Will Europe Be Ready in Time?

pa p e r s e r i e s The U.S. Natural Gas Revolution Will Europe Be Ready in Time? Paolo Natali Compagnia di San Paolo Fellow © 2012 Transatlantic ...
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The U.S. Natural Gas Revolution Will Europe Be Ready in Time? Paolo Natali Compagnia di San Paolo Fellow

© 2012 Transatlantic Academy. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means without permission in writing from the Transatlantic Academy. Please direct inquiries to: Transatlantic Academy 1744 R Street, NW Washington, DC 20009 T 1 202 745 3886 F 1 202 265 1662 E [email protected] This publication can be downloaded for free at www.transatlanticacademy.org.

Transatlantic Academy Paper Series The Transatlantic Academy Paper Series presents research on a variety of transatlantic topics by staff, fellows, and partners of the Transatlantic Academy. The views expressed here are those of the author and do not necessarily represent the views of the Transatlantic Academy. Comments from readers are welcome; reply to the mailing address above or by e-mail to [email protected]. About the Transatlantic Academy The Transatlantic Academy was created in 2007 as a partnership between the German Marshall Fund of the United States (GMF) and the ZEIT-Stiftung Ebelin und Gerd Bucerius. The Robert Bosch Stiftung and the Lynde and Harry Bradley Foundation joined as full partners beginning in 2008, and the Fritz Thyssen Foundation joined as a full partner in 2011. The Compagnia di San Paolo joined in providing additional support in May 2009, as did the Joachim Herz Stiftung and the Volkswagen Stifung in 2011. In addition, the Academy received startup funding from the Transatlantic Program of the Government of the Federal Republic of Germany through funds of the European Recovery Program (ERP) of the Federal Ministry of Economics and Technology. About the Compagnia di San Paolo Fellowship Chosen from among Italy’s most promising young academics and policy practitioners, Compagnia di San Paolo Fellows are in residence at the Transatlantic Academy for up to three months. During their fellowship, they interact with the Academy’s long-term fellows, conduct their own research, write a short paper for the Transatlantic Academy Paper Series, and make presentations to audiences of analysts and government officials in the Washington area. The Compagnia di San Paolo Fellowship is made possible by a grant from the Compagnia di San Paolo, Italy.

On the cover: A liquid natural gas tanker at port © Mayumi Terao

The U.S. Natural Gas Revolution: Will Europe Be Ready in Time? Transatlantic Academy Paper Series May 2012

Paolo Natali1

Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 The New Global Gas Glut and Europe’s Position . . . . . . . . . . . . . . . . . . . . . . . . 5 Market Structures as Functions of the Past . . . . . . . . . . . . . . . . . . . . . . . . . . . 9 Infrastructure and Governance in the European Gas Network . . . . . . . . . . . . . . . .15 What Policy Options for Europe? . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19 Policy Recommendations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .29 Bibliography . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .30

 The author wishes to thank the other Transatlantic Academy fellows for their support and comments, in particular Tim Boersma, Stacy VanDeveer, and Philip Andrews-Speed. Special thanks to Jarle Clemmet Molstad of Statoil and Roberto Maria Pattumelli of Royal Dutch Shell, experts in natural gas operations, for their comments and reality checks on gas shipping in Europe. A few further sources of information have requested to remain anonymous; their wish has been respected, and their views have proved equally invaluable in developing the case brought forward in this paper.

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Executive Summary

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he shale gas revolution in the United States is going to bring significant change to the global gas market. As more liquid natural gas (LNG) volumes and short-term opportunities become available, and with the once largest LNG importer set to possibly become an exporter, investment in LNG regasification capacity is flourishing in Western Europe, improving the diversification of sources and therefore overall energy security in the region. But the diversification challenge is felt more strongly on the eastern than on the western side of Europe. What can be done so that gas markets across the European continent are equally able to reap the benefits of the changes the global gas market is experiencing? Countries without LNG terminals will need to find ways to improve the conditions for gas shipping across borders. Europe has a developed gas network but there are

still significant barriers to cross-border shipping, mostly of a technical nature: network infrastructure development but, more importantly, inefficient market rules. Can these obstacles be overcome in a timely manner, before other regions secure LNG imports and the global market is reshaped in a way that is unfavorable to Europe and the transatlantic region? The paper starts with a description of the emerging global glut, and of the incentives and disincentives to integrate markets in Europe. It then moves on to analyze the likelihood that changes will take place, and the policy measures that are needed in order to make the best of the situation, namely the need for a European “shipping passport” to enable easy cross-border exchange of natural gas, and a Fourth Package of measures for the liberalization of the gas market.

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Introduction

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hale gas has become the buzzword of the decade in the oil and gas industry thanks to what could be described as its “negative capability”: its potential to change the nature of the energy supply game by negating some of the traditional dynamics of the market. Most notably, the shale gas revolution has the potential to terminate the West’s dependency on energy supplies produced in remote regions of the world. With the United States now in a position of selfsufficiency with regard to natural gas, the global market for Liquefied Natural Gas (LNG) will potentially transmit these changes to other regions too. Whether this will be beneficial or detrimental to regional markets depends on the strategies that will be put in place in order to exploit the global gas abundance. At first glance, Europe finds itself in a peculiar position. Importing LNG is only possible on the western side of the continent (Greece and Turkey being the exception) and it has higher costs than pipeline gas. But for some countries on the eastern side, the quasi-total import dependency on Russian gas is a source of political risk. Linking the two realities would be mutually appealing, and showing how such integration could be achieved is the goal of this paper. Optimizing procedures, investment, and therefore ultimately flows in the European gas market has been the subject of an extensive literature, and the ideas brought forward here are hardly revolutionary. They simply bring together various attempts at rationalizing the process of market integration. On the policy side, the topic is part of a broader set of actions oriented toward the liberalization of the gas and electricity markets that, due to the nature of the commodities traded, rely heavily on networks in order to connect production and consumption, hence creating a natural monopoly that needs to be addressed through regulation. However, within this framework, the harmonization of market rules has not enjoyed as

much attention, most of which has been directed, instead toward infrastructure investment. The Ten Year Network Development Plan produced by the European association of gas system operators (ENTSO-G) is the most prominent example of this trend [ENTSO-G 2009]. The harmonization of rules is being conducted in a typically European piecemeal fashion. A European Agency of the Cooperation of Energy Regulators (ACER) has been created, as mandated in 2009 by the Third Package for the liberalization of European gas and electricity markets. Meanwhile, ENTSO-G itself is working on common guidelines for Capacity Allocation Mechanisms and Congestion Management Procedures. And finally many of the measures contained in the three liberalization packages, along with the 2004 Directive on the security of gas supply (updated by a Regulation after the two Russia-Ukraine gas disputes in 2006 and 2009), were instrumental to the harmonization of gas market rules across Europe. On top of this, a process called the Gas Target Model has been started, promoted by the Council of European Energy Regulators, with the goal of creating a common framework of rules toward which the European gas market should tend. Finally, a group of 16 Transmission System Operators (TSOs), by their own initiative, is working toward the creation of bundled cross-border capacity products to be auctioned and traded on a common platform covering most of the continental side of Northern Europe by mid-2013. The academic backing for the creation of a harmonized European gas market is strong and present in virtually every research conducted on this topic. The extensive work undertaken by the Florence School of Regulation was the backbone of the Gas Target Model process, and it provides the bases for either the enlargement or a stronger interconnection of current market areas. The latter proposition is also the starting point of this paper

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The shale gas revolution has the potential to terminate the West’s dependency on energy supplies produced in remote regions of the world.

[Glachant and Kalfallah 2011]. The International Energy Agency, for its part, identified a lack of harmonization in gas shipping rules [IEA 2008], a theme that had already been highlighted by the EU Commission in their 2007 inquiry, which provided the grounds for the subsequent negotiation of the Third Package [EU Commission 2007]. Industry consultants have constructed a case similar to the one presented here in their report to the CEER-driven Madrid Forum in 2010 [Everis and Mercados EMI 2010]. Moreover, as a consequence of the United States reaching gas self-sufficiency,

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the first LNG cargoes being made available shortterm, and the first export license being awarded, the initial months of 2012 have seen a flurry of research into the potential impact of LNG availability in Europe. Notably the journal Energy Strategy Reviews has just published an entire issue on the topic [Bahn and Taylor 2012]. Earlier on, the U.S. Congressional Research Service had advanced the view that the LNG market would have created opportunities to be exploited in the coming years [Ratner 2010].

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The New Global Gas Glut and Europe’s Position This “dash for gas” had actually already started across the Western part of the continent during the 1980s, thanks to cheap indigenous gas from the North Sea as well as the fact that relying on coal and oil progressively became unsustainable due to increased environmental awareness. The role of natural gas in the energy mix kept growing steadily into the 1990s and then in the 2000s too under the effect, among other things, of the incorporation of former Soviet satellite states into the European Union. This required them to adapt to a host of environmental and energy regulations, the so-called acquis communautaire, explicitly or implicitly calling for a reduction of the role of heavier hydrocarbons in the energy mix. At present, with 492 billion cubic meters (bcm)/year (roughly 455 Mtoe), natural gas represents over one-quarter of the primary energy consumption in the region [Eurogas 2010; European Commission 2010]. This is a significant source of energy whose level will need to be sustained, and actually increased over time if the most recent estimates foresee an increase to 675 bcm (625 Mtoe) by 2030 [Eurogas 2010]. This increase EU27 Gross Inland Energy Consumption in Mtoe will also be accompanied by a steadier decline of indigenous production, from the current 250 bcm/year down to the region of 150 bcm/year, which is to say there will be a shift from a 48 percent import dependency in 2010 to a fork of 74-80 percent by 2030.1

Stable Energy Demand during the “Dash for Gas” ven as their energy intensity heads downwards, industrialized economies still require significant amounts of energy in order to keep their output growing. In most Western countries, the pace of GDP growth in a normal year is similar to the decline in energy intensity, with the result that total energy demand keeps stable. This is also true for the European Union. Even so, statistics show that this seemingly flat trend masks a very significant development when one looks at the breakdown by fuel: between 1990 and 2010, there has been a major substitution out of coal and into gas and, more recently, renewable sources of energy. The amount of coal consumed has fallen by almost a half from 460 million tons of oil equivalent (Mtoe) to 260 Mtoe, while natural gas has experienced the exact opposite trend, jumping from 290 to 430 Mtoe and being helped by renewables — with their 100 Mtoe increase — to fill the gap left open by the coal phase-out.

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Source: EU Market Observatory for Energy, 2011. Data from Eurostat 2011. “Coal” indicates the aggregate of coal and other solid fuels 1

 Eurogas 2010 reports 74 percent, BP 2011 reports 80 percent.

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The role of natural gas in the energy mix kept growing steadily into the 1990s and then in the 2000s.

The relative capacity of member states to attract natural gas imports varies widely across the region.

Regional Natural Gas Prices The Decline of Declinism in Natural Gas, and a Booming LNG Sector Alas, the destiny of natural gas, or at least of the public debate on it, seems to be facing the same controversy as the one on oil: the nightmare of peaking production and a long inevitable decline is looming in the industry. Despite the idea of exhaustion of resources, which is embedded in Source: U.S. Energy Information Administration 2012. Argos, Heren, Platts front month prices, 2012 the very same definition of That said, however, most shale gas reserves are “fossil fuels,” numerous studies are pointing to not yet commercially recoverable. On top of this, the reality that the timing of this ontological truth many in Europe doubt that there will ever be a very much depends on our estimates as to what significant indigenous production of gas from shale proportion of resources we are exploiting compared reservoirs, due to the controversies surrounding the to the total available, and by how much the pace technology. Mindful of this reality, the European of technological improvement will enhance the Union at large, as well as the member states at recoverability of the less easy hydrocarbons. The national level, are still interpreting security of gas “life span” of natural gas reserves, for example, has supply as a tale of imports from abroad. In the recently been expanded from about 70 years to short and perhaps medium term, this is certainly a almost 300 years by the shale gas revolution, thanks sensible approach. The availability of gas imports to a relatively small technological improvement therefore remains a priority for Europe, and bar a — the combination of hydraulic fracturing and domestic shale gas revolution, a priority that will horizontal drilling — which opened the way to a keep growing in importance in the coming years. huge leap in the figures of technically recoverable reserves worldwide. The relative capacity of member states to attract natural gas imports varies widely across the region. Most Western member states have the

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potential to mobilize capital, mostly through subsidization, toward other sources of energy that can substitute for hydrocarbons (including gas), progressively crowding them out of the energy mix on environmental grounds. Most Eastern member states, despite being bound to introduce 20 percent renewable energy sources to the mix by 2020, will struggle to do so and likely refuse to ever go beyond that threshold after 2020. Their first priority will remain access to cheap energy, that is either coal or natural gas, and the best effort they will be able to make on environmental grounds will be a substitution among hydrocarbons, from coal to gas. This will allow them to at least achieve the CO2-based part of the EU’s Climate Package, i.e. the carbon emissions reduction of 20 percent by 2020 compared to 1990 levels. Hence, given the current direction of energy policy, demand for gas will increase overall in Europe, but geographically speaking it will be driven by the eastern side of the continent.

among regional prices, i.e. the LNG market, is experiencing significant changes. It is early to talk about an impact on European gas markets, but, the story is now reversed from the previous situation in which the better geographical positioning of Europe relative to producing countries favored lower spot prices at the European hubs compared to Henry Hub. The huge availability of natural gas in the United States due to the shale gas discoveries of the past years has led to a situation in which Henry Hub gas sells at about one-quarter the European price [Platts 2012]. The main international consequence of this situation has been a shift in cargo flows, as the United States moved from being the largest net importer of LNG to actually releasing its first export license (a process that is bound to evolve with caution, due to understandable security of supply considerations), as producers start looking over the future commercial viability of directing LNG toward the European shores [Deloitte 2011].

Meanwhile, the relatively small chunk of the gas market that provides arbitrage opportunities

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Demand for gas will increase overall in Europe, but geographically speaking it will be driven by the eastern side of the continent.

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Market Structures as Functions of the Past

Europe Gearing Up for the LNG Impact s is often the case with technological developments, the revolution in gas flows is now exerting its influence on a market structure that had been conceived to face challenges deriving from the history of the hydrocarbons industry, rather than its unforeseeable developments. Since such history has been a tale of exports from the Middle East, Africa, and the former Soviet Union toward Europe, the United States, and North Asia, investment in LNG facilities and the related long-term contracts had been organized around this pattern. The result is that, at present, most of Europe’s LNG imports come from Qatar (41 percent), Algeria (22 percent), and Nigeria (18 percent) [IGU 2010].

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At the same time, in recent years many EU countries started to scale up their LNG capacity, equipping themselves with more regasification terminals in order to reap portfolio diversification benefits from the global market. In 2010, the LNG imports of Europe2 were 81.63 bcm, which equals roughly one-third of the world LNG market (276 bcm were delivered in 2010) and roughly onesixth of the European gas market, which totaled 460 bcm that year. The figure of Europe’s imports equals about half the total capacity of Europe’s LNG terminals, around 160 bcm. A Tale of Pricing The LNG reaching European shores typically comes from long-term contracts whose price formulae

World Gas Trade

Source: Congressional Cartography Program, 2010. Data from U.S. State Department and BP

  EU27 and Turkey.

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Imports in Europe per Exporting Country 2010

Share of LNG World Imports 2010

Source: GIIGNL, The LNG Industry 2010 [Europe includes EU27 + Turkey]

clearly do not have the same flexibility as spot market prices, which is what creates a business rationale for long-term gas sales agreements delivered by LNG. Instead, the pricing of spot LNG is still often unfavorable to the seller, i.e. the spot price of even the highest premium European hub (normally Italy’s PSV) is lower than other spot LNG opportunities around the world. This explains why European LNG terminals are currently only used at around half capacity. The main consequence of this is that LNG tends to be used as a backup, or a complementary element, in a wider trading portfolio, a sort of insurance on a potential lack of shipping capacity via land entry points in many markets, especially those in which domestic gas storage capacity is either not abundant or not available to some types of players, which limits a shipper’s ability to balance its positions in a system.3 This explains the rise of Spain as a major player on the short-term LNG market, which has started to take off in the Atlantic Basin since 1998.  In the Italian gas network, shippers having final customers, or selling directly to distributors having final customers, have priority allocation for gas storage. The storage market effectively clears with these shippers, hence leaving pure traders without the possibility to hedge their balancing risks through storage.

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Instead of merely safeguarding the security of existing long-term supplies coming via pipeline, as the LNG market evolves and price formulae for new long-term contracts move from oil indexation to hub-based spot gas prices, the LNG terminals in the Western shores of Europe as well as across the Mediterranean could become a baseload source of natural gas, provided that the final cost of LNG operations provides a credible alternative to spot prices at the various European hubs. This partially depends on how the United States will decide to play its new role of gas-abundant country: strategically withholding gas volumes by domestic policy action in the United States might significantly delay these developments in the global gas market. But with or without U.S. indigenous LNG, surely volumes that were previously directed toward those shores, and with prices typically linked to the Henry Hub, will be made available elsewhere, creating a downward pressure on prices. This, together with the general acknowledgement that LNG prices will go down over time thanks to new gasification and regasification technologies, has sparked a flurry of activity in developing new LNG capacity on Europe’s shores: to the existing

Pricing of LNG from Qatar by Destination

Source: Waterborne LNG netback calculations 2011 (elaborated by Daniel Fineren)

160 bcm, by 2020 new terminal expansions will add another 30 bcm (costing about €2 billion), new committed terminals will add 50 bcm (with a €4 billion price tag) and the planned and under study LNG capacity by 2020 is more than 200 bcm, potentially costing up to €17 billion (not all of which will be built obviously, depending on economic and political developments). Regasification Capacity becomes Paramount, but its Location Too Having LNG regasification capacity has therefore suddenly become a strategic priority for gashungry European countries; but the potential to develop LNG terminals differs from country to country, opening a gap that can be roughly described in geographical terms as a relative scarcity on the eastern side of the continent versus a relative abundance on the western side. Of the 20 existing terminals and the 6 that are already under construction, only one — Swinoujscie in Poland, financed in 2011 with a €210 billion backing from

the European Union — would directly serve one of the member states that are currently depending on Russian imports for the quasi-totality of their gas supply. In addition, a floating regasification unit at Klaipeda in Lithuania will also be operational in 2014. This is not much in comparison to the capacity available in Western Europe. It must be said that in normal conditions, the countries along Europe’s eastern border are not short on gas supplies. The largest exporter of natural gas to the EU, Russia, sits right beyond the border and satisfies about one-sixth of total EU gas demand, or 34 percent of imports. However, the political risk famously associated with Russian gas supplies implies security uncertainty for those regions. Moreover, the fact that gas from Russia is shipped via pipeline is a cause of concern to the security of supply picture of those regions. Depending on one single supplier also creates a situation by which the price for that gas is not established in a market, but is mostly a function of

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Of the 20 existing terminals and the 6 that are already under construction, only one would directly serve one of the member states that are currently depending on Russian imports for the quasitotality of their gas supply.

LNG terminals 2011-2020 by Volume ( bcm)

Same by Price (€ billion)

Source: GLE investment database and their internal assessment

long-term gas sales agreements and the formulae enshrined in such contracts, typically indexed to oil in the case of Russian supplies.

Alternatives to Russian Gas The alternatives to Russian imports are currently entering the gas network elsewhere in Europe. Algerian gas flows via pipeline to Spain and Italy to cover 14 percent of total imports, whereas

LNG Terminals in Europe

Source: GLE map 2012

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European Natural Gas Market and Major Import Sources

Source: BP, Statistical Review of World Energy, 2008

Norwegian gas flows to the U.K. and the Benelux, to serve most Western EU countries from there, representing 31 percent of imports [EU Market Observatory 2011]. The only land-based diversification alternative could be gas coming from the Southern Corridor route, from the Caspian and beyond. But currently, the only feasible plans to bring volumes to the EU through that route are those linked to the second phase of development of the Shah Deniz field in the Azeri section of the Caspian Sea, whose volumes amount to a mere 10 bcm/year. This is an important diversification initiative but not really able to make a big difference in an import market dominated by 130 bcm flowing annually from Russia and 100 bcm from Norway. And even though those volumes would still make a big difference to some south-eastern EU member states such as Romania and Bulgaria, the choice

of route is still surrounded by uncertainty, and the volumes might end up being entirely diverted to the southern shores of Italy in order to exploit the price premium at PSV relative to the Austrian hub at Baumgarten, which is the main price maker for the Balkan region.

Given that as described, most LNG capacity in the medium run will still be located on the western shores of Europe, the eastern part of the continent will mostly remain dependent on pipeline gas from the Russian neighbor. To illustrate the benefits of LNG availability on the security picture of this region, the example of Greece — 76 percent of whose gas is imported from Russia — offers a clear indication: during the gas supply disruption of January 2009, the Revithoussa regasification terminal alone was able to entirely offset the missing Russian volumes, resulting in supply continuity to match the Greek demand [Noël 2011].

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During the gas supply disruption of January 2009, the Revithoussa regasification terminal alone was able to entirely offset the missing Russian volumes.

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Infrastructure and Governance in the European Gas Network

Physical vs. Regulatory Progress any claims have been advanced as to the necessity to reinforce the European gas network in order to strengthen Europe’s gas market, on grounds that have spanned all three corners of the typical energy policy triangle. Market efficiency is the most obvious benefit, but there would also be security of supply gains for those countries depending on one single source of gas imports. And there would be environmental gains too, as gas would crowd out coal over time, thanks to prices made competitive by increasing emissions restrictions from the combined action of the Industrial Emissions Directive and the Emissions Trading System. Such claims have typically focused on the need to improve infrastructure in order for the molecules to flow.

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Reinforcing physical infrastructure would certainly bring the benefits described above, but the question should be asked as to whether it should actually be accompanied by speeding up another process whose benefits can be potentially even greater: the liberalization of natural gas markets. There is more room for optimization of flows than there is in the improvement of infrastructure. And it goes without saying that optimizing flows through network governance could be achieved at a fraction of the cost of building new physical connection. Physical infrastructure improvement can only be justified in market terms when operators are able to invest in a commercially viable venture. Since network pipes are a regulated business, commercial viability depends on what governments perceive as being an appropriate rate of return on investment. Indeed, the latter translates into transmission tariffs and ultimately raises consumer gas prices, making it a sensitive issue for the gas market. A comparison between EU and U.S. experience on the subject quickly shows that the higher diversification of routes in the United States is due to the regulator allowing rates of return in the

range of 15 percent against the typical 4-5 percent that European gas system operators are allowed to make.4 While 15 percent leads to a pipeline being considered worthwhile even if its capacity will not always be filled, a 4-5 percent rate of return implies a narrower margin and therefore only justifies investment that will be used at congestion level. This creates a case for doing something less costly in order to optimize flows [Jamasb and Pollitt 2007; Boersma 2012]. In addition, it must be noted that half of Western Europe’s LNG capacity is unused. This is the case mainly because that capacity is not necessary for balancing the respective national markets. But it could become a powerful tool to balance other markets, or to make gas volumes, or even simply their option, available to some of the Eastern countries suffering from 100 percent import dependency from one single supplier. In other words, while redundant pipeline investment can be justified on other grounds, it can hardly be justified on market efficiency grounds, as the most efficient way to exploit a piece of infrastructure is to optimize the way its capacity gets used. Certainly network investment is not an area to be neglected, and surely non-market considerations such as security concerns can lead a government to promote the construction of redundant infrastructure, which is exactly what the European Union has mandated with the “N-1 rule”5 enshrined in the 2009 Regulation amending the Gas Security of Supply Directive. But strategic considerations aside, further market improvement would help the European gas market as a whole to

 These rates of return are usually equaled to the Weighted Average Cost of Capital (WACC), and they form the basis for the regulator to set, or assess, the tariff rates. In this process, RPI-X methodology is also often applied in order to incentivise efficiency.

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 “N-1” refers to the requirement for any member state to have a fully functional gas network even if the largest piece of infrastructire should be unavailable.

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There is more room for optimization of flows than there is in the improvement of infrastructure.

reap the benefits of the revolution taking place in the global gas market.

The amount of capacity that remains unused at cross-border points varies from zone to zone, but on average remains higher than the actual security of supply needs would suggest.

The Case for Improving Market Governance Liberalization, of course, is a paradigm that stems from a certain vision of society, the “embedded liberalism” that has underpinned the Western order since the end of World War II. Before the liberalization wave started from the U.K. during the 1980s, the case was made that network-based forms of energy, providing quasi-public common goods, are better managed through state-owned enterprises, and that is why the electricity and gas industry has been initially built in this way in Europe. The reason this vision has changed is that more efficiency was sought, and efficiency in markets comes through increased competition. But there could not be competition without access to the transmission networks. The overarching idea of the market liberalization process that the EU has embarked upon since the 1990s is that molecules can be made to flow more efficiently through the existing network as a consequence of the creation of a market structure —specifically unbundling the transmission segment from the remainder of the industry — which creates the correct incentives for all market players and, in particular, removes barriers to access to the transmission network. This idea has been subject to reconsiderations, since it has been acknowledged that market incentives do not provide all the public goods that are required in these markets, most notably security of supply. As has been pointed out earlier, this problem was addressed in the gas realm at EU level, with the introduction of rules such as “N-1,” “1-in-20” and so forth;6 but the fact that some checks and balances are needed for the  The “1-in-20” requirement implies that any member state needs to have an adequate storage capacity to be self-sufficient for a certain number of days in the coldest winter, or highest demand peak, over the last 20 years.

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market to work does not cancel the importance of the efficiency gains obtainable through the optimization of existing flows. In fact, the situation from which the European gas network starts is one of relative inefficiency. An efficient gas network can be defined as one in which two conditions hold: firm transportation capacity is available for long-term booking by shippers effectively intending to physically make use of it; and after such efficient allocation, the differential between used capacity and maximum capacity is commensurate to the amount of spare capacity policymakers perceive to be needed (together with domestic storage) to protect the system from supply disruptions. It must be pointed out that most of the continental chokepoints are far from this situation. First of all, it is often the case that large incumbents book capacity long term without the intention to ultimately use it but simply to resell it at a later stage, either short term or as interruptible. This practice is discouraged but still possible, and the introduction of Use-It-Or-Lose-It clauses have done little to fix it. The result is that small players, or players in need of short-term flexibility, have to buy capacity short term, which affects their ability to schedule activities and in some cases to physically move gas. Secondly, the amount of capacity that remains unused at crossborder points varies from zone to zone, but on average remains higher than the actual security of supply needs would suggest. A study conducted on continental Europe in 2002, in a network whose chokepoints have not significantly changed since then, showed that cross-border capacity at peak demand times was often significantly larger than necessary, with Netherlands being a provider of flexibility to Germany. But there is an important exception: southbound flows to France, Spain, and Italy were found to be near maximum capacity [Lapuerta and Moselle 2002].

Italy has abundant gas storage capacity and can count on direct supplies via pipeline from Algeria and Libya (despite the trouble experienced with the latter connection during the summer of 2011), and therefore the congestion situation at Griespass and Tarvisio has not raised much attention so far — except that it is considered the reason why gas trades at a premium at the PSV hub. The French and Spanish exception explains the current plans to build an additional connection between these countries at the southern border near Perpignan, in the light of Spain providing flexibility into the French hub PEG thanks to its installed LNG capacity. (The currently existing cross-border point at Larrau only has reverse flow capability of 3 percent in winter and 5 percent in summer, while the other cross-border point at Biriatou is 50 percent reversible, but mostly ancillary to Larrau and only one-tenth its size). France needs such flexibility due to its relatively small storage capacity. But France’s storage capacity also has another important story to teach policymakers. After a milder than expected autumn, in November 2011 the French storage capacity was near full, which prompted the need to export volumes and accordingly send signals to markets, which were depressed for a few weeks

due to the glut and the limited physical ability to bring about a reduction of flows. Barring the mentioned exit points toward Spain, which are already congested, one should question why it was not possible to ease the situation by shipping the volumes elsewhere. A contractual solution to congestion, i.e. virtual reversal of flows leading to a physical reduction of flows, should have been possible at the border points between PEG Nord and Belgium and Germany. But France was not a possible recipient of the flexibility that Germany receives from the Netherlands, which would have otherwise been possible if only appropriate measures had been in place to facilitate the movement of gas in this direction. In other words, the harmonization of rules, leading to the integration of gas networks so that they can exchange the necessary flexibility, appears to be something that the gas market left to itself is not able to provide. This is a sub-category of the broader process of liberalization of Europe’s gas market described above, but a rather central one during a time in which the opportunity to reap the benefits of a global gas glut may be in sight. But appropriate policy measures need to be put in place in order to enable that.

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The harmonization of rules appears to be something that the gas market left to itself is not able to provide.

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What Policy Options for Europe?

Cross-Border Gas Shipping Today f shipping gas cross-border across the European gas market could be made easier through improvements in regulation, and in presence of reversible flow pipelines, there may be gains for Eastern European countries highly dependent on one single supplier, and therefore benefits for the EU as a whole. A governance solution that brings down the costs of shipping gas cross-border by only a tiny fraction could lead to a significant improvement in liquidity, and security of supply, in the countries on the southeastern side of Europe, even before physical investment is made, in order to provide those countries with more network infrastructure, storage, or LNG terminals.

I

At present, cross-border shipping of natural gas is a relatively cumbersome activity within the EU’s territory due to the lack of regulatory coordination among member states and the presence of a large number of Transmission System Operators (TSOs), at least one per member state but even more than one in many large countries. In order to ship gas through a transit country, companies need to make sure the transport capacities they source from the different TSOs match with one another, a rather complex exercise in a situation where capacity allocation mechanisms and congestion management procedures differ widely across networks, not to mention the market compliance rules that each government puts in place. Ironically, most of these mechanisms, procedures, and rules stem from some European requirement aimed at overall harmonization, but the way member states implement them is quite atomized. For a shipper wishing to hypothetically ship gas from the Dutch hub TTF to the Austrian hub CEGH at Baumgarten, it is necessary to undergo the complex process described in Box 1. On top of this, each government will require a number of country-specific license conditions, reporting requirements, strategic storage, and all

of this using rules and deadlines that are far from harmonized at the European level. The risks related to the entirety of this process are high and very diverse. Failure to comply with national legislation and government regulation can lead to fines and in some cases to the revocation of licenses. Inability to balance daily positions within each balancing zone leads to penalties (in regimes where shippers have final balancing responsibility) or cash-out fees (market-based balancing mechanisms with the TSO acting as provider of residual balancing) whose entity is often very similar to a fine, in that it can be even ten times the market spot price of gas. Moreover, the complexity of the system makes it such that market opportunities are not always visible or feasible for all players: each TSO has its own system to allocate capacity (negotiation, auctions, and so forth) and product availability and calendars widely differ. On many occasions, market players behave strategically, gaming the system in order to block out other players: an incumbent will typically book a much larger amount of long-term firm capacity in order to force smaller players to use short-term or interruptible capacity, which increases the risk in their commercial operations and therefore their operational costs. The main consequence of this is that if LNG prices and flows make, for example, Spain relatively gas abundant thanks to its effort to build regasification terminals, it is nearly impossible for Slovakia, Romania, and Bulgaria to see the benefits of these added volumes. For a start, shipping gas from Spain to Romania and Bulgaria is physically impossible in the current network, as Romania is currently not physically connected to the rest of the EU. Neither Romania nor Bulgaria has options from land pipelines. The connection is not even possible through LNG. Until the Constanta import terminal is built, importing from the Istanbul (Marmara Ereglisi) terminal is not an option since the Malkoclar entry point is unidirectional

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Cross-border shipping of natural gas is a relatively cumbersome activity within the EU’s territory due to the lack of regulatory coordination among member states and the presence of a large number of Transmission System Operators (TSOs).

Box 1: From TTF to CEGH

Imagine that a company has bought, or is otherwise going to hold, a certain volume of gas for a period of time, starting the following month (i.e. a “front month” contract), at the TTF hub in the Netherlands. This company believes the price differential with the Austrian hub CEGH at Baumgarten will increase, and therefore intends to sell this volume there. Leaving aside for simplicity any license requirement, in order to simply ship the gas across the continent, the company will need to complete the following: • Acquire exit capacity from the Dutch TSO GasTransportServices at one of the five exit points toward Germany (Bocholtz, Zevenaar, Winterswijk, Vlieghuis, Bunde). • Match it with entry capacity into Germany from the appropriate TSO (Open Grid Europe, Thyssengas, ENI GT DE depending on entry point). • Move it further inside Germany with other TSOs as necessary. continued on page 21

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continued from page 20 • Use exit capacity at either Oberkappel (Open Grid Europe or GRTGaz Deutschland) or Burghausen (Bayemets or Gascade). • Buy entry capacity from the corresponding Austrian TSO (BOG for Oberkappel, or Gas Connect Austria for Burghausen). The capacities acquired need to match in terms of volumes and timing, and in order for the shipping to be guaranteed, all of them need to be firm capacities. Any failure to obtain firm capacity in a segment of the route, with the consequent need to use at least interruptible capacity, will expose the entire route to risk of being disrupted. Imagine that, for example, the entry points from Germany are congested, and neither BOG nor Gas Connect Austria have firm capacity available for the specified time framework. In addition, this time the owner of the volumes is particularly unlucky, and it looks like no such capacity is available on the secondary market either. BOG offers interruptible at Oberkappel. The possibilities are: • Sell the volume at the German NCG, provide the Austrian counterpart with gas sourced locally at CEGH, strike two decent deals but forget about making a profit on the price differential. After all, this is exactly the reason why there is a price differential. • Buy interruptible capacity at the Austrian entry point, be lucky, and still be able to fully exploit the price differential. • Buy interruptible capacity at the Austrian entry point, be unlucky, and get interrupted for some days during the contract. During those days, sell the German volumes at NCG day ahead and provide the Austrian counterpart with local volumes sourced at CEGH day ahead, making a loss in the process. from Bulgaria into Turkey. The Greek terminal at Revithoussa is in the same situation since the entry point at Sidirokastron is not bidirectional. As for Slovakia, theoretically gas can flow from the Baumgarten hub and entry point, but before reaching Baumgarten, the hypothetical LNG landed in Spain would need to undergo the entire process described in Box 2. The complexity of the procedure implies that there is no way to implement it in a short-term framework, so it is impossible even for Slovakia to attract a spot LNG cargo landing in Spain. The experience of the 2009 gas supply crisis showed that customers on that occasion managed to substitute for missing Russian

volumes by buying short term at the German hub NCG and shipping through the Czech Republic. The point here is not that they should have been incentivized to look as far as Spain, as the cost of shipping would never have been competitive with that of a liquid hub such as NCG. But with a higher degree of interconnection, in the future, the effect of the spare LNG capacity in Spain could improve liquidity at NCG and the other central European hubs, hence mitigating the inevitable spot price spikes that occur in emergency situations such as the one of January 2009.

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Box 2: LNG from Spain to Slovakia

• In order to ship gas landed at the Bilbao LNG terminal, a shipper would first of all need to enter and exit the Spanish system operated by the TSO Enagas. • The gas must then pass through the three PEG balancing zones in France (TIGF operated by the eponymous TSO, then South and North operated by GRTGaz) to reach the German exit point at Medelsheim. • After the border crossing, the gas would be in Germany and in the pipes operated by either GRTGaz Deustschland or Open Gas Europe. • At this point, the long process already described in Box 1 needs to be completed in order to reach Austria’s eastern border at Baumgarten. As the Slovakian TSO Eustream now has physical bi-directional capacity at the Baumgarten entry point, the gas can then be shipped into Slovakia by booking the corresponding capacity. • More likely, however, the gas would be shipped through the Czech Republic (Waidhaus or Deustch Neudorf entry and Lanžhot exit) via the TSO Net4Gas. This physical shipping of gas from Spain to Slovakia is not what would happen even in a more virtually interconnected system, as there will always be different liquidity levels at different points in the network, and most likely this would lead to cheaper opportunities physically closer to the point of demand. In this case, unless the severity of the disruption drains out spot availability at hubs, continued on page 23

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continued from page 22 the spot price at NCG is likely to remain lower than that of landing a spot LNG cargo in Spain and shipping it in the byzantine way described above. But with more virtual interconnection, the costs of the two operations would influence each other, mitigating spot price spikes and therefore ultimately providing physical volumes at lower prices. Making it possible to ship gas eastbound does not automatically imply an inversion of physical flows between countries: most of the gas can be sourced through sales and purchase optimization strategies, which would reduce, but not necessarily reverse, the westbound flow of gas as long as deliveries from Russia keep steady. A company delivering LNG into Spain and interested in selling in Austria will swap the gas at the local hub AOC for gas at Baumgarten. Of course, reverse flow capacity for all pipelines is still important in order not to create a gas shortage in the East in case of Russian non-delivery. This is part of the reason why such swaps are not taking place in large volumes right now. But the other reason is the technical difficulty to offer flexibility in the Eastern European markets, a problem that could be effectively addressed by the governance improvements described here. The Needed Change and its Drivers Inverting this trend, and leaving aside physical improvement — which as has been said is important, and will improve the picture sensibly especially in terms of reaching southeastern Europe — what would be needed in the first place is the creation of cross-border capacity products, so that it does not take the whole process described in Box 2 to ship gas sourced from LNG in Spain to an end consumer in Slovakia. But cross-border capacity can only exist insofar as market rules in all the balancing areas involved are

fully streamlined. In order to span across as many TSOs and balancing zones as possible, the following harmonization measures would need to take place at least: • Capacity allocation mechanisms need to include the possibility of booking simultaneously across border points. In order for that to be possible, the minimum condition is that auction calendars are aligned or negotiated access can be done under the same application process. • Congestion management procedures need to be organized in a way that capacity booked as part of a cross-border product receives some degree of guarantee over capacity products, which can be reflected in the pricing, as it would be like buying insurance against those mismatches in capacity which current shippers have to keep in their risk considerations. • Reporting requirements toward governments, TSOs, regulators, and other institutions need to be harmonized in a way that a standard communication, at standard intervals, can be Box 3: Moving Gas Virtually from Italy to Bulgaria through an Optimization Strategy • Customer A in Bulgaria wants 1 mcm/d. • Customer B in Italy has 2 mcm/d available in Bulgaria delivered from Russia, and 1 mcm/d of LNG delivered to Italy. • Customer A buys 1 mcm/d Russian gas in Bulgaria from customer B, which serves additional customer C in Italy with 1 mcm/d LNG instead of using the physical Russian flow in exit from Bulgaria onto CEGH and then PSV, which is now only 1 mcm/d. • The process reduces the westbound flow rather than reversing it.

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What would be needed in the first place is the creation of crossborder capacity products.

Dependency on Russian Natural Gas Exports

Sources. EU27 countries: Commission Staff Working Document accompanying the proposal for a Regulation repealing EU Directive 2004/67/EC on the security of gas supply, July 16, 2007. Non-EU27 countries: U.S. Energy Information Administration, 2012

considered to satisfy all reporting compliance for all countries and TSOs that the gas is physically crossing. Reporting should also include the possibility to amend communications about gas import/exports at short notice, given the nature of today’s trading at the various European hubs, which often takes place one day ahead or even the same day for portfolio balancing purposes. • License conditions should be structured in a possibly uniform way, but most importantly, they must be structured according to the principle of proportionality. One cannot be required to acquire a portfolio of final customers in order to be able to balance itself at a hub in which it only intends to be a pure trader (this is the example of the Italian PSV). Otherwise this entry barrier will make it impossible for small players to import/export gas in a cost effective manner.

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As described in the introduction to this paper, there are a number of processes already in place at the European level in order to tackle these problems. This momentum created at the EU level on the integration of gas markets across Europe remains the most significant driver toward the harmonization of its rules, and it is promising that some TSOs are moving by their own initiative. Another important driver of change is the prospect of supply availability for member states whose supplies are currently not diversified. At present, all the countries to the east of the Baumgarten hub are more than 50 percent dependent on Russian gas, with the exception of Poland (48 percent), where the share of gas in total consumption is negligible, and Romania, where indigenous production provides diversification (although Russian gas still accounts for a significant 27 percent of consumption).

Furthermore, the sheer magnitude of the impact of U.S. shale gas on the global LNG market, and the plans for capacity expansion in the western part of Europe, should work as a driver toward more continental harmonization, leading to easier cross-border shipping. Keeping some spare capacity at regasification facilities may be seen as a securityof-supply buffer safeguard, but the efficiency loss when such spare capacity is more than 50 percent is not justifiable on these grounds. In the medium term, as shale gas is expected to express U.S. domestic gas prices well beyond 2020, even if policy-makers stay cautious on LNG exports, certainly there will be more and more diversions in the current LNG routes, releasing volumes previously earmarked for the U.S. market. In other words, long-term contract buyers will increasingly find it more economical to direct their contracted LNG cargoes somewhere else, inflating the spot market, and the obvious destinations for such volumes will be the relatively free regasification facilities in Europe. Western European gas demand is not bound to significantly increase in the next decade under pressure from various forces: • economic recession in Spain, Italy, Greece on the backdrop of the austerity measures put in place after the debt crises; • stricter environmental regulation making hydrocarbons less competitive in the electricity segment compared to low-carbon forms of generation; and • low spark spreads compared to dark spreads due to a low price of carbon emissions in the EU’s Emissions Trading Scheme. These elements combined will create an eastbound pressure for natural gas, likely to induce more and more gas consumption to shift eastwards. • Finally, price alignment among European hubs, which optimization of flows would lead to, is

another driver of change. Price alignment would be positive in systemic terms as it would create a level playing field for gas consumers throughout the continent, reducing the comparative disadvantage for gas intensive industries in those areas where gas trades at a premium. The Opposing Factors Integrating networks to effectively create links is far from a simple task. The main problem with the European gas network at present seems to be one of timing relative to the changes that are taking place in the global market. The time it will take to improve the current framework for shipping gas across the European network is likely longer than would be needed in order to reap the benefits of more gas availability in the global market. An historical shift in global gas flows is taking place right now, and as in every market, second comers will have fewer opportunities than those who were able to secure supply contracts in the first place. One of the limiting factors to harmonization is that too many and diverse initiatives are in place: ultimately, national authorities will be able to browse for their best options, and the end result will be a European market that for a long time is going to remain just as fragmented as it is today in terms of rules and requirements. One single process would be necessary, but several opposing factors prevent it from materializing: • Regulators and national governments wish to retain the right to shape their own regulations so it will take a long time to reach common calendars for auctions, regulatory deadlines, and so forth. In particular, in times of supply security concerns, countries with supply or LNG terminals will want to keep the benefits for themselves. • The large incumbents that exist in some EU countries see Europe-wide market integration as

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An historical shift in global gas flows is taking place right now, and as in every market, second comers will have fewer opportunities.

The monopoly power that is still held at many levels hinders the spontaneous development of the European gas market into a competitive playing field.

an obstacle. They have an interest in keeping the market fragmented, in order for that to remain an entry barrier for smaller players and foreign competitors, allowing for price differentials to remain in place between European hubs, hence leaving arbitrage opportunities in the hands of those larger companies that can deploy the necessary resources to face the complexities and regulatory risk of the current situation. What Direction? Market efficiency cannot be brought about by markets alone. As has been pointed out, the history of the gas sector has been one of national champions. The monopoly power that is still held at many levels, including the ownership and operatorship of gas networks, hinders the spontaneous development of the European gas market into a competitive playing field for all the actors interested in taking part in it, from producers to consumers. Policy action has so far been oriented toward correcting these sources of distortion to competition, and it went as far as mandating the unbundling of vertically integrated businesses so that the network component could be made independent of either end of the value chain. But moving from the overarching policy framework set by the three liberalization packages at EU level (1998, 2003, and 2009), down to the more specific measures that need to be implemented at the TSO and regulators level through processes most often involving initially voluntary guidelines — capacity allocation mechanisms, congestion management procedures, and so on — there is a substantial risk that the effectiveness of the overall idea gets watered down because of the ability of TSO to cherry-pick only some of the measures, moving from one lack of harmonization to just another lack of harmonization. For example, streamlining the procedures for reallocating unused capacity only works if all the TSOs decide to adhere to the

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same model. If they are left free to choose between several possible types of reallocation mechanism, a cross-border shipper will still be left with the risks from having to match two fundamentally different systems. As to the existence of large incumbents, with an interest in slowing down the integration process in order to keep positional advantages, it must be observed that even large incumbents are evolving in the increasingly liberalized European market. It has now become common to hear about this or that incumbent being forced to divest TSO assets in order to enable the full independence that TSOs ought to have. Moreover, many European companies facing limitations to their ability to integrate vertically have shifted their focus toward integrating horizontally and across borders. The result of this process is that a number of significant players, often even former state-owned incumbents, now have double-headed positions at the European level. A company that holds a majority market share at home might at the same time be wishing to enter a new foreign market, where it plays the role of the smaller importer, and faces all the related obstacles. Given the choice to either push for a more liberal regime (as it would facilitate their cross-border horizontal integration) or throw sand in the machine (as it would perpetuate their advantage at home), these companies are likely to see the potential long-term benefits of a harmonized market at European level. This is especially true given that in most cases, their home assets will not shield them completely from the movements of the EU-wide gas market, as has been made clear from the data on import dependency. Even price differentials across European hubs, which is what theoretically provides the driver for shippers to move gas around and make profits, will come to be seen as something that hinders further developments, even by the mentioned larger players. As the market becomes more and

The Future of the Global Gas Market

The real risk is that all these obstacles slow down the harmonization process in a way that easing cross-border shipping takes too long before becoming visible. Source: BG Group 2011

more liquid, and as more and more long-term gas sales agreements are benchmarked to hub prices, the gap between spot and long-term contracted prices will narrow to the point that the operational costs incurred in shipping gas from hub to hub will not be offset by the price differential, and so jeopardizing the benefit of rent-seeking attitudes from large shippers of the commodity. Rather than stopping what seems an inevitable medium- to long-term trend, the real risk is that all these obstacles slow down the harmonization process in a way that easing cross-border shipping takes too long before becoming visible. The reality of the global gas market is that new opportunities to secure long-term LNG volumes are materializing now, and investments in that sense need to be made now and not in a decade’s time. The importance of this external push to market integration is not felt enough in the policymaking arena at European or national level.

Pressure from Abroad under a Transatlantic Perspective It must not be forgotten that on one hand, LNG counts for one-sixth of total EU consumption of gas, and on the other, Europe’s LNG imports represent one-third of the global market. Such a high level of interconnection implies that the development of the European gas market will not be driven by intra-regional factors only. The emergence of a more liquid global gas market also implies global competition, and the benefits that Europe will not be able to reap, will be reaped by other players and regions. China will be a huge hub for demand in the forthcoming decades, and its gas network is undergoing a significant expansion under the pressure of demand increase, global LNG availability, and, perhaps in future years, also the potential of indigenous shale gas. The way these dynamics will develop is going to depend on the

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Developments in the U.S. domestic gas market will also be pivotal, as the former largest gas importer disappears from the demand curve and might soon start exercising its weight on the supply curve.

attitude taken by China’s political establishment in this sense, but the country will definitely play a role in shaping the global gas market. At the same time, India itself is undergoing a major scaling up of its gas network. Its geographical position makes it a perfect recipient of Asian LNG, but potentially also of U.S.-exported LNG. Asia is the largest region for the LNG market, both on the production and on the consumption side. In particular, about 55 percent of the LNG market serves end consumption in China, India, Japan, Korea, and Taiwan. And in the background of all this, the Southern Cone is slowly making its way into the gas market as well. Developments in the U.S. domestic gas market will also be pivotal, as the former largest gas importer disappears from the demand curve and might soon start exercising its weight on the supply curve. The LNG volumes typically imported in the

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United States in the last decade ranged between 12 and 20 bcm/year, representing a 5-8 percent share of the global market. These volumes are obvious targets for the LNG terminals in Western Europe, particularly Spain, which sits on 49.5 bcm regasification capacity of which only about 25 have been utilized in recent years. Pricing and not policy will obviously be the driver for Europe to secure these volumes stranded from the United States. A number of complex considerations come into play, among which are the differential with Asian gas prices and the shipping costs. Currently, a molecule of natural gas anywhere in the European system is worth four times as much as the same molecule in a U.S. pipeline. But the European price is still less than half the Asian prices, and this might divert most of the short-term LNG potential toward that region.

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Policy Recommendations

I

t is important for Europe to recognize the need to act in a timely manner in order to be able to play in the global gas market as equals with the other big players. Early positioning is important not to dominate, but even just to participate over the long run. As has been shown, the response the EU should put in place is about improving governance before infrastructure development. Cross-border shipping must be facilitated by speeding up all the processes related to the harmonization of market procedures, from the TSO and regulator level all the way up to the governmental requirements in terms of licensing and compliance. A European “shipping passport” should be envisaged, and a number of the existing processes should be managed under that umbrella, from the streamlining of license requirements and compliance (periodical reporting of lows, strategic storage, and so on) to the harmonization of capacity products, auction calendars, and all other network requirements. It must become possible for the small player to land an LNG cargo ship anywhere in the Iberian Peninsula and sell that volume in Slovakia, Poland,

or Bulgaria as necessary. Only in this way will the European market be able to use the opportunities stemming from LNG availability to address the lack of diversification of suppliers that affects most of its Eastern countries. The complexity of the measures that would be necessary in order to achieve the shipping passport might require one further step of top level legislation, a Fourth Package for the liberalization of gas markets. The development of a truly integrated liberalized market would require the streamlining of TSO market rules across the European continent, as well as the centralization of government compliance and reporting. Co-operation between TSOs in this sense is already emerging and it is a very valuable bottom-up approach to this process. But it should be acknowledged that the market itself will provide some of the drivers for this change but by no means all of them, and timing is also an important element in the equation. In this light, EU policymakers should speed up the required developments, which markets alone would take too long to implement.

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Bibliography

Alonso Suárez, Alejandro (Comisión Nacional de Energía) (2010), LNG in Spain: Key Figures and Regulatory Framework, presentation, Florence, March 26, 2010. Bahn, O. and P. Taylor (eds.) (2012), “Energy System Models & Natural Gas Strategies,” Energy Strategy Reviews, vol. 1/1, March 2012. Boersma, Tim, Safeguarding Optimal Investments in Gas Infrastructure, Transatlantic Academy, mimeo, 2012. BP (2011), Energy Outlook 2030, Statistical Review. Deloitte Center for Energy Solutions (2011), Made in America: The Economic Impact of LNG Exports from the United States. ETSO and EuroPEX (2009), Development and Implementation of a Coordinated Model for Regional and Inter-Regional Congestion Management. EU Market Observatory for Energy (2011), Key Figures, June 2011, European Commission DG ENER. Eurogas (2010), Natural Gas Demand and Supply Long Term Outlook to 2030. European Commission (2007), Inquiry into competition in gas and electricity markets, COM (2006) 851 final, January 2007. European Commission (2010), EU Energy and Transport in Figures — Statistical Pocketbook. European Commission (2011), Energy Roadmap 2050, COM(2011) 885/2. Everis and Mercados EMI (2010), From Regional Markets to a Single European Market, report presented to the ERGEG Madrid Forum on natural gas, January 15, 2010.

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Glachant, Jean-Michel and Haikel Kalfallah (2011), Conclusions of Workshop “Identifying Benefits and Allocating Costs for Cross-Border Electricity & Gas Infrastructure Projects,” European Commission DG ENER and Florence School of Regulation. International Energy Agency (2008), Development of competitive gas trading in continental Europe. International Gas Union (2010), World LNG Report. Jamasb, T. and Pollitt, M. (2007), “Incentive regulation of electricity distribution networks: Lessons of experience from Britain,” Energy Policy, 35 (12). KEMA (2009), Study on Methodologies for Gas Transmission Network Tariffs and Gas-Balancing Fees in Europe, for the European Commission, DG TREN. Lauperta, Carlos and Boaz Moselle (2002), Convergence of Non-Discriminatory Tariff and Congestion Management Systems in the European Gas Sector, The Brattle Group. Moffatt Associates (2008), Review and analysis of EU wholesale energy markets. Evaluation of factors impacting on current and future market liquidity and efficiency, study commissioned by DG TREN. Noël, Pierre (EPRG Cambridge) (2011), European Gas Supply Security, slideshow presented at CERI Sciences Po Paris, May 19, 2011. Platts, www.platts.com, natural gas spot prices 2012. Ratner, Michael (2010), Global Natural Gas: A Growing Resource, Congressional Research Service, December 2010.

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