.2 trillion in 2014. The ICT industry represented 8.7 percent of that total, or ¥84.1 trillion. This share was considerably larger than such sectors as wholesale, which accounted for 5.9 percent of economic activity or ¥57.0 trillion. Even construction, a tenth of Japan’s domestic economy in the 1990s, accounted for 6.3 percent of economic activity or ¥60.3 trillion (MIC 2016: 274). Earlier, the MIC’s 2013 White Paper had suggested that a strategic focus on ICT could help countries grow their economies by consuming less in physical commodities, producing and consuming more information rather than the resource-intensive activity of the conventional economic paradigm. The 2013 White Paper also demonstrated that investment in ICT had a significantly larger multiplier effect than conventional public works investment. The multiplier effect refers to the amount of subsequent economic activity generated in response to a given volume of investment. Drawing on a growing body of work suggesting that investment in software and other such “intangibles” (as opposed to such tangibles as plant and equipment) is very productive, the MIC assessed the overall multiplier effect of ICT investment to potentially be as high as 1.98, versus 1.19 for general investment. The Abe cabinet approved this ICT-centered growth strategy on June 14, 2013. The rebuild of the devastated regions on the basis of renewable and distributed energy was a core ambition written into documents by the LDP’s IT Strategy Special Commission (DeWit 2013b). The strategy made smart energy systems key to building disaster resilience, thus validating renewable energy in Japan’s center-right discourse. Japan’s strategy aimed at a profound restructuring of the energy economy, which entails the critical infrastructures that make up the modern urban community and shape the exchange of resources and information among citizens, businesses, and their governments. This emergent paradigm is not peculiar to Japan and is

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evident in the ICT-centered “industrial Internet,” “machine to machine,” Big Data, and related concepts. The smart city model had begun to emerge, as idea and practice, in the early 2000s. But from the beginning of the 2010s, worsening resource, economic, and climate crises were paralleled by such technical advances as the diffusion of Big Data analytics via the cheapening and miniaturization of sensors (Townsend 2013). As Jesse Berst, chair of the Smart Cities Council, notes, the plummeting costs of ICT are “one reason today’s smart phones are stuffed with sensors such as accelerometers, thermometers, hygrometers, ambient light, GPS, and more” (Berst 2014). These and other developments increasingly point to the disruption not just of centralized power generation and transmission but also of a resource-intensive growth dynamic that has characterized the developed economies over the past six decades (Koomey, Matthews, and Williams 2013). Japan and Germany, among others, have aimed at dematerialization of the economy since the 1980s, with an increasing sophistication of policies and programs for reducing resource waste through greater efficiency and recycling. But these initiatives were generally seen as more or less costly interventions in the mainstream economy to reformat and reduce its throughputs and polluting outputs. By contrast, the ICT strategy aims at a different kind of economy, one that is much more resilient and far less resource-intensive. The ICT deployment of sensors that monitor a multitude of aspects of the ambient environment and system parameters is already working to accelerate this transformation of the conventional economy through increasing the scale and speed of payback from new processes. Ironically, some of the most aggressive deployment of ICT is evident in conventional energy. The oil industry’s use of Big Data, in what it refers to as the “digital oil field,” is one example of hard-pressed actors deploying the technology in the face of rapidly rising costs of discovery and extraction (Leber 2012). Prior to 3-11, Japan’s smart city initiatives centered on building a low-carbon and more energy-efficient model in a few cities, with a focus on export opportunities. METI and other policymakers’ ambitions were constrained by the monopoly utilities, the centralized and nuclear paradigm in the power economy, and other strictures of the predisaster status quo. The matter changed dramatically after 3-11, as bolstering local energy independence and disaster-resilience became common sense in the public debate and core public goods for policymakers. The Japanese government’s smart city projects accordingly increased from 22 (Sato 2013) to well over 100. The projects centered on microgrids and other energy management systems that are key to maximizing energy efficiency and the uptake of renewable energy. Many communities are implementing a broad range of smart energy applications, including district heating, energy management

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systems, and interactive LED street lighting, while others confine theirs to one or a few areas of infrastructure. The Japanese central government’s official list of eighty-two Environment Model Cities (Kantei n.d.) includes the METI-led and other smart projects. But the list failed to include numerous local government projects underway from 2014 and afterwards. The list also omitted the growing number of private ventures. Among the overlooked local government projects were several smart city initiatives in the Tohoku region along with such examples as Ashikaga City’s impressive power generation, conservation, and storage-focused project, which took shape beginning in April 2012 (Ishida 2012). Among the private ventures are Panasonic and twelve other firms’ ¥60 billion Fujisawa Sustainable Smart Town (Hata 2013). And by 2016, Sekisui House alone was building smart towns in sixteen locations nationwide. One of Sekisui’s projects is the local power plant (producing 170 percent of its own consumption) Smart Common City Akaishidai in the suburbs of Sendai City (Sekisui 2016: 92). The Japanese were clearly taking a modular approach, building smart cities district by district and then linking them together. Green Growth as an Opportunity

In early 2017, Japan seemed at an impasse over restarting nuclear reactors versus adopting an energy-centered green growth paradigm, even as the power mix was back at an extreme level of dependence on fossil fuels. The potential for nuclear restarts was uncertain and appeared to be quite limited. Though the nuclear issue attracted the most attention, actual policymaking was already moving to maximize the deployment of such alternatives as efficiency and renewables. Examining which of the two idealized options—nuclear or renewable energy—offers the better return provides some insight into policymakers’ shifting incentives. Table 9.3 highlights several decades of profoundly skewed energy RD&D priorities in the IEA countries. Only in recent years have renewable energy and efficiency become a prominent target for RD&D investment. In 1975, nuclear fission accounted for nearly two thirds of total energy RD&D investment by IEA member countries. The figure was over half in 1985 and remained over one third up to 2000. By contrast, renewables and efficiency only became prominent in the 2000s. The early investments in efficiency and renewables, though minimal, appear to have paid off handsomely. For example, the United Nations Environment Programme calculates that global renewable energy investment in 2015 grew by 5 percent on the previous year to reach US$285.9 billion (UN Environment Programme 2016). According to the IEA Energy Efficiency

Energy Transitions in Japan Table 9.3 Energy RD&D Expenditures by IEA Countries, 1975–2014 (2014 US$ millions) 1975 1985 1995 2000

Efficiency Fossil fuels Renewables Nuclear fission Total energy RD&D

426 813 264 6,416 9,921

1,106 2,019 1,172 8,695 16,316

1,450 1,212 967 3,803 10,652

Source: IEA Energy Technology RD&D Statistics.

1,642 1,406 892 3,468 9,812

2005

1,574 1,406 1,283 4,221 12,156

2010

3,937 2,367 3,710 3,937 17,312

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2014

2,656 1,612 2,617 1,864 13,517

Market Report 2016, global energy efficiency investment in 2015 totaled US$221 billion, reducing total energy expenditure in IEA countries by US$540 billion for the same year. Very important for Japan, its fuel import bill of US$128 billion in 2015 was reduced 15 percent (US$19 billion) through improvements in energy efficiency (IEA 2016f: 31–32). Directly comparative data on nuclear power investments appear not to be available. But the 2015 global total of 402 reactors and their installed capacity of 348 gigawatts was considerably lower than the 2002 peak of 438 reactors and the 2006 peak of installed capacity at 368 gigawatts. Moreover, in 2015 global solar power output increased by 33 percent and wind power by 17 percent, whereas nuclear output only expanded by 1.3 percent (Schneider and Froggatt 2016: 11, 17). Thus the enormous research and development investment in nuclear power does not appear to have produced a thriving industry, particularly in Japan. Moreover, the IEA Energy Efficiency Market Report 2016 stressed how important efficiency had become in an era of volatile energy prices. The IEA emphasizes that there is much more efficiency potential to be exploited. In its 2016 report, the IEA declared that global energy intensity had improved by 1.8 percent in 2015. This figure was more than double the annual average over the previous decade. But it warned that energy intensity had to decline by 2.6 percent per year in order to achieve climate change goals (IEA 2016g: 17). Japan’s Smart Model and the Global Challenge

Within such network infrastructure as smart grids and district heating and cooling systems, ICT helps maximize efficiency and the uptake of renewables. This enabling role is the key reason the Japanese MIC and other central agencies view ICT and Big Data as central to alleviating a host of contemporary global crises. In their presentations to the Japanese cabinet and local communities, the MIC draw on the work of global think tanks and

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warn that the number of people living in water-stressed areas is expected to quintuple over the forty-five years between 2005 and 2050. They also point out that “business as usual” means that between 2005 and 2030, emissions of carbon dioxide are expected to increase by 160 percent. Continuation of the status quo also means the consumption of primary energy, particularly through oil and coal, will climb 140 percent over the twenty years between 2010 and 2030. In addition, between 2010 and 2050, the consumption of minerals is likely to exceed present estimates of total reserves (see also Bardi 2014). The main driver for these unsustainable trends is that the world’s urban population is in the midst of an historic explosion. By 2011, half the global total population of seven billion people was urbanized. This share is expected to increase at a higher rate than the global population itself over the coming years. Thus by 2025, the total global population estimate of 8 billion is projected to include 4.6 billion people living in cities. For 2050, by current projections, the total global population of 9.3 billion people will include 6.3 billion people in cities. The foregoing is simply not sustainable, given water and other resource constraints and accelerating climate change. In this fraught context, Japan’s smart-city ICT strategy is becoming the focus of preparations for the 2020 Olympic Games, potentially further accelerating Japanese initiatives. The payoff would not only be a global showcase for technological prowess. It could also help make global city regions more resilient to extreme weather and conventional resource-cost volatility. Toward an Expanded US-Japan “Green Alliance”

Though ambitious, Japan’s rollout of ICT-based resilience seems neither fast enough nor sufficiently comprehensive. One reason is that climate change requires more aggressive mitigation and adaptation than is commonly assumed. During 2014, the Intergovernmental Panel on Climate Change (IPCC) delivered several reports on climate change that are considered authoritative. While quite sobering, they are hardly the full picture. The IPCC cost-benefit assessments neither examine the benefits of an energy paradigm shift nor consider the reality that the costs of renewables and efficiency are falling rapidly (Morales 2014b). The IPCC reports underestimate and at times overlook (generally because the research results are too recent) the gravity of the water-energy-food crisis and the role of such positive feedbacks as changes in the jet stream, accelerated melting of Greenland ice, and albedo shifts in the Arctic region. Nor do the IPCC reports examine the rising pecuniary and other non–climate-related costs of the conventional,

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resource-intensive economy whose extraction costs are increasing (Bardi 2014). In short, the IPCC reports are too conservative. Indeed, the IPCC’s April 2014 summary report, a thirty-three-page overview for policymakers that is what most observers actually read, was “gutted at the insistence of government officials,” according to report coauthor Robert Stavins (Clark 2014). Compared to the IPCC, the US military is less constrained in its assessments of climate change risk and the merits of renewable energy and efficiency. Consistent with several years of military-centered analyses, the 2014 Quadrennial Defense Review warned that the multiplicity of effects produced by climate change “will influence resource competition while placing additional burdens on economies, societies, and governance institutions around the world” (US Department of Defense 2014: 8). The QDR 2014 also pointed out that the US military’s ambitious programs “to increase energy and water security, including investments in energy efficiency, new technologies, and renewable energy sources, will increase the resilience of our installations” (US Department of Defense 2014: vi). These commitments, which include the US Navy’s goal of 50 percent renewables by 2020, were very positively evaluated by the Pew Charitable Trusts, in partnership with Navigant Research, in a January 16, 2014, assessment (Pew Charitable Trusts 2014a). The programs have also been accelerated, with the navy in particular emphasizing the synergistic role of microgrids in maximizing renewables and efficiency (Kliem 2016). The US military does not generate these analyses and programs independently, but rather in cooperation with federal agencies (especially the Department of Energy), the National Renewable Energy Laboratory, the American Council on Renewable Energy (ACORE 2014), and other elements of what perhaps could be described as a green military-industrial complex (DeWit 2013c). There are two important reasons this is relevant to Japan and this chapter. One is that Japan’s Abe regime and the US military both recognize the science of climate change and represent distributed renewables and efficiency as central to disaster resilience and security, a discourse that transcends partisan politics. And a second reason is that since November 2009, there have been US-Japan agreements to cooperate on clean energy technologies and build a Green Alliance. This alliance centers on the diffusion of renewable and efficiency technologies at military bases. There are 109 US military bases in Japan, versus 179 in Germany, 83 in South Korea, and a total of over 5,000 worldwide. The agreements relating to the bases were arranged in 2010, when Yukio Hatoyama was the prime minister of a DPJ government, ironically one eager to act on the nuclear vision. Follow-up after the 2010 agreements included collaboration on deploying renewable and efficiency technologies on US bases in Japan (Ministry

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of Defense, Japan 2013: 211), Okinawa-Hawaii energy cooperation, and other initiatives. The efforts on Japan-side US bases got caught up in the Japanese left-right polarization over the very legitimacy of the bases, a long-standing issue in Japanese politics (Shimabuku 2011). On March 15, 2012, Akahata, the newspaper of the Japanese Communist Party, delivered a stinging blast at use of ¥2.85 billion Japan-side fiscal support (omoiyari yosan) to put solar on US bases, deriding it as a plot to legitimate the installations’ continued presence (Akahata 2012). Against the backdrop of climate change and energy risks, the Communist Party’s knee-jerk dismissal was probably unwise: the US military bases in Hawaii are a key reason that state is credibly committed to 100 percent renewable energy by 2045 (Cole 2015; Cooney 2013; DeWit 2013c). Moreover, as of 2016, the California Energy Commission is partnered with the US Navy to help roll out renewables and microgrids (California Energy Commission 2016). The US-Japan Green Alliance could and should play a larger role. This prospect was recognized by the March 21, 2016, conference on “The US, Japan, and the Future of Renewable Energy.” The conference was held in Honolulu, at the Daniel K. Inouye Asia-Pacific Center for Security Studies, a US Department of Defense institute. The conference featured speakers from Japan’s METI and the private sector. Its US participants included representatives from the US Pacific Command, the US Embassy in Tokyo, the National Renewable Energy Laboratory, and the Hawaii State Energy Office. The event emphasized that “Japan and the U.S. share a special responsibility . . . given their advanced technologies and high proficiency in science that together can help move economies toward a greener, more sustainable, future” (Hall 2016). Both the Japanese government and the US military emphasize building resilience in communities via distributed energy systems and other advanced critical infrastructure. This pragmatic approach to diffusing renewable energy and smart infrastructure helps take the politics out of fighting climate change. It could also help transition the increasingly uncertain, and potentially dangerous, role of the US military in Japan and the rest of the Asia-Pacific. Accelerating the diffusion of sustainable energy, efficiency, and their network infrastructures would help build crucial global public goods, as the QDR and other analyses suggest. Greater US-Japan collaboration on advanced green and smart technologies, centered on military bases and extending through the private economy, helps repurpose the military in unstable times (DeWit 2014c). The substitution of conventional fuel inputs with renewables, and the destruction of unnecessary demand with deep efficiency, would alleviate the pressure on water and other resources that the US military warns exacerbates the risk of conflict. Moreover, closely link-

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ing the world’s number one and number four economies, the United States and Japan, is almost certain to amplify synergies and accelerate the ongoing rollout of resilient and smart communities. Thus, expanded US-Japan Green Alliance collaboration on renewables, far from being dangerous, would instead bolster constructive engagement in the face of existential threats (DeWit 2014d). Conclusion

Devoted for over a century to resource-intensive industrialization, Japan’s response to energy challenges and crises has been marked by extremes of dependence and fateful strategic choices. The speed and scale of Japan’s shift to oil in the 1960s also suggests that energy paradigm shifts may not always require decades (see Smil 2010). This may especially be the case when multiple technological breakthroughs beckon and when there are unprecedented climate damage, extreme energy dependence, fraught geopolitics, and other incentives to disruptive action. In the wake of the 311 natural and nuclear disasters, Japan contends with a costly and continuing nuclear crisis and the eclipse of its resource-intensive, mass-production growth model. Powerful elements in the LDP and the bureaucracy are using green energy to build local resilience and capture the many positive externalities inherent in ramping down Japan’s unparalleled external dependence on energy. The country may thus be on the path to a new and sustainable model that affords it the autonomy and status it has always sought.

10 The New Cost of Plenty Timothy C. Lehmann

The reality is there is no alternative energy source known on the planet or available to us today to replace the pervasiveness of fossil fuel in our global economy and in our very quality of life, and I would go beyond that and say our very survival. —Rex Tillerson, CEO of ExxonMobil (May 25, 2016)

Humanity’s very survival is at stake. The dilemma is that the nascent energy contest between renewables and fossil fuels is heavily weighted in favor of the entrenched infrastructures and concerted interests of the oil majors. Their plan for ongoing fossil fuels dominance seeks only to shift the global energy mix toward natural gas and away from coal in power generation, while maintaining the central role of oil in transportation. Absent rapid deployment of planet-wide atmospheric and oceanic decarbonization systems, the oil majors’ preferred energy mix consigns humanity to a dismal future. The “transition” the oil majors envision would bring a future of mere adaptation to the ravages of global warming and the other destabilizing consequences from the seemingly ceaseless development of conventional and unconventional oil and natural gas resources. The well-paid acolytes of the oil majors cynically prod this shift as an environmentally superior process improvement, which calls for no sacrifices in consumption or quality of life. These apostles of abundance have long held the view that energy is plentiful and will be developed in ample amounts provided only that free markets are allowed to work their special magic and technological innovation yielding more output is given its proper support by industry, society, and, of course, the state (Tillerson 2015; Simon 2013). Seldom does one find in their assessments the costs of any newfound fossil fuel abundance, whether to local environments or geopolitical stability, or anything in between. In this concluding chapter, I detail many of these costs and debunk the most fanciful arguments from proponents of the “new” fossil fuels. Because the scale of the problems accompanying the rise of unconventional energy resources is so vast, I am necessarily giving shorter 205

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shrift to many of the harmful costs of the emerging energy system. This volume’s authors covered many of these so well that I am freer to close with some of the key geopolitical quandaries of this emerging energy order and to explore the necessary characteristics of an alternative one, founded in renewable energy. Perennial resource optimist Daniel Yergin epitomizes oil industry servility as he has giddily enthused over the “shale gale,” finding hydrofracked US shale formations to be “the most significant energy innovation so far this century” (Yergin 2011b: 6; Yergin 2010). Yergin lionized the conviction of the private-sector shale pioneers, who he envisioned stood alone peering deeply into this wondrous present only a few years ago (Yergin 2015). Expounding on this euphoria, David Victor offered an ethnocentric win-win rationale for an energy shift toward more intensive development and use of natural gas. Such a shift would “enrich” US firms who lead in the technology to hydrofrack shale formations and liquefy gas while also “lessening the rate of global warming.” He concluded a recent piece with the innocent question: “what can be done to accelerate the gas revolution and help it spread globally?” (Victor 2013: 103). One thing that was done was to purchase the support of environmental groups to proselytize about the environmental benefits of natural gas, at least relative to coal. For example, the late Aubrey McClendon’s Chesapeake Energy Corporation began secretly funding the Sierra Club in 2007, to promote natural gas as the “bridge fuel” to a more distant clean energy future, one “beyond coal” (Gold 2014: 249–255; Walsh 2012). ExxonMobil followed suit with the Sierra Club in 2009, finalizing a joint lobbying document for carbon tax legislation. ExxonMobil’s other lobbying efforts certainly undermined the Sierra Club’s ill-considered alliance, yet ExxonMobil met its goal of deflecting Congressional attention away from cap and trade legislation (Roston 2015; Lizza 2010; Mackinder 2010). As ever, these efforts revealed the abiding cynicism of the oil majors regarding global warming and climate change, as well as their ceaseless pursuit of corporate autonomy from political authority over energy matters. These and the examples to follow demonstrate yet again the vast tentacular reach and influence of these petrochemical concerns. The oil majors’ history is one of successfully leveraging this adaptive cartelized organizational structure, which includes all manner of other industrial and service firms, to manipulate public information and policy. The leading petrochemical firms act more as a concert than as individual competitive enterprises, even compared with those organized laterally with other petrochemical firms as in trade associations. In contrast, the petrochemical concert leaders leverage their influence up and down their operating value chains to affect diverse economic and political processes and outcomes. As we have seen in practice

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this means, for example, coordinating with automobile firms to tear up electric light rail as in the past, or buying into niche research and intellectual property markets on biochemicals to forestall any biofuels rivals to the oil majors’ interests (as ExxonMobil tried to do with Craig Venter in 2009; LeVine 2011). The petrochemical concert is wealthy and widespread. It influences actors across many industrial and societal sectors because it can multiply its economic effects on infrastructure and products, for example, while also broadening its bases of political influence. The petrochemical concert is the energy system at the core of the world’s economic and social order, and it would require a large “socio-technical transition” to move it to the side in favor of another energy system (Van de Graaf et al. 2016: 6–11, 20–22, 34; Kern and Markard 2016). The Houston-Based Petrochemical Concert

Since the breakup of the Global Climate Council (GCC, 1989–2002), which existed to block greenhouse gas (GHG) emission limitations such as in the Kyoto Protocol, the oil majors have acted on their most toxic externalities only in symbolic ways. For example, ExxonMobil highlighted its carbon-absorbing tree planting program, and BP rebranded itself for a short time as “beyond petroleum” (Skjaerseth and Skodvin 2004: 51, 55; Frey 2002). Despite Royal Dutch Shell and BP’s agreement that “prudent precautionary measures” were warranted by 1998, the oil majors and their allies have continued the GCC mission of diverting or blocking effective action against fossil fuels development and consumption. Around the time of the signing of the Kyoto Protocol, Royal Dutch Shell and BP withdrew from the GCC, seemingly indicating a split among the oil majors from the United States and Europe. Despite the similar appearance today of a transatlantic rift among the oil majors over embracing renewables and recognizing climate change, it is as clear now as it was then that these are little more than temporary posturings before different public constituencies. In the 2015 letter to the United Nations by European petrochemical firms, they proclaimed a need for carbon pricing but didn’t even bother to thinly disguise their simultaneous lobbying for an increased role for natural gas, the most “flexible partner to renewables” (Lund et al. 2015). The current joint ownership of the largest oil and gas reservoirs and production platforms attests to the enduring nature of the Anglo-American-Dutch oil majors’ cartelized operations. For example, the $54 billion Gorgon gas project in Australia has Chevron as the operator and controlling 47.3 percent with ExxonMobil and Royal Dutch Shell each owning 25 percent. The super giant Mishrif reservoir in southern Iraq has ExxonMobil, Royal

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Dutch Shell, and BP as the operators of the prime Rumaila, Majnoon, and West Qurna oil and gas fields with Royal Dutch Shell holding the exclusive twenty-year monopoly on all associated natural gas from these fields (Lando and van Heuvelen 2011). It is self-evident that the oil majors are partners—not rivals—in the biggest energy projects on the planet. This is true whether one looks at older natural gas sites in the North Sea or on land at Groningen, Netherlands, where ExxonMobil and Royal Dutch Shell each own 50 percent of Europe’s most productive natural gas field. Groningen also highlights the faulty design of a gas future as it is now under intense sovereign management due to its worsening seismic instability and depletion dilemmas (Reuters 2016). Coordination among the leading players of the Houston-centered concert of leading petrochemical concerns is also evident in all of the newer oil and gas plays, such as in Mozambique, Thunder Horse in the Gulf of Mexico, or the super giant Tengiz and Kashagan sites in Kazakhstan. The oil majors have operated in this “alliance capitalism” format since late 1927, when they finally came to agreement over the disposition of Dutch East Indies oil in Southeast Asia, setting the stage for the more formal agreements covering the Middle East in July and August of 1928 (Dunning 1997; Reed 1958). The contemporary period is no different. Rivals to the Anglo-AmericanDutch oil majors, whether state or private, are simply incorporated into the deal structures on new energy plays in the upstream or the myriad of downstream activities (e.g., transportation, refining, chemicals and products, etc.). Concerted action by the Western oil majors determines how this primary industrial sector affects global economic and military affairs. For example, if one looks at Russian actors in Iraq at West Qurna II or Chinese actors in the Mozambique deals, one still sees the organizing hand of ExxonMobil and the other majors, not some freewheeling marketplace of creatively destructive competition among actors from many different nations. In fact, West Qurna and the whole of southern Iraq exemplify these realities as ExxonMobil is likely back in as project lead for the water injection infrastructure needed for the future production of all the southern fields (Lando 2015). This was taken away from ExxonMobil for a time after its Kurdish dealings in late 2011. But, the withered Iraqi state was left with no alternatives and is now under International Monetary Fund (IMF) mandate to pay and necessarily defer to the international oil companies (IOCs) (IMF 2016; van Heuvelen and Lando 2016). As a result, ExxonMobil resumes its role as director of energy operations in the region, balancing Saudi-led OPEC from within Iraq. Even before this potentially bountiful future for Iraqi output was arranged, the oil majors had increased Iraqi production so much that it was the second biggest contributor to global oil supply growth in 2015, after the

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United States, and the third most important contributor to ExxonMobil’s future production schedule after Canadian tar sands and liquefied natural gas (LNG) (Asghedom 2016; Denning 2016). In contrast to the tens of billions invested in the Tengiz field in Kazakhstan, where the production yield is still well under a million barrels a day, southern Iraq is cheap and bountiful, adding nearly two million barrels a day of output since Iraq began signing over operation of the prime fields to the oil majors in 2008. Petrochemical concert actors used to have to work through various state apparatuses to achieve their ends, but with Rex Tillerson’s assumption of the office of US secretary of state, this indirect channel of policy influence is supplanted by direct officeholding authority. The policy distance between the US and IOCs such as ExxonMobil has now been evaporated by direct representation, while Tillerson’s history of breaking the Iraqi state in late 2011 with the Kurdish dealings raises serious questions about the composition and framing of US interests going forward (Cafruny and Lehmann 2012). The actual policy distance between the United States and its IOCs was always slender (as it was between the UK and BP and Royal Dutch Shell). It has become practically non-existent since the oil shocks of the 1970s and the subsequent overidentification by the United States with the IOCs as detailed in Chapter 6. Nonetheless, the outright assumption of a foreign office directorship by the chief executive of a leading IOC is new. ExxonMobil, Royal Dutch Shell, and the other Anglo-American-Dutch majors coordinate much of world energy development, and the national oil companies (NOCs), whether from Russia, China, or OPEC states, are really still junior partners to these Western leaders. This is as true at Tengiz, where Chevron is the lead operator and ExxonMobil a junior partner, as it is at the other significant sites around the world. This remains true despite high-profile splits in the IOC-NOC alliance structure, as occurred in March 2016, when Saudi Aramco partially broke up its global alliance with Royal Dutch Shell by severing holdings in the large US-based downstream refinery and petrochemical products joint venture called Motiva Enterprises (Bousso and Seba 2016). ExxonMobil and Saudi Aramco remain joined at the hip, operating refineries and chemical plants inside Saudi Arabia, China, and elsewhere (Rashad and Shamseddine 2017), but the oil majors’ effort to move toward gas separates the IOCs from most of the OPEC NOCs. ExxonMobil distinguishes itself, even from Royal Dutch Shell, as it has sought to cultivate an aura of acceptable inevitability about a transition to natural gas. This stems from ExxonMobil’s position as the leading gas producer in the United States, the leading gas-producing state in the world, and the company’s leading position in the global game of instantiating natural gas as the primary fuel of the future (Natural Gas Supply Association 2016). Qatar’s gas is essentially a wholly owned platform of ExxonMobil,

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and it supplies one third of the world’s LNG. It was a simple concert-sustaining compromise for ExxonMobil to support Royal Dutch Shell’s exclusive control of Iraq’s natural gas, because these top two IOCs jointly operate the West Qurna I field, and both prod the planet toward a gas future (Campbell, Katakey, and Paton 2016). The domineering concert among the leading oil majors is obvious in the many partnerships at producing sites around the world, but it can also be seen in small coordinating realities that set the oil and gas industry apart. These are usually revealed well in time of crisis. One risible example of this amid the all too normal catastrophes the industry generates occurred when BP’s Macondo well blew up in the Gulf of Mexico in 2010. Very little seems to have changed since Harvey Molotch’s analysis of the Santa Barbara oil spill in 1969, and the oil majors continue to ignore or shape regulatory rules as they see fit and affect political outcomes to their ends (Molotch 1970). The spill response plan for the Gulf of Mexico that BP had on file with the US Department of Interior’s Minerals Management Service was identical to ExxonMobil’s, down to the erroneous parts about protecting walruses and references to the same single marine wildlife expert who had been dead for five years (Coll 2012: 608–610). Collusive coordination in regulatory filings, or “competitive bidding” processes, is common, and the broader power of the oil majors emerges in instances when they simply assume the authority of the state. They have done this many times abroad and at domestic accident sites, such as in the Gulf of Mexico in 2010, when they reduced the US president to a mere Socratic observer who only noted that the US state was weaker than BP in dealing with the crisis, as detailed in Chapter 6. In 2013, ExxonMobil simply assumed full command from all federal and state authorities at the Arkansas pipeline spill site and buffaloed reporters away, including via some semblance of air power grounding legitimate news helicopter overflights (Song 2013). The Plans and Operations of the Petrochemical Concert

The reach of the petrochemical concert extends well beyond their occasional showdowns with and end runs around individual state authorities, and includes orchestrating the self-interest of the actors related to their businesses, such as banks, insurance firms, infrastructure and contractor service firms, and all of the political and regulatory officials connected thereto. These actors are part of the broad spectrum of concert-affiliated firms, all of whom gain from the work of the oil majors. They assist in executing the designs of the oil majors by promoting their desired fossil fuel future and thwarting alternatives. For example, JP Morgan Chase, which

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has worked with Standard Oil and its progenitors for generations, was fined nearly half a billion dollars for helping California move away from zero-emission electricity and toward natural gas in electrical generation. From 2010 to 2012, JP Morgan Chase was found to have gamed the electricity pricing of California’s system operator in particular ways that hurt the nuclear industry while assisting the rise of natural gas in California (Davis and Hausman 2016). Not surprisingly, the share of natural gas in total California electrical generation rose from 52.7 percent in 2010 to 60.6 percent in 2014 (US EIA 2016e). This all occurred despite California’s effort to move away from fossil fuels and is of a piece with the massive natural gas storage problems in California so visibly on display with the Aliso Canyon gas leak fiasco, which began in October 2015 (Porter 2017). The direct competition between renewables and natural gas in electrical generation’s future is ripe in California, but less so in other places in the United States where the oil majors have successfully installed a great deal of natural gas infrastructure, altering US energy demand in long-lasting ways (Manzagol 2016). Actors within the petrochemical concert can create energy infrastructural outcomes in specific political and regulatory jurisdictions using price discriminatory tactics and other “market” techniques, but these actors have other, more direct means available as well. For example, Warren Buffett, whose electric grid, pipeline, and fossil fuels businesses are substantial, used his political power in Nevada to derail solar energy’s advances there (Buhayar 2016). Influence from the governor’s office through the public utilities commission was used to change state incentives to the detriment of solar electricity in late 2015, and the nearly immediate relative reduction in solar generation, to the benefit of gas, remained in place for at least a year (Environment America Research & Policy Center 2016: 3). As of this writing, legal challenges against Nevada’s arbitrary commission changes have led to some semblance of a deal not to punish existing solar generators, but the future remains unclear there, as it does in many US states with ballot initiatives on renewable energy (Natter and Chediak 2016). Buffett is particularly atavistic in arguing that climate change has not increased the number or severity of natural disasters such as hurricanes, and even if it did, insurance is repriced every year to the benefit of shareholders, only making his business “larger and more profitable” (Buffett 2016a: 25– 26). Worse, Buffett questions the polluter pays principle and the public goods nature of the environment, arguing: “If society is the one that’s benefiting from the reduction of greenhouse gases, then society should pick up the tab, and I don’t think somebody sitting in a house someplace in Nevada should be picking up the subsidy for their neighbor” (Buffett 2016b). Insurers and banks outside the concert act differently, as Munich Re, UBS, and Allianz illustrate (Ceres 2016; National Academy of Sciences 2016:

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15–17; UBS 2016; Allianz 2015). Of course, the German example of majority funding for renewable energy infrastructure from the citizenry provides a vivid example of how the world might move more quickly toward renewable energy. Yet, the entrenched political power of fossil fuels persists. The coal lobbies in Germany and China may not be coordinated, but they do inhibit movement toward renewables, while the petrochemical concert maneuvers us all toward natural gas. The disingenuous public relations efforts from all fossil fuel actors is self-evident in the “clean coal” and “clean diesel” campaigns that have either led nowhere or resulted in massive legal harm to proven frauds such as Volkswagen AG (Porter 2016). The current effort by some of the European oil companies, such as Total, to offer some support for renewables is as unsurprising as it is misleading (Chasan 2016). Total’s functional subordination to Royal Dutch Shell and BP in Europe and around the world is as observable as was its pursuit of deals with Vladimir Putin’s Russia until the untimely death of former CEO Christophe de Margerie. Putin has proven adept at using Rosneft and other Russian NOCs to collaborate with the Houston concert, and he is a proven ally in the fight against renewables, once saying global warming might “be a good thing. We’d have to spend less money on fur coats and other warm things” (Bullough 2012). His administration has obviously not been progressive on energy and climate change, yet Russia has successfully partnered with both ExxonMobil and Royal Dutch Shell. Royal Dutch Shell’s leaders praised their Russian partners in 2014, and they remain the leading oil major from a Europe still unsteady in dealing with a revanchist Russia (Doroshev and Maznev 2014). Royal Dutch Shell has no doubts about a future relying on more natural gas and relatively fewer renewables. Shell CEO Ben van Beurden summarizes it exquisitely: “We’re more a gas company than an oil company. If you have to place bets, which we have to, I’d rather place them there” (Campbell, Katakey, and Paton 2016). If the oil majors were committed to renewables, why did BP start selling off its solar assets in 2011 and flirt with selling all of its US wind assets in 2013? Why did Rex Tillerson denigrate investment in the entire renewables sector in May 2015, declaring: “we choose not to lose money on purpose” (Koenig 2015)? Of course, ExxonMobil has been choosing to lose money in the long game regarding natural gas, at least since its illtimed acquisition of XTO Energy in 2009. Houston’s game is a global, longterm one. The declining price of natural gas in East Asia, where its most expensive traded forms are consumed, has had a short-term negative effect on ExxonMobil, Chevron, Royal Dutch Shell, and the rest of the oil majors. They remain optimistic on global gas demand increasing, and every new electrical generation plant built to run on gas confirms their long-term planning, as does the freezing or closure of all other types, whether based on coal, nuclear, or renewables. As in 1998, any seeming transatlantic split on energy

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and climate is likely to be immaterial and ephemeral. The Houston-led oil majors are pushing fossil fuels, particularly natural gas, and they are denigrating renewable energy because they are afraid of it. They are cunning, however. They understand that if natural gas takes hold of more of the world’s electrical generation, then it does not matter as much if consumers buy electricity for an all-electric car or gasoline from the corner station. Effectively, they will still be buying either energy input for transportation from ExxonMobil and the rest of the majors. As shown in Table 10.1, the upstream component of investment in oil and gas still greatly exceeds that of all aspects of renewables investment. The oil and gas estimates do not include midstream and downstream operations, including the vast refining and transportation investments by the industry. In contrast, the renewables estimates include all aspects of renewables investments, including in electric cars and smart grid infrastructure investments, which also service fossil fuel–based electrical generation. According to the first International Energy Agency (IEA) study on types of energy investment, LNG liquefaction plants (e.g., not including production platforms or expensive LNG tankers, etc.) received $35 billion alone in investment in 2014, while the majority of all new investment still goes to oil and gas (IEA 2016a: 95–96). In fact, the most recent years have witnessed the greatest growth in natural gas investments and, unsurprisingly, the overproduction of natural gas around the world. For 2016, the trends look to revert to the norm with renewables investment having decreased to $287.5 billion and significant expected increases in upstream oil and gas investment (Blas and Shankleman 2017). Despite the oil majors’ unrelenting efforts to convince the world that natural gas is the environmentally necessary bridge fuel to a better future, global natural gas demand has been largely flat in recent years. According to Cedigaz, in 2014, global natural gas consumption increased only 0.3 percent,

Table 10.1 Worldwide Renewable Energy and Upstream Oil and Natural Gas Annual Investment Estimates, 2004–2015 (in US$ billion) Upstream oil and natural gas exploration and production investment

Renewable energy investment

2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 218

261

340

390

474

407

452

556

606

656

705

62

88

128

175

205

207

276

317

291

269

315 348.5

Sources: Mills and Louw (2016: 9); Evercore ISI (2015).

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while the “international natural gas trade (net of LNG re-exports) reached a volume of 1,007 bcm, a global decrease of 2.8 percent from 2013, the worst result since 2009” (Cedigaz 2015). The IEA sees it similarly, noting: Following a stagnation in 2014, global gas demand is estimated to have returned to growth in 2015. Expansion has remained well below the historical average, however: since 2012, global gas demand has increased by just 1 percent a year, much slower than the ten-year average of 2.2 percent. This report forecasts demand to reach 3.9 trillion cubic meters in 2021, increasing at an average annual rate of 1.5 percent, equivalent to an incremental 340 bcm between 2015 and 2021. . . . Demand in Japan and Korea—which today account for almost 50 percent of global LNG imports—is forecast to stagnate or even decline sharply depending on the scale of nuclear comeback in Japan. (IEA 2016b: 10, 13)

The IEA concluded that the global natural gas slowdown has been driven by weaker demand growth in the United States, China, and Japan, and that without Chinese natural gas demand growth returning to form, “there would be no need for incremental imports throughout the end of the decade. In this case, the oversupply in global gas markets would extend well into the 2020s” (IEA 2016b: 11). Every retained or increased use of cheap coal, nuclear, or renewable energy across the world, particularly in China and the rest of East Asia, eats into the current and future market share of natural gas, upsetting the plans and investments of the oil majors (Yergin 2011b: 715). Because the oil majors have bet on gas as van Beurden so inelegantly put it, they have overbuilt the LNG infrastructure in particular, hoping that import demand rises to take up this gas. This has not yet happened, despite the many gasification terminals and a wider Panama Canal through which the many LNG carriers can traverse. This overbuilt infrastructure includes the novel floating natural gas production platforms of Petronas (Satu) and Shell (Prelude) (Murtaugh and Paton 2016). The Houston concert’s gas investments ensure that any energy transition away from the oil majors’ preferences would be complex and laden with conflict. The renewables sector is significantly weaker than the petrochemical concert with its many allies in related businesses and government offices, all of whom are highly attuned to the oil majors’ preferences and patterns of influencing outcomes. Little New Under the Sun: The Ill-Defined Externalities of the Oil Majors’ Operations

The oil majors are keenly aware of the struggle with the fledgling renewables sector, and they do what they have always done with threats—belittle them in public and, if need be, cozy up to and absorb them in private. In this

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case, they have chosen to portray natural gas as the best fossil fuel complement to growing electrical generation from renewables. Only recently, however, and with little sense of irony, have leaders such as Tillerson begun to equate their energy preferences with humanity’s very survival. This odd response is explicable in part due to the rise of renewables and the creeping realization that promoting ever more costly types of oil and natural gas is harming the planet and their positions in the public marketplace. From the simmering divestment campaigns to the efforts to hold the oil majors accountable, if not liable, for their many decades of harm and denial regarding climate change, the possible reduction in their businesses is starker now than at any time since the end of World War II. The oil majors’ response to these pressures is to decry solar as “facing a new winter” and push natural gas with ever greater vehemence (Felix 2016). While Tillerson has promoted natural gas as a savior of the planet, Harold Hamm of Continental Resources ventured into sheer poetry in using rhetorical flourish to polish self-interest in being perhaps the first to label increased output of US oil and natural gas a “renaissance” (Moore 2011). Despite both industry titans’ open welcome into the Donald Trump administration, Hamm’s empire, based in Oklahoma, does not look much like a renaissance anymore. Hydrofracking’s negative effects on geological stability in the state have finally been accepted, despite Hamm’s best efforts at clamming up the state’s seismological authority, which was housed at the University of Oklahoma under the servile eye of university president and former Democratic Senator David Boren (Elgin 2015; Galchen 2015). One irony of Oklahoma’s tragic approach to its own commons has been the increased earthquakes accompanying unconventional oil and gas drilling actually risking the geologic stability of the massive oil storage and pipeline system at Cushing. In contrast to Oklahoma and much of the US federal government, the Dutch government has acted against natural gas drilling due to its seismic instability consequences. The Groningen field is the largest in Europe, supplying up to 10 percent of EU demand, and while a “conventional” field, it is being conserved due to the harmful effect on the region’s seismic stability. Despite the current role of conventional fields such as Groningen, more costly “unconventional” gas is expected to provide 68 percent of future supply growth, rising from 704 bcm in 2014, to 1,602 bcm in 2035, growing from 20 percent of total gas supplied in 2014, to 34 percent in 2035 (Cedigaz 2016: 12). Despite its higher costs, as Michael Klare noted in this volume (Chapter 2), unconventional gas is frequently promoted with a crude and often illogical geopolitical rationale. For example, Aubrey McClendon stated that: “the United States has the capacity to become the Saudi Arabia of natural gas,” and “if you want to cut oil imports, this is the way to do it, this is how you deOPEC and de-carbonize the economy” (Barrett 2011; Michaels and Landers

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2011). Irrespective of the fact that almost no transportation runs on natural gas, heady pioneers such as McClendon successfully pushed their agenda of ceaseless gas production within a United States used to abundance and visions of energy independence. Yergin, Victor, Hamm, Tillerson, and McClendon all espouse the morality tale that sees the indomitable ingenuity of Western and particularly American individualistic capitalism as the safest guarantor of all things desirable for the body politic, particularly the public’s ongoing faith in its right to boundless energy consumption. Only in passing, in their works, does one find much analysis of the role of the state in the current energy “revolution,” and they almost never recognize the externalities and costs associated with this “new” energy. As is true of nearly every important energy development, little is new, abundance has many costs, and the role of the state is usually outsized, not tertiary. In the specific case of unconventional US shale resources, their identification and development are neither new, nor have they been led exclusively from the private sector. Shale resources were identified by the oil majors in the western United States at least as early as the 1910s, and they received government-protected status under the Mineral Leasing Act (1920), when they were held in trust as US Navy fuel reserves. Shale resources were developed widely across the world at this time, from Scotland to Fushun, Manchuria, where in 1926–1927, the Japanese navy developed them to secure a source of liquid fuels for naval power projection (Crawford and Killen 2010; Dyni 2006; Lehmann 2002: 194–195). Geopolitics has always set the broad parameters of energy development, particularly the costly and technically sophisticated forms of unconventional energy that pique the autonomy desires of both state and petrochemical concert actors. While the role of the state in energy markets was often more direct in prior eras, contemporary hydraulic fracturing of US shale reserves has received many decades of government support. This support has ranged from direct production and research investments to indirect subsidization, while important regulatory safeguards were removed from shale’s developmental path (Cha 2013; Trembath et al. 2012). The overt US governmental intention to develop shale and other expensive unconventional energy resources was particularly striking in the 2005 Energy Policy Act, as the unconventional-related provisions were explicit in stating a desire for US energy, instead of reliance on “unstable” foreign oil. This act also contained the infamous “Halliburton loophole,” which legislated the exemption of the shale industry from the Safe Drinking Water Act. The US Environmental Protection Agency (EPA) still does not fully identify or regulate the chemicals injected during the hydraulic fracture drilling process (US EPA 2015a; Prud’homme 2014: 73–85; Goldman et al. 2013). Nonetheless, in June 2015, the EPA concluded that it did “not find evidence that these mechanisms have

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led to widespread, systemic impacts on drinking water resources in the United States,” while the many narrow, specific instances of contaminated water and other fracking maladies were found to be “small compared to the number of hydraulically fractured wells” (US EPA 2015b: 1). At best, the EPA has been remiss in regulating the oil and gas industry; at worst, it has allowed the industry to self-regulate and put groundwater at risk as well as whole communities along the transportation pathways of these new oils. In water purity, the EPA has relied on data from FracFocus, to whom oil and gas companies “may disclose information voluntarily or pursuant to state requirements about the ingredients used in hydraulic fracturing fluids at individual wells” (US EPA 2015b: 5, n2; Lustgarten 2013). If the nearly voluntary self-regulation that produces seismic instability, earthquakes, and groundwater contamination were not enough reason to restrain this drilling, the chemicals injected into the shale reservoirs transform the oil that is unearthed, increasing the presence of hydrogen sulfide and other compounds in the resulting crude oil. This makes North Dakota’s Bakken crude, for example, much more toxic, volatile, and explosive. The US Department of Transportation noted: “the crude has a higher gas content, higher vapor pressure, lower flash point and boiling point and thus a higher degree of volatility than most other crudes in the US, which correlates to increased ignitability and flammability. . . . It is more volatile than most other types of crude—which correlates to increased ignitability and flammability” (US Department of Transportation 2014: 1, 16). A similar reality of more toxic and transformed crude oil rolling down the tracks of North America in “train bombs” can be found in the peanut butter– like sludge that is the Canadian oil sands bitumen flowing through many pipelines. Tar sands oil has to be chemically treated so that its viscosity improves enough for pipeline transport, creating a toxic diluted bitumen product (dilbit). When it spills out of ruptured pipelines, whose rupturing is made more likely by the acidic and steel-eating chemicals in the dilbit (as it did in Arkansas in 2013, among other places such as the Kalamazoo River in Michigan in 2010), the cleanup is much more difficult and costly (Hasemyer 2016). Hence, wherever possible, the oil majors prefer to take over contamination sites and fend off oversight and accountability (Song 2013). Sovereign authority in this policy domain always seems to lag behind industry’s ability to create situations that cause costly harm. The record $61.6 billion (and still rising) total liability tab for the Macondo well blowout in the Gulf of Mexico illustrates the costly world the oil majors are building. One simple conceptual measure of nonenvironmental costs is the energy return on energy invested metric (EROI). Unsurprisingly, it is lower for unconventional resources than for simpler plays in conventional resource reservoirs such as the Mishrif reservoir in southern Iraq. But, as with any

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contested area of inquiry affecting powerful interests, it is difficult to accurately account for the energy inputs to Canadian tar sands or large offshore oil and gas platforms, for example, that consume much of the associated gas in operations. Nonetheless, it is clear that Canada’s tar sands are much more expensive in terms of energy inputs than conventional oil, as are shale-based oils. Similarly, there is a long-run secular trend since 1919 of declining net energy returns, and this trend has only accelerated with more energy-intensive production from unconventional projects around the world (Brandt et al. 2015, 2013; Hall, Lambert, and Balogh 2014; Guilford et al. 2011; Diederen 2010: 49–50). Le Billon, Bridge, and Lehmann all noted in this volume that the expanded legal construct defining “oil” now includes so many unconventional resources that their increased exploration, processing, and distribution are certainly making our consumption of the resulting energy more expensive and even dangerous. Global warming and climate change are, of course, the greatest external costs of the oil majors’ operations. The oil majors dispute their primary role in causing the undue accumulation of greenhouse gases or of having early knowledge of its effects on the planet’s climate. Their multiple decades of disinforming the public did stave off accountability. But, their recent efforts in this same vein seem ineffectual at best, and more akin to Claude Rains’s shock to find gambling inside Rick’s Café Américain. For example, ExxonMobil’s public spat with Columbia University’s School of Journalism in late 2015, and its thinly veiled threat to reduce corporate ties to the university are hollow and ham-fisted efforts, very unlike the industry’s past when it controlled the “science” by universities and governments for decades surrounding the harms from tetraethyl lead, for example (Cohen 2015; Kovarik 2005). The preponderance of the evidence shows that since the late 1970s, the oil majors understood the climatic consequences of their operations, and even planned accordingly in the Arctic region (Banerjee, Song, and Hasemyer 2015; Jennings, Grandoni, and Rust 2015). First efforts at identifying individual company emissions profiles have led to good albeit crude rankings of potential responsibility for accumulated greenhouse gases since 1854 (Heede 2014: 237). Finding Chevron at the top of one initial ranking is intriguing, and its rank there seems to be influenced by its operations in California and Saudi Arabia since the 1930s, where the eventual large volumes of crude oil seem to have contributed to Chevron’s ranking. Nonetheless, ExxonMobil was almost always the larger company in terms of production (i.e., Standard Oil of New Jersey and Standard Oil of New York together, compared with Standard Oil of California), and ExxonMobil retained coal operations for many decades. An even more intriguing effort is under way at the Carnegie Endowment for International Peace. Their Global Oil-Climate Index is doing good com-

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parative work on the greenhouse gas properties of many different crude oil types (Gordon et al. 2015). Not surprisingly, they have found that the world’s worst “oils,” in terms of GHG emissions in an holistic well-towheels, life cycle accounting, are those from Canada’s tar sands region, particularly the “extra-heavy, high-sulfur bitumen” produced by Suncor and Syncrude. These types of “oil” emit close to 750 kilograms of carbon dioxide equivalents per barrel of crude oil produced and used, whereas conventional types such as Kuwait’s Burgan field emit 510 kg CO2 equivalents per barrel. The Canadian tar sands produced 2.2 mbd of “oil” in 2014, but also generated mountains of petcoke among other by-products, all of which have their own toxic GHG pathologies (Canadian Association of Petroleum Producers 2015: ii). These all add up to the 50 percent greater GHG cost for this “oil” relative to many others. It does not appear that the ruination of the boreal forest carbon sink is part of the equation in these Carnegie estimates, and fully accounting for this ongoing reduction to this doubly efficient carbon sink would further increase the overall costs of these worst “oils” on Earth (Petersen, Sizer, and Lee 2014). David Livingston concluded: “the key takeaway holds—displacing the dirtiest oils in the global economy is worth almost twice as much in terms of climate benefit as displacing the cleanest oils in the global economy” (Livingston 2015: 22). In Chapter 3 of this volume, Le Billon and Bridge explained the necessity of achieving “better oil” before being able to move beyond oil. Limiting these worst unconventional oil and gas plays is an obvious first step, particularly since their climate consequences mirror their ruinous effect on local air quality and population health (Austen 2016; InsideClimate News 2014). Unfortunately, ExxonMobil and most of the other oil majors have only increased their stakes in and reliance upon these unconventional oil and gas plays. The Canadian tar sands project alone, which now accounts for just over a third of ExxonMobil’s reported “oil” reserves, is living up to the warning of James Hansen—its ongoing development means “game over” for the planet (Kusnetz 2016; Hansen 2012). Getting rid of this most costly energy source will be extremely difficult. The oil majors have put their investments in and are now looking forward to steady long-run returns from their unconventional plays and spreading tar sands–like operations to Utah among other locales (ExxonMobil 2016: 58– 62). They disregard the climate consequences and negative feedback loops affecting this very investment in Canadian tar sands, which were on display in the unprecedented spate of wildfires throughout Alberta in May 2016 (Gillis and Fountain 2016; Harvey 2016). Global warming is now driving several negative feedback loops, including the emblematic one wherein mountain snowpack is constantly under stress and being reduced globally, which limits the capacity of hydro-

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electric generation. Hydroelectric sources were 21 percent of global electrical generation in 1973, but they were only 16.3 percent in 2013. Aggregate hydroelectric output has increased across these four decades, but the snowpacks of several key countries and mountain ranges are under stress, particularly in South Asia and South America (IEA 2015a: 18–19). In contrast, natural gas saw its share of global electrical generation rise from 12 to 22 percent over the same period, while in the United States, gas found a rough generating parity with coal for the first time in 2015 (IEA 2015a: 24; US Department of Energy 2016a: 15). With global warming, this downward trend in hydroelectric’s global share is expected to accelerate even more (van Vliet et al. 2016). The most likely substitutes will be from fossil fuels, particularly natural gas. Other negative feedback mechanisms from a warming planet and climate change include warming and rising seas, which release more of the ocean’s frozen methane hydrates, and of course increasing storm intensity, which threatens the world’s coastal energy infrastructures, such as refineries (Laffoley and Baxter 2016; Union of Concerned Scientists 2015b). It seems likely that the oil majors will adapt to these threats to their assets, stranding only those to other owners or lessees that are extremely vulnerable but unworthy of further ownership-based control by the majors. How they treat ownership and insurance of these vulnerable yet productive properties will be good indicators of their own assessments of the consequences of climate change. Will they remove themselves from direct ownership of risky downstream assets as they did from tanker ownership after the Exxon Valdez debacle in 1989? No matter their approach to internal risk assessment, why should the world accept their preferred vision of transitioning to natural gas and adapting to climate change’s ravages? Is this really the best and only path? Bypassing the Bridge: The Environmental and Geopolitical Costs of a Gas Future

Natural gas is not the bridge fuel to a better future. Its overall environmental footprint and its GHG emissions are no better and may even be worse than coal and oil, while its geopolitical consequences do not yield confidence in a better future. Properly assessing methane (CH4) releases from natural gas activities matters, because methane is approximately eighty-six times worse than CO2 in GHG potency over a twenty-year period, and emissions have been chronically mis-measured. Robert Howarth argues that “both shale gas and conventional natural gas have a larger GHG than do coal or oil for any possible use of natural gas and particularly for the primary uses of residential and commercial heating” (Howarth 2014: 47).

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Furthermore, he found “the greenhouse gas footprint of shale gas is significantly larger than that of conventional natural gas, coal, and oil. Because of the increase in shale gas development over recent years, the total greenhouse gas emissions from fossil fuel use in the US rose between 2009 and 2013, despite the decrease in carbon dioxide emissions” (Howarth 2015: 45). Similar trends exist for the world. CO 2 emissions have actually increased every single year since 1992, except for 2009, even if only marginally (IEA 2016d), whereas methane emissions have increased dramatically (National Oceanic and Atmospheric Administration [NOAA] 2016a; Turner et al. 2016; Brandt et al. 2014). Increasing GHG emissions and atmospheric concentrations correlate with the nearly constant rise in average global surface temperatures, and 2016 topped all prior years, particularly in the Arctic region (NOAA 2016b). The steep rise in natural gas production and methane emissions, particularly from unconventional shale reservoirs such as Bakken, are now being measured more precisely. These unconventional plays have contributed much more significantly to the global rise in methane emissions. Through better direct measurement above producing sites, the newer assessments correct some prior accounting discrepancies, all of which significantly undercounted methane emissions (Kort el al. 2016; Zavala-Araiza et al. 2015). The tremendous amount of flaring of natural gas at oil fields is another contributor to the rising GHG tally, and this practice helped account for the Carnegie team’s calculation that the Zubair oil field in Iraq was materially worse than West Qurna, Rumaila, or Kirkuk. In many Iraqi oil fields, flaring rates exceed 70 percent, while the overall national flare rate in 2014 was 60 percent (US DOE 2016b: 12; van Heuvelen 2013b). The accurate measurement of these widespread practices remains problematic. Although the World Bank and others find global flaring to be around 5 percent of total gas production, many highly productive fields are well above this, including those in the Permian and Bakken reservoirs of the United States and all those in Iraq (Tollefson 2016). The move toward globally traded LNG will not reduce GHG emissions or accumulations. The US Department of Energy’s National Energy Technology Laboratory (NETL) concluded that increased reliance on traded LNG would have no positive climate effect compared with existing coal generation. Even if methane released at production sites and in pipeline distribution were better controlled, LNG carries greater energy and environmental costs. The NETL noted: “The liquefaction, ocean transport, and regasification of natural gas are energy intensive activities with significant GHG emissions, accounting for 17.5 percent of the cradle-to-grave emissions” (US DOE, NETL 2014: 11, 18). Others conclude that the GHG dilemma could actually be made worse by China importing LNG instead of

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burning domestic coal (Cushman 2014). In addition to the net negative climate consequences of moving to a gas future, the geopolitical dilemmas are even more troubling. For example, much of the overbuilt LNG infrastructure (e.g., tankers, export terminals, and output itself) is predicated on rising import demand from China and at least constant demand in Japan and elsewhere in East Asia. These presumptions have proven faulty. In the case of China, one has to wonder why the oil majors and their home governments would place confidence in the desire of all state and semi-private Chinese actors to increase their external energy dependencies on the Western oil majors. Why should China be expected to transgress against its own energy autonomy, beyond its existing oil dependency, by building extensive LNG infrastructure and external trade dependencies, which have to be fulfilled largely by the oil majors? As Erickson and Strange noted in Chapter 7, the fact that large-scale Chinese natural gas and LNG reliance has yet to materialize fully is testament to what is likely a fundamentally flawed proposition—that the Chinese state should render itself even less energy autonomous than it already is, particularly in electrical generation and other industrial activities tied to gas and LNG. It is hard to see how any amount of the oil majors’ upstream gas dealmaking with Chinese actors in Mozambique, Qatar, or elsewhere could lead to unbalanced Chinese reliance on imported LNG. In contrast, it is easy to see how dreams of South China Sea resources spur rising Chinese militarism. Erickson and Strange note the particularly aggressive role played by the statedirected China National Offshore Oil Corporation in using its HYSY/HD-981 oil rig to press territorial claims against Vietnam and others in the South China Sea. Nonetheless, the bulk of China’s external natural gas needs are still met via pipeline imports from Turkmenistan and Russia, and these sources are growing in importance relative to imported LNG (International Gas Union 2016: 10). These realities bolster the role of Russian natural gas in northeast Asia, which allows Russia to continue to support China’s maritime expansionism, selling it its first aircraft carrier and implicitly supporting its increasingly aggressive maneuvers out onto the “American Lake” of the Pacific Ocean. One has to wonder whether the new US administration is even capable of seeing Putin’s hand in incentivizing a Sino-American rivalry across the southeastern portion of the Pacific theater. These observations highlight the simple fact that the geopolitics of natural gas are the domain of an even smaller subset of the dominant oil actors, including principally the United States and Russia, and then lesser actors such as Iran, Qatar, Saudi Arabia, ExxonMobil, Royal Dutch Shell, Rosneft, and Gazprom. Much of the geopolitics of gas is not a relief from the geopolitics of oil, but rather a concentrated version of the same old game. LNG is different and does favor the Western oil majors relative to Russia and other

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actors. Thus, the oil majors proselytize for LNG because they seek their own relative advantage among all the natural gas players. But, as Michael Klare noted in Chapter 2, the primary source countries for gas merely demonstrate the continued dominance of the leading oil states, with Russia and the United States occupying two of the top three producing ranks in both oil and natural gas. In short, a transition to natural gas frees no one from the “tyranny of oil,” saves no one from the calamity of climate change. The power politics of world energy remain essentially the same, unless one believes that Qatari gas is somehow different in effect than Saudi oil, or that the oil majors can reform themselves despite their strenuous opposition to renewables and denial of climate change and their role in causing it (for differing views see Ladislaw et al. 2014). The oil majors do not seem unnerved by climate change, and of course they have been eagerly awaiting opportunities to develop the energy resources of the Arctic region since at least 1944 (Pratt 1944). As Dag Harald Claes argued in Chapter 5, the Arctic is a zone where mild geopolitical rivalry among the leading states may be tempered by the many alliances among the oil majors to develop the region’s ever-more accessible oil and gas fields. While the US government did halt cooperation between ExxonMobil and Rosneft at the Universitetskaya-1 well in the Kara Sea in September 2014, it did not end all of the many cooperative arrangements in the northern offshore energy game among firms from the United States, Canada, Norway, Britain, the Netherlands, Japan, and Russia. Similarly, the direct ties among the oil majors and Russia remain intact, including, for example, with US majors in Iraq at West Qurna or Sakhalin Island (Bradshaw 2010). As they have since OPEC’s NOCs tested their limited relative power in the 1970s, collaborative development continues among many actors from these non-OPEC nations, and for the same reason—to enhance one’s own relative autonomy in energy, particularly vis-à-vis OPEC. Development of new, unconventional energy sources—whether Canadian tar sands, Bakken shale, ultra deepwater Gulf of Mexico, Australian LNG, or in the Arctic—is driven by the same complex desire that motivated the major states and firms in the 1970s—to be relatively freer of any possible OPEC dictate. ExxonMobil and Saudi Aramco may be acting as proxies along these lines in a geopolitical and economic contest between the United States and Saudi Arabia since the 2014 price war began, but they are also very much partners in the existing energy order against renewables. They bargain with each other about their relative position in the existing energy system based in oil and gas, while working together against alternatives. For example, they hold in common the desire to stem demand for electric and more fuel-efficient vehicles, and the reduction in crude oil and gasoline prices has been successful to this end. Global sales of all electric and plug-in hybrid electric vehicles

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were approximately 550,000 in 2015, up from 318,000 in 2014, but total vehicle sales across the world were at least 72 million in each of these years (IEA 2016a: 53–55, 2016c: 4). More distressingly, average fuel economy in new vehicle sales in the United States started falling again across 2015, and it fell just below twenty-five miles per gallon in December 2015, as more consumers bought light trucks and less efficient cars than they had in the 1990s (University of Michigan, Transporation Research Institute 2016). In the largest car market, China, electric and other “new-energy vehicles” sales were higher than in the United States, but still only 1 percent of total vehicle sales, far short of affecting overall vehicle stocks and medium-term oil demand. As a result, the medium-term, ten-year global oil demand structure related to vehicles is basically intact (Hirtenstein 2016). The Western oil majors and the leading NOCs from the OPEC states are in hybrid relationships as Naná de Graaff noted in Chapter 4. Their precise ownership relations across the upstream and downstream of the petrochemical value chain have adjusted over time, but the relative power of the states and the collusive bargain among them is the same. Since 2014, another round of bargaining and role redefinition has commenced as the Saudis and others try to play a larger role in oil’s downstream and use some of their oilbased political power. The Saudi decision in 2014 to increase oil production and drive global oil prices down had many economic targets, including: high-cost US shale; Canadian tar sands; and global deepwater plays led by the oil majors. Nonetheless, like October 1973, it was motivated primarily by geopolitics. By the summer of 2014, the Saudis had grown increasingly incensed by a United States that: courted Iran in 2009; overthrew Hosni Mubarak in 2011; abandoned Iraq to Iranian-influenced Shia majoritarian politics; waffled on overthrowing Bashar al-Assad in Syria; and began finalizing the Iranian nuclear accord with its promise of restored Iranian oil production and influence. In a shallow effort to affirm what they perceived as their central role in the world’s energy system, and thus its politics, the Saudis started this price war, or “discovery exercise” as Tillerson labeled it. In the bargain, the Saudis have learned that their relative economic power vis-à-vis the United States is minimal. The United States and its oil majors can use increased Iraqi oil production, future Iranian production, and still record US output from unconventional resources to call the Saudi bluff, maintain US leverage over all the oil states in the Middle East, and even force the Saudis into financial straits. As ever, Tillerson noted the successful rebuff of the Saudi challenge tersely: “We have confirmed the viability of a very large resource base in North America. Never bet against the creativity and tenacity of this segment of our industry” (Rascouet et al. 2016). This latest contest’s outcome confirms the operational theory and findings from Chapter 6. North American relative autonomy in energy was pursued and preserved vis-à-vis Saudi-led OPEC. The United States will liquefact what-

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ever hemispheric “oil” resources are necessary to dilute the leverage of Saudi Arabia and maintain its global dominance over energy and all the actors related thereto. Nonetheless, it is only another temporary victory in an old game, perpetuating the existence of an old energy system built up since World War I, which increasingly relies on tar sands in Alberta and costly shale “resources” to maintain itself. While the same game is played by the Russians, particularly with natural gas in Europe and Germany, the less powerful actors in the Middle East have had to confront their own systemic relative weakness yet again. For their part, Saudi Arabia and the other Sunni emirates have had to cut their government budgets and borrow money on the capital markets in the last few years. To try and stave off even worse financial distress, the Saudis have dangled to the public markets a JP Morgan Chase–brokered meager ownership slice in Aramco. The Saudis have cut their renewable energy program, including solar generation, as well as their illusory “Vision 2030” overhaul of their oil-centric state, jeopardizing the whole region’s budding solar ties to China (Calabrese 2015). In 2014, the Saudis generated statistically 0 percent of their electricity from solar, but used 835,319 barrels of crude oil a day to generate 49 percent of their electricity. This is the least efficient end use for oil. Regressive Saudi practices in energy are paralleled by Saudi Arabia’s ongoing global promotion of the most radical version of Islam (Shane 2016). Long ago, Hans Morgenthau argued that control of oil by feudal “potentates” from the strategically irrelevant desert was “in itself a perversity” of the political order. Morgenthau observed the solitary, negative character of Saudi oil power: They can ruin the highly developed industrial nations, but they are unable to put a new order in the place of the ruined one: for the oil-producing states are devoid of any other element of power through which they could back up a new order to replace the one destroyed. These governments have become in a sense enemies not only of their own citizens but of mankind, because they hold within their hands the power of destruction, either direct or indirect, without any control from above whatsoever and without any compensatory creative ability. (Morgenthau 1975: 50)

While US military power has been used frequently to affect “control from above” in the Middle East since the nearly constant state of regional war began in 1980, the US state is assuredly weaker, relatively, to both Houston’s concert and its own historical traditions. The Houston-based petrochemical concert supports the many decades of US dealings with the Saudi system and influences state policy in its preferred directions. These actors’ collaboration against political, economic, and environmental progress is at odds with humanity’s progress. To be sure, the United States has also sought relative autonomy from OPEC NOCs through unconven-

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tional energy the world over, but in the end, the United States has mainly genuflected to and reified the existing concert of petrochemical power. As Secretary of State Tillerson framed it, for humanity’s survival, it is incumbent on the United States to break up the entrenched power of the oil majors and their many alliances with OPEC NOCs and other actors within the petrochemical concert. This necessary end is elusive, more so now than ever, because the US state is compromised by many decades of servility to the petrochemical concert. This concert’s structural power infuses and circumscribes US state policy at home and abroad. Hans Morgenthau understood this in the 1950s, when this concert first conditioned US policy at home and abroad to its ends. He identified the need to make the state strong enough to curb its vested economic interests, which “use the state to make themselves secure from competitive displacement,” forcing a stark choice of either this “new feudalism of private power or the despotism of the public power” (Morgenthau 1958: 120). Morgenthau observed the central dilemma facing a US hegemony based in petrochemicals: the vitality of the US-led global economic system has resided in its ability to renew itself on new technological opportunities, unfettered by the interests identified with an obsolescent technology . . . this is what we call freedom of competition . . . a function of the rules of the economic game, as formulated and enforced by the state. Yet, the new feudalism, if it is not controlled and restrained, must inevitably tend to abrogate these rules of the game in order to assure the survival of the economic giants which, in turn, tend to take over the functions of the state. (Morgenthau 1958: 119)

A Concert for Clean Energy

A more independent and powerful US state is needed to challenge the petrochemical concert, but one state alone will not be enough. Globally, energy functions more as a “closed enterprise system,” serving the interests of the oil majors and their many political, business, and military allies across dozens of key petrochemical-dependent societies (Green 1972). To alter this, the “conflict methodology” of sociology needs to infuse a new power politics based in renewable energy systems (Collins 1975). The reigning “economic giants,” the oil majors, have configured the global economy and the most important national societies so thoroughly that their micro-tweaking of the gasoline price alters consumer purchases of ten-year vehicle capital stocks in ways that reinforce their ongoing dominance. As two sociologists noted the last time these postwar power realities and behavioral patterns were investigated well: “Corporations have become very sophisticated in selling an ideology of consumerism to the public by hiding the facts and costs of control from those over whom power is exerted”

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(Lehmann and Young 1974: 21). A form of hidden control is indeed exerted over the broad energy consuming masses in the United States, China, and elsewhere, but a different future is possible. The unfortunate truth, however, is that conflict is necessary if any renewables concert is to displace the dominant petrochemical one. In 1946, Standard Oil of California (Chevron) was perfectly situated to challenge Exxon, Mobil, Royal Dutch Shell, and BP for global dominance. Chevron could contemplate this based on its exclusive monopoly position over Saudi Arabia and its excellent petrochemical complex based in California, covering and serving the US military and much of the Pacific theater. An executive named Ronald Stoner drafted a brief competition strategy document detailing how Chevron could unseat Exxon and the others, binding in independent refiners on the Atlantic coast and political power related to them as well as the US military and diplomatic establishment, which were all moving then to base future US influence out of Arabia (US Senate, Subcommittee on Multinational Corporations 1975: 47–52). Stoner’s memorandum was considered and then rejected. Instead, Chevron’s holdings in Saudi Arabia were folded into the existing Exxon-led cartel, which then received an antitrust waiver by the US attorney general in April 1947. It is instructive to note that Stoner’s strategy had economic, military, and political calculations at its center, as expected counterattacks by the other oil majors had to be considered. In contrast, today, there is no exclusive economic power base for a renewables concert with any kind of local or regionally important political authority consistently behind it, and precious little reliable and ongoing support for renewable energy from a powerful military, let alone several, which would be necessary to counter the political muscle of the petrochemical concert. In short, all of this would have to be mustered and then sustained against unrelenting counterattack. Conceiving of an energy transition merely in terms of marginal price differentials and operating efficiencies— as if it were a depoliticized market rational process—deadens its likelihood (Van de Graaf et al. 2016: 19–20; Sovacool 2016; Hancock and Vivoda 2014: 208–209). Similarly dispiriting regarding the necessary evolution of the energy system is the finding that a competitive geopolitics in renewable energy system components (whether the rare earth elements necessary for permanent magnet motors in wind turbines and hybrid vehicle engines or in solar panel production and trade disputes as between China and Germany, etc.) is likely to inhibit broad adoption of these technologies (Scholten and Bosman 2016; Ghosh 2016; Lewis 2014; De Ridder 2013). Addressing these renewables limitations forthrightly could help overcome Houston’s power, but mere belief in the “irreversibility” of an energy transition to renewables is sheer folly (Obama 2017).

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Instead, a power- and conflict-based approach is needed in the following four policy arenas. First, active and sustained backing for renewable energy must come from several leading militaries, not just parts of the US Navy and Marine Corps and their allies in Japan. This would encompass electrical generation and the mobility of various military platforms (e.g., green fleets and aircraft with fourth-generation biofuels; fuel stacks or batteries for land-based vehicles, etc.). If a seventy-ton M1A1 Abrams tank can run on a hydrogen fuel cell stack or a new battery system, then the civilian spillover to trucks and sport utility vehicles is simple. The technical hurdle remains in generating the motive power to replace the 1,500-horsepower engine and 500-gallon fuel tank that yields 0.5 miles a gallon. The transition to the oil era was led as much by militaries as by the civilian sector, and militaries must come to see energy resource–based competitions as anathema compared to enhanced autonomy coming from renewables. Military system operating principles for redundancy and survivability would help ensure energy systems that become more broadly appealing than the efficient, yet expensive efforts of boutique platforms such as Tesla’s. Andrew DeWit identified a nascent “green alliance” between the governments and militaries of the United States and Japan. This is vital and would be better still if Japan’s lead in efficient, electric vehicles were coordinated with Germany’s lead in electrical generation from renewables. It is disconcerting that Germany leads in renewable electrical generation but lags badly in electromobility in transport, while Japan has trended backward on electrical generation, relying on coal and natural gas, despite leading in electromobility. These primary US allies should lead in closing the loop by marrying renewable electricity to ever-more efficient electric transport systems. Instead of a US alliance system based in facilitating oil and natural gas supplies to allies from the Middle East as detailed in Chapter 6, an alliance that levers the system-leading energy advantages of Japan and Germany could help create the insulated political spaces and budget lines necessary for technology breakthroughs and mass deployment in both generation and transport. Toward these ends, military budgets with their civilian and university sector multipliers should be even better secured and put into black budget lines if need be. Second, the power and desire of ordinary citizens for renewable energy need to be fully unleashed. Volkmar Lauber’s chapter demonstrated the impressive return on citizen investment in renewables in Germany, and these programs and incentives need to be universalized, not tampered with. The German citizenry is not unique in investing in local renewable public power projects, rooftop solar, and wind energy, but they are the solitary example among advanced industrial states in driving the majority of deployed renewable generation. Energy consuming citizens in advanced

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industrial and developing states want clean energy, better storage, and more efficient end use. Political and regulatory authorities have to simplify their citizens’ pathways to greener electrical generation and related cleaner transport, again, closing the loop between generation and transportation. Universalizing the primary German tool of well-articulated feed-in tariffs and twenty-year purchasing deals for renewables makes a great deal of sense. The standard two-page power purchase contract in Germany compares favorably to the ridiculous number of pages in each US power purchase agreement, negotiated idiosyncratically across the many US utilities jurisdictions (Morris and Pehnt 2015: 38–39). If renewables are to thrive, the state must ease the process of renewables purchases and certainly nullify the nearly constant, squalid local politics of utility commission backtracking on subsidies and contract terms. Third, subsidies and finance mechanisms must favor long-term support for a renewables concert and disfavor fossil fuels (e.g., large carbon taxes related to production levels and caps on unconventional energy resources). In 2014, global subsidies to fossil fuels were at least $493 billion, while those to renewables were only $135 billion (IEA 2015b: 96, 382). Fossil fuel subsidies have been at least four times greater than renewables in recent years and remain unwarranted (IEA 2016e: 97–100, 470–471). Large-scale public subsidies for and investments in renewables are needed as is the elimination of the constant fluctuation in those subsidies (International Monetary Fund 2015). Too many renewable energy subsidies are put on temporary time lines amid not just contentious but often hostile politics, whether from an EU Commission or a backward local utility commission. Subsidies for fossil fuels go on indefinitely, seemingly without the slightest threat of repeal. For example, solar, wind, and electric vehicle subsidies in the United States are always being capped or timing out, hampering long-term investment and innovative financing mechanisms. Electric vehicle subsidies from the United States are absurdly capped by manufacturer quotas—200,000 in the case of Tesla vehicles—which means the $7,500 federal income tax credit disappears quickly after the 200,000th Tesla car of any type is sold (Randall 2016). China is little better, perhaps due to the influence of similar automobile manufacturers and oil interests. After subsidizing hybrid and allelectric car purchases at a cost of $4.5 billion and directly investing as much as $13 billion in 2015, the Chinese government is phasing out all subsidies by 2021, despite the obvious need to incentivize non-gasoline consuming vehicles to go with more renewable Chinese electricity (Schuman 2017; Spring 2016). Globally, financial governance must evolve to not just price carbon, and all greenhouse gases, but also to strand the worst unconventional energy resources through harsh economic penalties and divestment campaigns against them while fostering greener transportation of all types.

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Finally, to create the political space for more renewable electrical generation and storage to coalesce with more efficient and all-electric transportation, the political power of the Houston-based petrochemical concert has to be reduced. The citizens of the leading states want cleaner transportation and greener electricity, and if their governments can get out of their way by standardizing and simplifying regulatory processes and subsidy support programs on generation and transport, progress is possible. It is simply the case, however, that to achieve this, there must exist the political will to do harm to Houston’s interests and positions across all strata of state and society around the world. Without strong states and civil societies that hobble Houston, the pathways to a clean energy concert either will not come to pass or will continue to do so in only immaterial ways. Stating all of this as necessary for conserving unconventional resources for long-run security of supply or the geologic stability of shale areas would be politically expedient and palatable enough grounds to justify a shift away from Houston’s prerogatives. These rationales have been used before and are necessary again to create the space for an effective renewables concert that works for humanity’s “very survival.”

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The Contributors

Gavin Bridge is professor of economic geography at Durham University and has research expertise in the political economy of natural resources. His research centers on the spatial and temporal dynamics of extractive industries such as oil, gas, and mining. He is coauthor, with Philippe Le Billon, of Oil (2013, 2017) and coeditor of the Routledge Handbook of Political Ecology (2015). Dag Harald Claes is professor at the Department of Political Science, University of Oslo. He specializes in international energy relations, in particular studies of oil-producer cooperation, the energy relations between Norway and the EU, the role of oil in Middle East conflicts, and Arctic oil and gas. Naná de Graaff is assistant professor in international relations at the

Department of Political Science at the Vrije Universiteit Amsterdam, The Netherlands. She publishes in leading journals in international relations (European Journal of International Relations) and journals within the field of international political economy and sociology (e.g., Global Networks, Globalizations, International Journal of Comparative Sociology). Her latest books are American Grand Strategy and Corporate Elite Networks (with Bastiaan van Apeldoorn, 2016), and The State-Capital Nexus in the Global Crisis (coeditor, 2013).

Andrew DeWit is professor in the School of Economic Policy Studies at Rikkyo University in Tokyo. His teaching centers on Japan’s energy policy and local public finance, with an emphasis on bolstering fiscal and other forms of resilience in the face of demographic as well as climate and energy challenges. His recent research focuses on Japan’s use of taxation and transfers to foster compact and disaster-resilient smart communities.

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The Contributors

Andrew S. Erickson is professor of strategy in, and a core founding member of, the Naval War College’s China Maritime Studies Institute. Since 2008 he has been an associate in research at Harvard University’s John King Fairbank Center for Chinese Studies. Erickson is also an expert contributor to the Wall Street Journal’s China Real Time Report, and he runs the research website www.andrewerickson.com.

Michael T. Klare is the Five College Professor of Peace and World Security Studies, a joint appointment at Amherst, Hampshire, Mount Holyoke, and Smith Colleges and the University of Massachusetts, Amherst. He is the author of 14 books and many articles on international security affairs, the arms trade, and resource politics, including:  Resource Wars (2001),  Blood and Oil (2004), Rising Powers, Shrinking Planet (2008), and The Race for What’s Left (2012).

Volkmar Lauber is professor emeritus of political science at the University of Salzburg, Austria. He specializes in comparative public policy and is the editor of Switching to Renewable Power (2005). In recent years his focus has been on renewable energy policy in Europe and the contributions of German civil society and public policy to initiate the shift to renewable power, despite the opposition of the big electricity incumbents and large parts of energy intensive industry. Philippe Le Billon is professor at the Department of Geography of the University of British Columbia. Working at the intersections of environment, development, and security, he is the author of Wars of Plunder (2014) and coauthor with Gavin Bridge of Oil (2017). Timothy Lehmann is faculty director for the social sciences at Excelsior

College. His research focuses on strategic studies and political economy, particularly the relationship of oil to great power grand strategy. His publications include articles and book chapters on the Iraq War, the failure of the League of Nations, US-British-Japanese interwar relations, and contemporary US-China energy relations. His work has appeared in Security Studies, Global War Studies, and the New Left Review as well as edited volumes on the financial crisis and the Iraq War. Austin M. Strange is a PhD candidate at the Department of Government of Harvard University. His research focuses on international political economy, security studies, and Chinese foreign policy.

Index

Abe, Shinzō, 191, 194–195 Accidents, 125–127. See also Oil spills Africa, 30–34 Akins, James, 117 Alaska, 95, 96fig, 97, 104, 116 Albany, New York, 121 Aliso Canyon, 211 Aliyev, Heydar, 31 Alliance capitalism, 12, 74, 208 Almunia, Joaquín, 172 Alternative fuels, 17, 58, 59, 62, 105 Altmaier, Peter, 171 Amauligak field, Canada, 99 Amoco, 119 Anglo-Persian Oil Company (APOC), 27 Anti-trust, 114, 227 Arab embargo on oil (1973–1974), 24– 25, 51, 91, 116–117, 157, 187, 224 Arctic, 19, 37, 40, 42, 45, 61, 223; activity by country, 94tab; Alaska and, 95; amplification, 85–86; anarchy in, 102; Canada and, 98–99; CARA appraisal of oil in, 87, 89–90; climate change and, 104, 200; competition in, 87; Council, 102; debates about exploration of, 88; ecosystems in, 38–39; environmental conditions in, 92; ExxonMobil in, 79; Greenland and, 99–100; indigenous peoples of, 102; infrastructure in, 103; intergovernmental cooperation in, 102–103; investment opportunities in, 89; IOCs in, 86; natural gas reserves in, 87–88, 88tab, 90fig, 91; Norway and, 97–98, 100; ocean, sea ice on, 85; oil

activity in, 86; oil companies in, 103; oil reserves in, 38, 87–88, 88tab, 90fig, 91; policy, 102; real estate, 39; resources, 91–92, 104; Royal Dutch Shell in, 104; Russia and, 86–87, 93– 95, 100; sea boundaries in, 100–101; sea level, 85; sovereignty claims and jurisdiction in, 100–103; states, 101; United States and, 101–102; vulnerability of, 100; wildlife, 86 Argentina, 68 Asia, 86, 144. See also specific countries Australia, 36

Baker Hughes, 122 Baku-Tbilisi-Ceyhan (BTC) pipeline, 31 Barents Sea, 87, 94, 97–98, 104 Beaufort Sea, 39, 101 Bering Sea, 39 Big Data, 197, 199 Biofuels, 59, 126, 207, 228 Bitumen, 43, 45, 59, 63n1, 114, 120– 122, 126, 217 Blair, Tony, 7 Bohai Sea, 118, 143, 152n15 Boren, David, 215 Brandt, Willy, 156 Brazil, 37–38, 41 Brent field, North Sea, 114 British Petroleum (BP), formerly AngloPersian Oil Company (APOC), 27, 49, 66, 119, 210, 227 Brzezinski, Zbigniew, 5, 106 Budzik, Philip, 92 Buffett, Warren, 211

271

272

Index

Burgan field, Kuwait, 219 Bush, George H. W., 29 Bush, George W., 29, 31–32, 105

Cairn Energy, 99–100 California, 202, 211, 218 Canada, 39, 45; Arctic and, 98–99; bitumen of, 121; hydrocarbon resources in, 121; oil in, 16–17; oil production of, 121; oil reserves of, 99; oil sands of, 19, 88, 120–122, 128, 209, 217– 218, 219, 224; United States and, 115; Venezuela and, 122 Capitalism, 12, 74, 208, 216 CARA. See Circum-Arctic Resource Appraisal Carbon, 18, 44, 54, 174, 200, 206. See also Decarbonization; Greenhouse gas emissions; Hydrocarbons Carnegie Endowment for International Peace, 218–219 Carter, Jimmy, 28–29, 32, 179 Caspian Sea, 25–26, 30–32, 35–37 Centcom, US DOD, 32 Chernobyl disaster, 153, 157–158, 163, 169, 181–182 ChevronTexaco, 6, 8, 16, 37, 49, 51, 109, 114, 227 China: Africa and, 32–34; air quality in, 133, 138; assets of, 146; Beijing, 131–136, 138, 143; CBM in, 139, 152n11; challenges of, 132; clean energy in, 133; consumption in, 33, 68, 131, 133, 137; decarbonization in, 49; demand in, 133; dependence on coal, 138; dependence on natural gas, 136; dependence on SLOCs, 132, 146; diversification in, 146, 152n14; economic growth of, 131, 134, 145; electric cars, 11, 229; electrical grid of, 11; environmental concerns of, 132–133, 137–138; gasoline in, 11; GDP of, 133; Germany and, 170–171; greenhouse gas emissions in, 136, 137–138; growth of, 18; hydraulic fracking in, 140; Japan and, 16, 185; leaders of, 132; LNG in, 134–135, 139, 140–142, 143, 150, 221–222; maritime law enforcement of, 147–148; Maritime Safety Administration of, 148; natural gas

demand in, 135, 151n5; natural gas development in SCS, 142–150; natural gas imports of, 139, 140–141; natural gas in, 11, 13, 20, 27, 33, 134; natural gas markets of, 139– 140; natural gas reserves of, 141, 145–146; navy of, 134–135, 147– 148; NOCs of, 67, 71, 77–79, 133, 140, 151n3; offshore natural gas development of, 135–142; offshore oil development, 135–142; oil consumption in, 47–48; oil demand in, 134; oil development in SCS, 142– 150; oil in, 18, 33, 134–135; overseas suppliers of, 132; pipelines in, 33, 36, 139, 140–142, 152n14; planners in, 134; policy of, 132, 136, 143, 145; pollution in, 138; portfolio of, 134; power generation in, 139; rare earth element production in, 42; resource nationalism of, 17; Saudi Arabia and, 70; security in, 133, 142, 150; self-sufficiency of, 150; shale in, 133–134, 139, 151n5; ship-building industry of, 150; solar and wind in, 179, 180; sovereignty claims of, 134, 142, 143, 146, 147, 150, 152n16; subsidies in, 229; transportation of, 11; transportation tariffs in, 152n14; United States and, 34; urban natural gas consumption in, 139; Vietnam and, 38, 148–149; warships of, 34. See also Beijing China National Offshore Oil Corporation (CNOOC), 147, 148 China National Petroleum Corporation (CNPC), 78, 140 Chinese Communist Party, 78 Chinese Export Import Bank, 78 Chukchi Sea, US, 97 Churchill, Winston, 109 Circum-Arctic Resource Appraisal (CARA), 87, 89–90 Civil society coalitions and movements, 50–52 Clean energy. See Renewable energy Climate change, 54, 85, 197, 218; Arctic and, 104, 200; cynicism about, 206; definition of, 55; effects of, 201; Germany and, 178, 181; IPCC, 200– 201; Japan and, 183, 199, 200, 202,

Index 203; natural disasters and, 211; oil and causes of, 218; renewable energy and, 201, 207 Clinton, William Jefferson (Bill), 31 Clinton, Hillary, 30 CNPC. See China National Petroleum Corporation Coal, 3, 5, 9; China dependence on, 138; clean, 10, 212; electrical generation and, 5, 11, 59, 128; in Germany, 13, 154–155, 158, 163–164, 168, 175, 177–178; in Great Britain, 1, 21n1; in Japan, 183, 184, 185–186, 200; natural gas and, 11, 25, 59, 128; prices, 136; World War II and, 2–5, 156 Coalbed methane (CBM), 139, 152n11 Cold War, 52, 115, 123 Collective Security Treaty Organization, Russia, 32 Colorado Fuel and Iron Company, 5 Commission on the Limits of the Continental Shelf, UN, 101 ConocoPhillips, 49, 79, 94 Consumption, 16, 216; of Asia, 144; in China, 33, 68, 131, 133, 137; growth in, 68; of hydrocarbons, 68; natural gas, 35, 137fig, 139; patterns of world, 67–70; renewable energy and, 169; by type, 3tab Corporate elite networks, 70–79 Corporations, 2, 7, 65, 66, 74, 76, 79, 158 Crude oil, 9; Dutch East Indies, 10; exports, 125–127; imports, 47; of Iraq, 129n1; of Middle East, 111– 112, 112fig; in North Dakota, 46; quality decline of, 50; United States, 111–112; volatility of, 217

Davies, Ralph, 109, 128 Decarbonization, 49, 53, 59–60, 64n64, 205 Deep Water Royalty Relief Act, US, 119 Deepwater drilling, 37–38, 42, 46–47, 49 Deindustrialization, 111, 175, 177 Demand destruction, 48, 57 Dempsey, Martin E., 29 Denmark, 87, 100–102, 104, 161 Department of Commerce, US, 125

273

Department of Defense, US, 116 Deutsche Bank, 12 Diversification, 30, 146, 152n14 Donilon, Tom, 40 Drilling technologies, 25, 34–35, 43, 95, 118 Dudley, Bob, 75 Dulles, John, 111 Dutch East Indies, 10, 14, 208

Earnest, Josh, 125 East China Sea, 38, 42, 118, 145–146, 152n7, 152n15 EBRD. See European Bank for Reconstruction and Development Ecosystems, in Arctic, 38–39; across world, 215–220 EEG. See Renewable Energy Act EEZ. See Exclusive economic zones EITI. See Extractive Industries Transparency Initiative Electric batteries, 17, 60 Electric vehicles, 18, 60, 107, 181, 213, 223, 229 Electrical generation, 4, 220; in California, 211; coal and, 5, 11-12, 59, 128; in Germany, 153, 156, 159, 160fig, 162tab, 164, 228; hydropower, 60; in Japan, 187–193; oil and, 12–13, 24, 156; in Saudi Arabia, 225; in US, 128, 220 Electricity: consumption in Germany, 178; incumbents, renewable energy and, 173–175, 179; incumbents of Germany, 173–175; prices in Germany, 167, 171–172, 174; storage and renewable energy, 176 Energiewende, Germany, 153–154, 157, 159; curtailing, 175–178; decentralized, 176; German political parties and, 169–172, 175–178; popular support of, 172; rise of, 161–168; significance of, 178–181 Energy. See specific entries Energy Basic Plan, Japan, 189–190 Energy Concept, Germany, 169–170, 176 Energy Information Agency, US, 8 Energy Policy Act, US, 120, 124, 216 Energy return on energy invested (EROI), 217–218

274

Index

Energy White Paper, Japan, 192, 196 Eni, 98 Environment, 18, 43, 45, 61, 132, 133, 137–138. See also Climate change Environment Model Cities, Japan, 198 Environmental Protection Agency (EPA), US, 216–217 E.on, 153, 158, 173 Equity oil, 53 EROI. See Energy return on energy invested Ethanol, 59 EU Emission Trading System (ETS), 159–161, 166, 173–174 Europe, 86, 103, 117. See also specific countries European Bank for Reconstruction and Development (EBRD), 56 Exclusive economic zones (EEZ), 38 Explosives, oil and, 4 Extinction, 86 Extractive Industries Transparency Initiative (EITI), 61, 64n8, 64n10 Exxon Valdez accident, 88, 220 ExxonMobil, 64n8, 66, 114, 119, 122, 206, 208; in Arctic, 79; ChadCameroon pipeline, 55; hydrocarbons and, 49; in Iraq, 122, 130n1; LNG of, 209–210; natural gas of, 6, 63n6, 127–128; oil reserves of, 63n1, 219; policy and, 15; Rosneft and, 126; Royal Dutch Shell and, 114, 127–128; Saudi Arabia and, 14

Feed-in law, Germany, 161–167, 168tab, 172, 176, 178–179, 180, 195, 229 Flanigan, Peter, 117 Forrestal, James, 110 Fossil fuels, 8–9, 17, 44, 58, 82, 106; dominance of, 205; Germany and, 164, 172; greenhouse gas emissions of, 221; in Japan, 189, 192, 193–194, 198; reliance on, 13; renewable energy and, 215; subsidies and, 11, 229; survival and, 205; World Energy Outlook report on, 86n10 Fracking. See Hydraulic fracturing Framework Convention on Climate Change, UN, 55 France, Syria and, 28

Fuels: alternative, 17, 58, 59, 62, 105; biofuels, 59, 126, 207, 228; hydrogen, 59–60, 106–107; natural gas as bridge, 20–21, 128, 138, 206, 220; stocks in Europe, 117; synthetic, 10, 17; taxes, 58; unconventional, 118– 120, 124. See also Fossil fuels Fukushima nuclear disaster, 151n5, 159, 169, 170, 174, 183, 188, 190–191, 194

G20 summit, 57 Gabriel, Sigmar, 175 Gasoline, 2, 11, 59, 125, 223 Gazprom, 75, 76, 94 GCC. See Global Climate Council General Motors, 191 Geopolitics: defined, 4, 15, 23; energy and, 4, 15, 216; as field of study 5, 14; natural gas compared to oil, 35– 36, 140–141, 180–181, 222–223 Georgia, 32 Geothermal systems, 60 “German Problem,” 154 Germany, 10, 20; carbon permits in, 174; cartels, 2–3, 155; China and, 170–171; citizenship in, 159, 212, 228; climate change and, 178, 181; coal in, 13, 154–155, 158, 163–164, 168, 175, 177–178; corporations in, 158; deindustrialization in, 175, 177; economy of, 175, 197; EEG, 163– 168; electrical generation in, 153, 156, 159, 160fig, 162tab, 164, 228; Electricity Act (1935), 155; electricity consumption in, 178; electricity incumbents of, 173–175; electricity prices in, 167, 171–172, 174; Energy Concept of, 169–170, 176; ethics commission in, 169; ETS, 159–161; feed-in-law, 161–168, 168tab, 172, 176, 178–179, 180, 229; fossil fuels and, 164, 172; greenhouse gas emissions in, 169–170, 172; history of geopolitics in, 154–158; labor force in, 177; military of, 3–4; Ministry of Economic Affairs, 162; National Allocation Plan, 174, natural gas in, 159, 174–175, 180; nuclear power in, 153, 156, 159, 164, 167, 168, 169, 174–175, 177; oil crisis in, 156;

Index ownership share in renewable energy, 166tab; pipelines in, 180–181; policy of, 155, 158–161, 178; political parties of, 157–158, 161, 163, 166–168, 169–172, 170, 175–178; Power at EPEX Spot, 167fig; power plant construction in, 159–161; renewable energy in, 17, 20, 153, 157, 158–159, 160fig, 164, 165, 176, 179, 181; renewable energy policy in, 171–172; renewable generators in, 173–175; Russia and, 75, 178– 180; security in, 157; solar and wind in, 163, 168, 169–170, 174–175, 179, 180, 182; Soviet Union and, 156– 157; synthetic oil of, 2–3, 15; tariffs in, 154, 161–166; transportation in, 181; United States and, 155 Gilpin, Robert, 15, 111 Global Climate Council (GCC), 207 Global market, 77, 151n1 Global Oil-Climate Index, Carnegie Endowment for International Peace, 218–219 Global warming, 39, 86, 218–221. See also Climate change Globalization, 71 Goliat oil field, Norway, 98 Great Britain, 1, 21n1, 28 Green Alliance, US-Japan, 200–203, 228 Greenhouse gas emissions, 13–14, 20, 49; in China, 136, 137–138; flaring and, 9, 124, 221; of fossil fuels, 221; GCC and, 207; in Germany, 169– 170, 172; global warming and, 220– 221; LNG and, 221; oil and, 218– 219; of shale, 221. See also Climate change Greenland, 39, 87, 99–100, 104, 200 Groningen field, Netherlands, 114, 215 Groundwater, 216–217 Gulf of Mexico, 6, 37, 100, 103, 112, 116, 118–119, 210, 223 Gulf Wars, 14, 29, 118, 122–124. See also Iraq Halliburton, 68, 122, 216 Hamm, Harold, 215 Harper, Stephen, 120, 121 Heavy oils, 19

275

Horizontal drilling, 47 Hormats, Robert, 117 Hormuz, straits of, 149 Human rights, 54–56 Hussein, Saddam, 29 Hybrid vehicles, 18, 107, 181, 223, 229 Hydraulic fracturing (“fracking”), 19, 25, 43, 47, 59, 63n6, 122–123; in China, 140; drinking water and, 216– 217; methane from, 138, 220–221; negative effects of, 215; shale and, 6, 123–124, 206, 216 Hydrocarbons, 19, 23, 40, 49, 63; in Canada, 122; consumption of, 68; exploration, 119; ExxonMobil and, 49; global flow of, 26; reserves, 125; reservoirs, 7–8, 109; resources, 7, 14, 121, 128; South China Sea and, 142– 143, 147, 149 Hydroelectric generation, 60, 219–220 Hydrogen fuel, 59–60, 106, 107 Hydrogen vehicles, 105–107

Ibn Saud, Abdulaziz (king), 28 Ickes, Harold, 107, 109, 128 IEA. See International Energy Agency IFIs. See International financial institutions IMF. See International Monetary Fund India, 36 Indian Ocean, 135 Indonesia, 144, 208. See also Dutch East Indies Infrastructure, 2, 9, 19; in Arctic, 103; global warming and, 220; grid, 213; LNG, 214, 222; natural gas, 211; oil, 60; renewable energy, 212 Insurance companies, 211–212 Intergovernmental Panel on Climate Change (IPCC), UN, 200–201 Interlocking directorate, 74–76, 83n5 International Energy Agency (IEA), 7, 64n9, 68, 81, 188 International Energy Forum, 62 International financial institutions (IFIs), 55, 56 International Monetary Fund (IMF), 208 International oil companies (IOCs), 2–3, 5–6, 12–13, 15, 50, 51–52, 110–111; in Arctic, 86; directors of, 67, 76; Europe and, 117; IMF and, 208;

276

Index

immunization and subsidization, 117–118; Japan and, 117; NOCs and, 58, 65–67, 73–74, 79–80, 209; role of, 116–117; United States, 112–113, 117–118, 209 International Renewable Energy Agency, 62 Investments, 121, 124, 213, 213tab IOCs. See International oil companies IPCC. See Intergovernmental Panel on Climate Change Iran, 40, 110–111, 115, 224 Iran-Iraq War (1980–1988), 29, 225 Iraq: crude oil of, 129n1, 130; ExxonMobil in, 122, 129n1–130; Great Britain and, 28; natural gas of, 9, 221; oil in, 12, 207–209, 221; oil reservoirs of, 129n1–130; Russia and, 208; United States and, 44, 120; wars, 14, 29, 111, 121, 123, 124 Islam, 225 Islamic State, 32

Japan, 13, 15, 20, 144; Abenomics, 195; anti-nuclear public opinion in, 194; autonomy in, 183; Basic Energy Plan, 193; carbon dioxide emissions in, 200; China and, 16, 185; climate change and, 183, 199, 200, 202, 203; coal in, 183, 184, 185–186, 200; dependence of, 184–185; economy of, 183, 196; Energy Basic Plan, 189–190; Energy White Paper, 192, 196; exports of, 185; feed-in-law, 195; fossil fuels in, 189, 192, 193– 194, 198; Fukushima nuclear disaster, 151n5, 159, 169, 170, 174, 183, 188, 190–191, 194; green growth as opportunity in, 198–199; imports in, 185; incumbent power monopolies of, 190; industrial revolution of, 184; IOCs and, 117; lighting in, 189, 198; LNG in, 183, 192; Middle East and, 111, 187; mineral consumption in, 200; National Resilience in, 195; navy of, 216; nuclear power in, 187– 192, 194, 199; oil in, 183, 184, 185– 187, 192, 200, 203; oil prices in, 187; policy of, 185–192, 194, 196, 198; political parties of, 191–192, 196, 202, 203; power generation in,

190; power market of, 194; rationing in, 184–185; regulations in, 188; renewable energy in, 193, 195–196, 198; self-sufficiency of, 186; smart cities in, 196–198; solar and wind in, 195, 199; sources in, 186tab; supply and demand in, 184; United States and, 185, 200–203, 228; vehicles in, 190 Jevons, William, 1 Jevons’ paradox, 21n1 Johnson, Lyndon, 111 Joint ventures, 66, 83n3, 208 JP Morgan Chase, 210–211, 225 Kansteiner, Walter, III, 31 Kara Sea, 38, 87, 94, 223 Kazakhstan, 79–80, 209 Kennan, George, 111 Keohane, Robert, 14, 65 Keystone XL pipeline, 53, 64n11, 121 Kirchner, Cristina Fernández de, 68 Kissinger, Henry, 117 Kohl, Helmut, 162 Korean War, 110, 115 Korpfjell, 98 Kuwait, 219 Kyoto Protocol, 45, 52, 207 Kyushu Electric, 193

Lac-Mégantic train disaster, 63n7, 217 Law of the Sea, UN, 148 Liberalism, 15–16, 52-53 Libya, 7, 111 Lighting, 189, 198 Liquefied natural gas (LNG), 6, 25; in Africa, 34; in China, 134–135, 139, 140–142, 143, 150, 221–222; exports, 27, 36; of ExxonMobil, 209–210; greenhouse gas emissions and, 221; imports, 214; infrastructure, 214, 222; in Japan, 183, 192; oil and, 151n6; role in global gas trade, 142; in South China Sea, 152n15; storage of, 142; terminals, 36; trade of, 221; vehicles, 106–107 Macondo accident, 49, 55, 100, 126, 210, 217. See also Gulf of Mexico Malacca Straits, 70, 135, 149 Malthus, Thomas, 1

Index Marxism, 15 McCloy, John J., 111 Merkel, Angela, 169 METI. See Ministry of Economy, Trade and Industry Mexico, 6, 12, 115, 116, 127 Middle East: crude oil of, 112, 112fig, 113; Japan and, 111, 187; nationalization of oil industry in, 95; NOCs in, 114; oil consumption and, 106; oil imports of, 113; oil reserves in, 46; oil triangle, 112fig; politics in, 95; United States and, 5, 9, 16, 20, 28, 105–106, 107–115, 128–129. See also specific countries Militarism, 53 Military, and oil, energy, 2, 3–4, 19, 23, 44, 107, 109, 201–202, 227 Mineral consumption, 200 Mineral Leasing Act, US (1920), 216 Minerals Management Service, US, 210 Mishrif reservoir, Iraq, 207–208, 217 Moran, Daniel, 14 Morgenthau, Hans, 15, 225–226 Motiva, 114 Mozambique, 208, 222 Myanmar, 140–141 N Block, Kazakhstan, 79 National City Lines, US, 16, 123 National oil companies (NOCs), 6, 50, 51–52, 54, 56; Chinese, 67, 71, 77– 79, 133, 140, 151n3; directors of, 67, 71–72, 76; expansion of, 77; global expansion of, 65; globalization of, 71; IOCs and, 58, 65–67, 73–74, 79– 80, 209; in Middle East, 114; nonOECD, 70–75, 73fig, 75tab, 77, 79, 81; non-Western, 66; OPEC, 226 Natural gas, 3, 6, 23; in Beijing, 138; as bridge fuel, 20–21, 128, 138, 206, 220; in California, 211; in Caspian Sea, 35; in China, 11, 13, 20, 27, 33, 134, 136; China dependence on, 136; coal and, 11, 25, 59, 128; consumption, 35, 137fig, 139; demand in China, 135, 151n5; development of China in SCS, 142–150; drilling, 215; exports, 36; of ExxonMobil, 63n6, 127–128; as gasoline substitute, 59; in Germany, 159, 174–175,

277

180; green, 124; imports of China, 139, 140–141; infrastructure, 211; investments, 213tab; of Iraq, 9; markets of China, 139–140; in North Dakota, 9, 123; offshore development in China, 135–142; oil and, 9, 128, 223; oil companies and, 6; oversupply of, 10; power generation and, 139; prices, 92; production in United States, 119; reliance on, 34; in Russia, 13, 25–26, 36, 41, 172, 178, 180; security and, 136; storage, 211; synthetic, 138; trade, 214; transportation and, 10; of United States, 215–216; vehicles, 106–107 Natural gas reserves, 68, 69fig; in Arctic, 87–88, 88tab, 90fig, 91; of China, 141, 145–146; by country, 24tab, 35; of East China Sea, 152n7, 152n15; of SCS, 135, 152n15 Natural Resource Charter, 61 NGOs. See Nongovernmental organizations Nixon, Richard M., 28 NOCs. See National oil companies Nongovernmental organizations (NGOs), 54–56 Norsk Hydro, 94 North Dakota, 9, 40, 46, 123, 124 North Pole, Russia and, 100 Norway, 61, 87, 97–98, 100 Nuclear power: expenditures by country, 188tab; Fukushima nuclear disaster, 151n5, 159, 169, 170, 174, 183, 188, 190–191, 194; in Germany, 153, 156, 159, 164, 167, 168, 169, 174–175, 177; in Japan, 187–192, 194, 199

Obama, Barack, 29, 37–38, 97, 105, 121, 125–126, 227 OCS. See Outer Continental Shelf Lands Act, US OECD. See Organisation for Economic Co-operation and Development Oettinger, Günther, 171 Offshore energy: drilling, 126; natural gas development of China, 135–142; oil, 37–40; oil development of China, 135–142 Oil, 2–3, 23, 89; access to, 15; accidents and spills, 46–47, 49, 100, 126, 210,

278

Index

217; age, 3–5; of Alaska, 116; Arab embargo on, 24–25; ban on US exports, 24–25, 125; business, 5; in Canada, 16–17; Caspian Sea and 30– 32; in China, 18, 33, 134–135; companies, 6, 46, 58, 103; consumption, 26tab, 43, 47–48, 48fig, 106; control, military and, 44; corporations and, 7; crises, 24–25, 64n9, 156; curse, 60– 62; demand, 26, 57–59, 107, 127, 134; development of China in SCS, 142–150; easy, 8; economy and, 49; electrical generation and, 12–13, 24, 156; elite networks, transnationalizing of, 75–77; environment and, 45, 61; exports of Iran, 40; future of, 44, 45; global flow of, 24; governance, 51–52, 56–62; greenhouse gas emissions and, 218–219; heavy, 19; imports, 26tab, 113; industry, Big Data and, 197; infrastructures, 60; investments, 213tab; in Iran, 110– 111, 224; in Iraq, 12, 207–209, 221; in Japan, 183, 184, 185–187, 192, 200, 203; LNG and, 151n6; in Mexico, 6, 127; military and, 4, 23, 44, 107–109; natural gas and, 9, 128, 223; new reality of, 45–50; in North Dakota, 123; offshore, 37–40; offshore development in China, 135– 142; Persian Gulf exports, 30; politics and, 19, 45, 47, 50, 54; pollution, 51; prices, 56–57, 69, 88, 92, 111, 120, 187; production, 3, 45, 91, 95, 96fig, 97, 118–121; recovery technologies, 7, 54; reliance on, 35; reservoirs, Iraqi, 130n1; in Russia, 41; sands, 3, 8, 16, 19; in Saudi Arabia, 225; SEC definitions of, 125; security, 27, 51; shock, 24; social dominance of, 19; as socioenvironmental problem, 44; Soviet Union and, 4–5, 30; subsidies, 45; supply and demand, 8, 127; synthetic, 5, 122; tight, 19; trade, 47; transportation and, 10, 43, 53; trends in United States, 108fig; triangle, 112fig; tyranny of, 105; unconventional, 57, 116, 117, 219; United States and, 4; as vital, 23; war and, 14, 27–28. See also Crude oil

Oil reserves, 8, 52, 55, 68; in Arctic, 38, 87–88, 88tab, 90fig, 91; of Canada, 99; control of, 58; by country, 24tab; data, 82n2; of East China Sea, 152n7; of ExxonMobil, 63n1, 219; global, 46; in Middle East, 46; new, 46; proven, 63n5, 69fig; in Saudi Arabia, 46; of SCS, 135, 145–146 Oil spills, 46–47, 49, 100, 126, 210, 217 OPEC. See Organization of the Petroleum Exporting Countries Organisation for Economic Co-operation and Development (OECD), 47, 48fig, 51–52, 65, 67, 75tab, 226 Organization of the Petroleum Exporting Countries (OPEC), 7, 24 Orinco belt project, Venezuela, 122 Outer Continental Shelf (OCS) Lands Act, US, 97

Pahlavi, Mohammad Reza (shah), 28 Painter, David, 4–5, 23, 28, 44, 63n3, 107–108 Pakistan, pipelines in, 36 Paris Agreement (2015), 181 Partnership for a New Generation of Vehicles, US, 119 Partnership types, of non-OECD NOCs, 73fig, 74 Pearl Harbor, 185 Pechora Sea, 38, 94–95 Persian Gulf, 27–29, 30 Petrochemical by-products, 3–4, 208 Petrochemical cartel/concert, 2–3, 5–6, 12, 15–16, 51, 65, 80, 120, 125, 126, 206–213, 225–227, 230 Petro-optimism, 43, 47 PetroVietnam, 148 Philippines, 144 Pipelines: bitumen, 126; in China, 33, 36, 139, 140–142, 152n14; in Germany, 180–181; in Russia, 32; sabotage of, 141; of Soviet Union, 35. See also specific pipelines Polar ice cap, 85-86 Pollution, 50–51, 54, 138 Population, agriculture and, 1 Poverty, 62 Powell, Lewis, 117 Pre-salt fields, of Brazil, 37–38 PreussenElektra v. Schleswag, 168

Index Price volatility, oil and, 56–57, 86–88, 95, 104, 116–118, 187, 199, 224 Prudhoe Bay oil field, 95 Putin, Vladimir, 13, 39, 75, 212 Qaddafi, Muammar, 7 Al Qaeda, 32 Qatar, 6, 27, 35, 222

Rail transport, 9, 16, 63n7, 126 Rapid Deployment Joint Task Force, US, 29 Rare earth elements (REEs), 11, 17–18, 42, 227 Rayner, Charles, 109 Rayon, 3 Reagan, Ronald, 29 Realism, 15, 53, 106, 111, 225–230 Refining, 47–48, 67–70, 115–120, 213 Regulations, 3, 61, 97, 188, 216–217, 230 Renewable energy (clean energy, green energy): climate change and, 201, 207; concert for, 226–230, consumption and, 60, 113, 169; electrical storage and, 176; electricity incumbents and, 173–175, 179; fossil fuels and, 215; in Germany, 17, 20, 153, 157, 158–159, 160fig, 164, 165, 176, 179, 181, 212; industrialization of, 179; infrastructure, 212; investments, 213tab; in Japan, 193, 194, 195–196, 198; military and, 200–203, 227; ownership share in German, 166tab; policy in Germany, 158–161, 171–172; reliance on, 42; Saudi Arabia, 225; subsidies and, 229; survival and, 230 Renewable Energy Act (EEG), Germany, 158–159, 161, 163–168, 171–172, 176 Renewable generators, in Germany, 173–175 Reserves, oil, definition of, 3, 43, 46, 63n1, 90, 125 Resources: Arctic, 91–92; of Asia, 144; availability, 16; competition, 201; conventional and unconventional, 7– 9; definition of, 6–8, 90; depletion, 16; development, 6, 12; endowment, 16; scarcity, 19, 65, 85, 86; unequal distribution of, 70

279

Rockefeller Family Fund, 60 Roosevelt, Franklin D., 28, 107, 114 Rösler, Philipp, 170, 171–172, 180 Rosneft, 103, 126 Royal Dutch Shell, 6–7, 10, 38, 49, 66, 97, 104, 114, 127–128, 209–210, 212, 227 Russell, James, 14 Russia, 20; Arctic and, 86–87, 93–95, 100; Germany and, 75; Iraq and, 208; natural gas in, 13, 25–26, 36, 41, 172, 178, 180; North Pole and, 100; oil in, 41; pipelines in, 32; SinoRussian pipeline, 140–141; Ukraine and, 157; United States and, 39 RWE, 173, 175 Rystad Energy, 8

Safe Drinking Water Act, US, 216 Sasol, 3 Saudi Arabia, 8, 27; China and, 70; ExxonMobil and, 14; oil consumption in, 48; oil in, 225; oil production in, 91; oil reserves in, 46; renewable energy, 225; royalty payments to, 15; secret auctions for, 80; United States and, 43, 114, 227 Saudi Aramco, 76, 114, 223 Schlumberger, 68 Schröder, Gerhard, 75 SDAG, 95 Sea lines of communication (SLOCs), 132, 146 Securities and Exchange Commission (SEC), US, 119, 122, 125 “Seven Sisters.” See International oil companies Shale, 225; in China, 133–134, 139, 151n5; greenhouse gas emissions of, 221; hydraulic fracturing, 6, 124, 206, 216; non- deposits of, 41; overinvestment in, 125; reserves, 124– 125; revolution, 40–41, 123–128; in United States, 40–41, 151n2 Shanghai Cooperation Organisation (SCO), 33 Shareholder value, 55 Shtokman gas field, 95 Siberia, 37, 42 Sieminski, Adam, 8, 124–125 Sierra Club, 206

280

Index

Sino-Japanese War (1895), 184 Sino-Russian pipeline, 140–141 Smart cities, in Japan, 196–198 Snøhvit natural gas field, Norway, 98 Social network analysis (SNA), 71, 74, 80 Social networks, corporate elite, 70–79 Soil quality, biofuels and, 59 Solar and wind: Buffett and, 211; in China, 179, 180; in Germany, 163, 168, 169–170, 174–175, 179, 180, 182; in Japan, 195, 199; tariffs, 165, 168tab, 171; tax credits, 125; in United States, 179 South China Sea (SCS), 131, 134, 222; Chinese natural gas development in, 142–150; Chinese oil development in, 142–150; coastal states, 143; deposits, 145; disputes, 147; geopolitics of, 135; hydrocarbons and, 142– 143, 147, 149; LNG in, 152n15; natural gas reserves of, 135, 152n15; oil reserves of, 135, 145–146; regional perceptions of development in, 144; security and, 142 South Korea, 144 Soviet Union, 4–5, 30, 35, 156–157 Standard Oil, 5, 8, 109, 111, 119, 128, 211, 227 Statist interventionism, 53 Steel industry, 185 Subsidies, 11, 45, 53, 229 Sustainability, 62 Sykes-Picot Agreement (1920), 28 Synthetic fuels, 2, 10, 15, 17, 63n1, 120–122 Synthetic natural gas, 138 Syria, France and, 28 Tar sands, of Canada, 3, 8, 16, 19, 120– 122, 125, 129, 209, 217–219, 224 Tariffs: in China, transportation, 152n14; of Denmark, 161; feed-inlaw, 161–167, 168tab, 172, 176, 178–179, 180, 195, 229; in Germany, 154, 161–166; for photovoltaics, 168tab, 171; solar and wind, 165, 168tab, 171 Tarim basin, China, 133 Taxes, 58, 61, 95, 116, 119, 120, 125, 179

Tengiz field, Kazakhstan, 209 TEPCO. See Fukushima nuclear disaster Terrorism, 32 Tesla, 228 Tight oil, 19 Tillerson, Rex, 14, 205, 209, 212, 215, 224 TNCs. See Transnational corporations Total, 49, 51, 94 Toyota, 60 Trans-Alaska Pipeline, 116 Trans-Caucasus pipeline, 31 Transnational corporations (TNCs), 66, 74, 76, 79 Transnational oil elite networks, 75–77 Transportation, 4, 10, 11, 17, 19, 43, 53, 59–60, 62, 152n14, 181 Trudeau, Justin, 97 Turkmenistan, 35

Ukraine, Russia and, 157 UNCLOS. See United Nations Convention on the Law of the Sea Unconventional energy sources, 3, 8–9, 14, 19–20, 43–47, 57, 88, 106–110, 116, 117, 119–122, 124, 128–129, 205–206, 216–219, 223 United Nations Convention on the Law of the Sea (UNCLOS), 101–102, 104 United States (US), 36; Arctic and, 101– 102; ban on oil exports to, 24–25; Canada and, 115, 116; China and, 34; crude oil, 112, 113; decarbonization in, 49; deindustrialization, 111; Europe and, 103; Germany and, 155; imports, 151n2; independence of, 123–128, 151n1, 216; IOCs, 110, 111, 113, 116–118, 209; Iraq and, 44, 120; Japan and, 185, 200–203, 228; Mexico and, 115; Middle East and, 5, 9, 16, 20, 28, 105–106, 107–115, 128–129; military, 201–202; natural gas of, 215–216; natural gas production, 119; Navy, 201–202; oil and, 4; oil demand of, 107; oil trends in, 108fig; policy, 114, 115; Russia and, 39; Saudi Arabia and, 43, 114, 227; shale in, 40–41, 151n2; solar and wind in, 179; Venezuela and, 115, 116 Uranium, 63n2

Index Urengoy gas field, Russia, 94

Vaca Muerta oil field, Argentina, 68 Vehicles, 119; electric, 18, 60, 107, 181, 213, 223, 229; emissions, 59; hybrid, 18, 107, 181, 223, 229; hydrogen, 105, 106–107; in Japan, 190; LNG, 107; natural gas, 107; sales, 223–224 Venezuela, 41, 115, 122 Victor, David, 206 Vietnam, 38, 144, 148–149 Voluntary Principles on Security and Human Rights, 56 Wang Yilin, 147 War, 4, 14, 27–28. See also specific wars Water, 216–217

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Watts, Philip, 91 West Africa, 31 West Qurna, 208, 210, 221 Wind. See Solar and wind World Bank, 55, 56 World War I, 3, 28, 109, 120, 123, 155 World War II, 3–4, 28, 107, 154–156, 215 Xi Jinping, 34, 147 XTO, 63n6, 122, 212

Yamal Peninsula, 94 Yang Jiechi, 149 Yergin, Daniel, 8, 16, 107, 206 Yoshida, Shigeru, 115 Zhang Hua-chen, 34 Zubair oil field, Iraq, 221

About the Book

In the all-encompassing energy realm, powerful state and private actors determine which of the world’s many energy resources are developed . . . and how societies are molded to accommodate those decisions. The authors of The Geopolitics of Global Energy delve into the energy realm, identifying the infrastructure investments of today that are shaping the use patterns and political dependencies of tomorrow. They explore, as well, the prospects for change to more sustainable and democratically accountable forms of energy. Timothy C. Lehmann is faculty director for the social sciences at Excelsior

College.

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