NATURAL GAS MARKET REVIEW 2007

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Security in a globalising market to 2015

INTERNATIONAL ENE R G Y A GENCY MARKET REVIEW 2007

Security in a globalising market to 2015

INTERNATIONAL ENERGY AGENCY INTERNATIONAL ENERGY AGENCY

The International Energy Agency (IEA) is an autonomous body which was established in November 1974 within the framework of the Organisation for Economic Co-operation and Development (OECD) to implement an international energy programme. It carries out a comprehensive programme of energy co-operation among twenty-six of the OECD thirty member countries. The basic aims of the IEA are: To maintain and improve systems for coping with oil supply disruptions. To promote rational energy policies in a global context through co-operative relations with non-member countries, industry and international organisations. To operate a permanent information system on the international oil market. To improve the world’s and demand structure by developing alternative energy sources and increasing the effi ciency of energy use. To assist in the integration of environmental and energy policies. The IEA member countries are: Australia, , , Canada, , Denmark, Finland, , , Greece, , Ireland, , , Republic of Korea, Luxembourg, , New Zealand, , Portugal, , Sweden, Switzerland, , and . The Slovak Republic and are likely to become member countries in 2007/2008. The also participates in the work of the IEA.

ORGANISATION FOR ECONOMIC CO-OPERATION AND DEVELOPMENT

The OECD is a unique forum where the governments of thirty democracies work together to address the economic, social and environmental challenges of globalisation. The OECD is also at the forefront of efforts to understand and to help governments respond to new developments and concerns, such as corporate governance, the information economy and the challenges of an ageing population. The Organisation provides a setting where governments can compare policy experiences, seek answers to common problems, identify good practice and work to co-ordinate domestic and international policies. The OECD member countries are: Australia, Austria, Belgium, Canada, Czech Republic, Denmark, Finland, France, Germany, Greece, Hungary, Iceland, Ireland, Italy, Japan, Republic of Korea, Luxembourg, Mexico, Netherlands, New Zealand, Norway, Poland, Portugal, Slovak Republic, Spain, Sweden, Switzerland, Turkey, United Kingdom and United States. The European Commission takes part in the work of the OECD.

© OECD/IEA, 2007 No reproduction, copy, transmission or translation of this publication may be made without written permission. Applications should be sent to: International Energy Agency (IEA), Head of Publications Service, 9 rue de la Fédération, 75739 Paris Cedex 15, France. Natural Gas Market Review 2007 • Foreword 3

FOREWORD

In May 2005, IEA Ministers concluded that extended our time horizon out to 2015, more focus on medium-term gas markets to better refl ect the time horizons was required in order for the IEA to of the gas industry and to assess perform its prime mission: energy security. investment trends more accurately; The Natural Gas Market Review (GMR) was launched in June 2006, at the World highlighted more clearly regional Gas Congress in Amsterdam. The annual demand and supply balances, again GMR series is unique and unprecedented emphasising the role of fl exible LNG in looking at gas markets from a global supply in meeting regional demand; rather than a purely regional or national perspective. devoted much more attention to LNG, recognising that two-thirds of The GMR 2006 made some observations incremental IEA gas supply to 2015 will which are very important for energy be in this form; security, noting for the fi rst time that formerly separate regional or national gas included a section on short-term markets are globalising. Specifi cally, they energy security policies and measures, are being linked by rapidly expanding with recommendations to member shipborne LNG trade. It also found that gas governments; production from IEA member countries, which hold less than 10% of world gas published early results of our work on reserves, is either stable or in decline gas fl ows across borders to emphasize while their gas demand, notably for power that greater transparency is essential generation, is rising. Inevitably this means to providing security in gas markets; higher imports, over longer distances. summarised key regulatory develop- As well as looking at global thematic issues, ments which have a critical role in the GMR 2006 reported on disruptive providing the right balance between events in a number of distinct markets assuring protection from monopoly – proving that there is not yet one truly- abuse and encouraging much needed global gas market. Such events included investment; and the impact of hurricanes in the , shortages in Italy and the United extended and deepened our geographic Kingdom and of course the brief but coverage of trends in IEA and other widely reported interruptions of Russian countries and regions, refl ecting growing gas supplies. interdependence.

The GMR was well received by both The GMR 07 refl ects the events of the past governments and the wider energy com- year; it is written against a backdrop of high munity. For the 2007 edition, we have prices and warmer winters in the Northern kept the same format, looking at global Hemisphere that have not altered the cross-cutting issues and individual market underlying trend of gas demand growth. developments. We have also: Natural Gas Market Review 2007 • Foreword 4

In the current gas market, we see greater We trust this 2007 edition of the Natural transparency as essential – from gas Gas Market Review will be as well received reserves to investment levels, gas fl ows, as the fi rst. This book is published under pricing and regulation. We will continue my authority as Executive Director of the to work with companies and our member International Energy Agency. governments to improve information in all these areas and look forward to Claude Mandil further progress in information exchange with non member countries, both gas producers and consumers. Natural Gas Market Review 2007 • Acknowledgements 5

ACKNOWLEDGEMENTS

The Review was prepared by the Energy Valuable comments and feedback were Diversifi cation Division (EDD) of the received from within the IEA, including International Energy Agency, under the Maria Argiri, Fatih Birol, Lawrence Eagles, oversight of Noé van Hulst, director of Aad van Bohemen, Jacob Marstrand, the Offi ce for Long-Term Co-operation Maria Sicilia-Salvadores, Amos Bromhead, and Policy Analysis (LTO). The Review was Jonathan Sinton, Fabien Roques, Jolanka designed and managed by Ian Cronshaw, Fisher and Andreas Biermann. head of EDD. The lead authors were Daniel Simmons and Hiroshi Hashimoto. The Review greatly benefi ted from input and overview from the following Signifi cant contributions were made from external experts: Terence Thorn, Sybe right across the IEA, including Fausta Visser, Manfred Hafner and Gi Chul Jung, Geelhoed, Isabel Murray, Ulrik Stridbaek, the latter two under the aegis of the Brian Ricketts, Christof van Agt, Ghislaine International Gas Union (IGU). However, Keiffer, Catherine Hunter, Dagmar Graczyk, the fi nal responsibility for the Review lies Francois Nguyen and Elena Merle-Beral. with the IEA. Timely and comprehensive data from Mieke Reece, Armel Le Jeune and Erica The Review was made possible by voluntary Robin were fundamental to the Review. contributions from the Governments of Belgium, the Netherlands and the United Muriel Custodio, Rebecca Gaghen, Corinne Kingdom, plus assistance from DONG Hayworth, Tanja Kuchenbecker and Loretta Energy and Tokyo Gas. Ravera provided essential support to the Review’s production and launch. Our thanks also go to Elli Ulmer for all the copies to be sold. Bertrand Sadin deserves special mention for heroic efforts in the Review’s preparation for printing. Maps or information for the maps sourced from the Economist Limited www.petroleum-economist.com. Satellite derived imagery supplied to Petroleum Economist by NPA Satellite Mapping. Natural Gas Market Review 2007 • Table of Contents 7

TABLE OF CONTENTS

Foreword 3 Acknowledgements 5 Table of contents 7 Key messages 15 Executive summary 17 Point of departure 21

Recent events 25

North American fundamentals 25 Japan 27 Korea 30 Recent developments in Europe 32 United Kingdom supply developments 33 Algeria MOU 37 Indonesia 39 Major project decisions in 2006 40 /Belarus gas and oil negotiations 44

Investment 45

General cost infl ation 45 Upstream 47 Investment to 2015 48 Shipping 52 Transmission pipelines 53 Downstream 54 Storage 55

Regional demand & supply balance to 2015 57

Demand 57 Supply 58 Production 59 Supply and demand summary to 2015 62 Natural Gas Market Review 2007 • Table of Contents 8

Gas security 67 Recent supply disruptions in IEA countries 67 Gas storage 69 Strategic gas stocks: what are they? 73 Why do gas stocks cost so much more than oil? 74 Why are gas stocks less effective than oil stocks? 75 What are the other options besides strategic stocks? 77 Conclusion 80 Data transparency initiative 82

Developments in LNG markets 83

Overview 83 Production 88 Consuming country developments 100 Marketing, contracts and spot trade evolution 110 Peak demand, LNG terminal utilisation and seasonal storage issues 114 Coping with Indonesian shortfalls 114

Gas for power 119

Power use drives gas demand growth 119 Gas as the fuel of choice for new power plants, 2000-2004 120 Economics of gas-fi red generation 124 Gas-fi red generation capacity adds fl exibility 126

Non-OECD country/region update 129

Russian Federation 129 Islamic Republic of 142 and North Africa (MENA) 150 Central Asia 159 People’s Republic of China 163 India 167 Latin America highlights 171 Natural Gas Market Review 2007 • Table of Contents 9

OECD country/region update 179 North America 179 Republic of Korea 187 Germany 194 United Kingdom 204 Netherlands 208 Norway 213 Belgium 218 Turkey 222

European regulatory issues 231

Cross-border regulatory issues in Europe: Italian example 231 Internal regulation of gas markets in North West Europe 235

Annex A: Existing gas security measures in IEA countries/regions 251

France 251 Spain 255 Hungary 259 Directive 2004/67/EC 263

Annex B: Contractual gas fl ows involving OECD countries 265

Annex C: Abbreviations 269

Annex D: Glossary 271

Annex E: Conversion factors 275

Annex F: LNG regasifi cation terminals 277

Annex G: LNG liquefaction plants 283 Natural Gas Market Review 2007 • Table of Contents 10

List of fi gures

Figure 1 • Traditional OECD countries’ gas markets 21 Figure 2 • United States’ gas production 25 Figure 3 • Canadian gas consumption 27 Figure 4 • Increase in Japanese LNG imports driven by oil price differential 28 Figure 5 • Korea’s eighth long-term natural gas supply/demand plan (2006-2020) 30 Figure 6 • Kogas’ monthly gas sales 31 Figure 7 • New import infrastructure for the United Kingdom market 34 Figure 8 • Investment reverses the trend of increasing United Kingdom winter prices 35 Figure 9 • Northwest European exchange prices converge 36 Figure 10 • Upstream oil and gas industry investment in nominal terms and adjusted for cost infl ation 46 Figure 11 • LNG shipping fl eet capacity and crew requirement 52 Figure 12 • World reserves of natural gas (as of January 2006) 59 Figure 13 • Summary of inter-regional natural gas trade in the Reference Scenario 62 Figure 14 • OECD North America gas outlook 63 Figure 15 • OECD Europe gas outlook 64 Figure 16 • OECD Pacifi c gas outlook 64 Figure 17 • Possible LNG sales by region: one scenario 65 Figure 18 • IEA regional gas consumption and volume of commercial gas stocks by region, by type 72 Figure 19 • Physical, international fl ows for pilot countries 82 Figure 20 • Traditional and recent models of LNG business 85 Figure 21 • Expected regasifi cation import capacity by region: regas capacity is ample 86 Figure 22 • Expected LNG export capacity by region 87 Figure 23 • Australia’s LNG projects 89 Figure 24 • North West Shelf’s long-term sales commitments 90 Figure 25 • An unprecedented fl eet expansion 109 Figure 26 • Import terminals using onboard regasifi cation technology 109 Figure 27 • LNG and oil prices in Japan since 1969 111 Figure 28 • Changing focus of price negotiations 111 Figure 29 • Big drop in price expectations: NBP (National Balancing Point) in the United Kingdom 113 Figure 30 • Indonesia’s LNG sales commitments 116 Natural Gas Market Review 2007 • Table of Contents 11

Figure 31 • Electricity consumption in selected months since 2001 121 Figure 32 • OECD power generation growth 121 Figure 33 • Shares of -fi red generation in the United Kingdom were at their highest level in a decade in 2006 122 Figure 34 • Gas-fi red generation capacity and gas-fi red electricity production in OECD countries, as a share of total 123 Figure 35 • Gas prices in the USD 4-6 /MBtu range over the long term are pivotal for the economics of CCGTs 125 Figure 36 • Coal and gas-fi red generation often sets the price in competitive electricity markets and the merit order is highly dependent on coal and gas prices 126 Figure 37 • Gas-fi red power generation as share of total generation in Texas, and difference between electricity price in Texas and gas price at Henry Hub 127 Figure 38 • Russia/European pipeline trade affects global gas balance 130 Figure 39 • Gas infrastructure of Russia 133 Figure 40 • Gas price rises in selected Russian export markets 140 Figure 41 • Iran’s gas production, consumption, imports, and exports 143 Figure 42 • Iran’s gas system 146 Figure 43 • Pipelines in Central Asia 160 Figure 44 • Gas infrastructure of China 164 Figure 45 • Gas infrastructure of India 170 Figure 46 • Major South American natural gas fl ows, 1975-2005 175 Figure 47 • Gas infrastructure of South America 176 Figure 48 • United States’ gas production: has it peaked? 179 Figure 49 • United States’ coalbed and Gulf of Mexico gas production 180 Figure 50 • Canadian gas exports 183 Figure 51 • Korean gas consumption 188 Figure 52 • Korea’s projected gas demand and contract cover, 2000 to 2015 190 Figure 53 • Korea’s gas transport network 191 Figure 54 • Korea’s natural gas industry structure 192 Figure 55 • German gas transport network 199 Figure 56 • United Kingdom gas production and gross imports 205 Figure 57 • United Kingdom gas transport network 207 Figure 58 • Netherlands gas consumption 210 Figure 59 • Netherlands gas transport network 212 Figure 60 • Norway gas transport network 214 Natural Gas Market Review 2007 • Table of Contents 12

Figure 61 • Norwegian gas production 215 Figure 62 • Expected future Norwegian gas production 216 Figure 63 • Belgian gas consumption 219 Figure 64 • Belgian gas transport network 221 Figure 65 • Gas transport network in Turkey 223 Figure 66 • Turkish primary energy supply 224 Figure 67 • Turkish gas supply by source and demand by sector 224 Figure 68 • Nabucco project 229 Figure 69 • Under-utilisation of Italian import capacity 232 Figure 70 • United Kingdom gas industry organisation 236 Figure 71 • Netherlands gas industry organisation 238 Figure 72 • Norway gas industry organisation 240 Figure 73 • Belgium gas industry organisation 241 Figure 74 • Proposed organisational remedies for the merger of Suez & Gaz de France 250 Figure 75 • France’s gas sources 251 Figure 76 • France’s gas entry points 252 Figure 77 • France’s transportation and storage system 254 Figure 78 • Spain’s gas sources 255 Figure 79 • Spain’s transportation and storage infrastructure 257 Figure 80 • Hungary’s gas sources 260 Figure 81 • Hungary’s transportation and storage system 262 Figure 82 • Gas fl ows based on 2005 IEA data - North America 265 Figure 83 • Gas fl ows based on 2005 IEA data - Asia Pacifi c 266 Figure 84 • Gas fl ows based on 2005 IEA data - Europe 267

List of tables

Table 1 • Combined share of Russia and Algeria in Europe 36 Table 2 • Shtokman, status 40 Table 3 • Sakhalin II, status 42 Table 4 • Global GTL projects 43 Table 5 • Selected global LNG projects 49 Table 6 • World primary natural gas demand in the Reference Scenario (bcm) 57 Table 7 • World fi nal gas consumption (bcm) 58 Natural Gas Market Review 2007 • Table of Contents 13

Table 8 • World natural gas production in the Reference Scenario (bcm) 60 Table 9 • Countries and regions involved in international LNG trades 85 Table 10 • Australian LNG export project interests 92 Table 11 • ’s LNG projects: traditional and mega trains 94 Table 12 • Sakhalin I & II projects 98 Table 13 • Gazprom’s spot LNG deals 99 Table 14 • North American LNG receiving terminals already available & under construction 101 Table 15 • LNG terminals in the United Kingdom 102 Table 16 • LNG terminals in Belgium 103 Table 17 • LNG terminals in France 104 Table 18 • LNG terminals in the Netherlands 104 Table 19 • LNG terminals in Spain 105 Table 20 • LNG terminals in Italy 105 Table 21 • LNG terminal regasifi cation/storage capacity utilisation (2005) 114 Table 22 • Increase in from gas in selected IEA member countries 120 Table 23 • Investments in transit-avoidance pipelines 138 Table 24 • Iran’s pipeline export projects 147 Table 25 • Iran’s LNG projects 149 Table 26 • MENA natural gas export projects to 2015 151 Table 27 • Reported domestic gas feedstock prices in selected MENA countries 157 Table 28 • China’s domestic pipeline plans 167 Table 29 • Korea’s consumption of natural gas by sector, 1990 to 2004 188 Table 30 • Korea’s LNG imports by source, 2001 to 2005 189 Table 31 • Korea’s annual natural gas demand outlook, 2006 to 2020 194 Table 32 • German domestic trunk pipelines 196 Table 33 • New German storage capacity (planned or under construction) 201 Table 34 • Existing underground gas storage in France 253 Table 35 • Major new and expansion storage projects in France 253 Table 36 • LNG terminals in Spain and expansion plans 256 Table 37 • Underground gas storage in Spain 258 Table 38 • Entry capacity of the gas system in Hungary 261 Table 39 • Underground gas storage in Hungary 263 Natural Gas Market Review 2007 • Table of Contents 14

Table 40 • Conversion factors for natural gas volume 275 Table 41 • Conversion factors for natural gas price 275 Table 42 • LNG regasifi cation terminals 277 Table 43 • LNG liquefaction plants 283

List of boxes

Box 1 • Gas agreement of 31 December 2006 44 Box 2 • LNG vs pipeline gas investment 51 Box 3 • Fuel switching in Russia during extreme cold 141 Box 4 • Central Asia’s eastern ambitions 161 Box 5 • Nabucco 228 Natural Gas Market Review 2007 • Key Messages 15

KEY MESSAGES

Natural gas is becoming an Gas security is visibly deteriorating 1 increasingly global commodity; 6 in IEA member countries. In the developments in previously separate sshorthort tterm,erm governments need to regional gas markets can no longer be elaborate gas emergency policies, and considered in isolation. evaluate them in an international context.

To 2015, investment is a more Short-term emergency policies 2 serious concern than identifi ed in the 7 need to be based on a suite of Natural Gas Market Review 2006. Current measures, which might include strategic bottlenecks in uupstreampstream production and storage in the right circumstances, but LNG liquefaction capacity are tightening. such storage is not “the silver bullet” for gas security. Continuing regulatory uncertainty 3 is the primary factor slowing In the llongeronger tterm,erm gas security ddownstreamownstream investment, especially in 8 will be served by more effi cient gas IEA Europe, in both national and production and use; more investment; international pipelines, as well as storage. improved domestic market designs; increased transparency of fl ows and A year of generally mild winter investments; and diversifi cation of energy 4 weather in 2006 reduced gas sources, suppliers and supply routes. demand in IEA countries, disguising the underlying trend of very tight markets. Despite a mild 2006, gas remains 9 vulnerable and expensive. Gas demand for power generation 5 is still strong, growing in the United States by 6.5% in 2006. Policy uncertainty is slowing a revival of coal-fi red and , despite extensive plans.

Natural Gas Market Review 2007 • Executive Summary 17

EXECUTIVE SUMMARY

Gas goes global By 2015, LNG is set to provide almost a quarter of OECD gas demand, but will Total gas output in IEA countries is contribute relatively little to non-OECD falling, while demand is rising. IEA energy demand. Despite the traditionally countries are becoming more dependent slow pace of developments in LNG on inter regional trade, with this trend markets, the business is changing rapidly. most marked in Europe. While the North Newly-negotiated and recently-renewed American region has traditionally been long-term contracts are responding to the concerned with pipeline gas, and the effects of globalisation seen in the more Pacifi c market with LNG, neither can now price responsive short-term LNG market. afford to ignore the global picture. North The rapid growth in LNG use and its greater America is preparing to import LNG from fl exibility is already beginning to create both Pacifi c and Atlantic producers, while a global market for gas. This process has Pacifi c consumers have sharply increased accelerated over the last year, compared LNG imports from Atlantic markets as to expectations of the GMR 2006. some traditional Pacifi c suppliers have been unable to meet contracted demand. Due to its liquidity and depth, the North IEA Europe will import increasingly large American market has provided the “price volumes of both LNG and pipeline gas, to beat” for the increasing volumes of so what happens in this region is of price-sensitive LNG cargoes. Nevertheless, paramount importance to all regions of LNG importers in the Pacifi c and European the world. If investment in pipeline gas regions remain able to outbid the United does not develop as anticipated, (and States in order to secure incremental there is cause for concern in this regard) supplies due primarily to differences in pressure on both the Atlantic and Pacifi c domestic market structure. The United LNG markets will increase. States price (usually indicated by the Henry Hub) therefore seems to be setting a fl oor LNG production capacity is growing, from price for price-sensitive LNG. During periods 240 bcm in 2005 to 360 bcm by 2010 (in in 2006, a correlation between Henry Hub line with the 2006 Natural Gas Market and prices in the United Kingdom became Review, GMR 2006) and, by 2015 to apparent, whilst some long-term LNG 470 bcm, potentially as high as 600 bcm, supply contracts are now indexed to the but capacity increases after 2010-12 Henry Hub. depend critically on new projects being sanctioned soon. Regasifi cation capacity is Investment outlook worsens growing rapidly, although some countries and regions need to improve competitive Investment in the gas sector is a serious cause forces in their domestic markets if they for concern, having worsened in comparison are to take advantage of the diversity to the GMR 2006. Current upstream inves- provided by LNG. tment to 2015 is considerably below the amount required, with particular weakness in several regions. Gas investments every- where are suffering higher costs and Natural Gas Market Review 2007 • Executive Summary 18

construction delays, in keeping with energy borders must be crossed. Within many investments generally, although proposed jurisdictions, regulatory uncertainty is LNG projects seem especially affected. slowing investment. A selection of these LNG projects shows production delays averaging almost a year, Storage investment seems to be lagging with average cost overruns of more than substantially in IEA Europe, but progressing USD 2 billion per project. Furthermore, only well in IEA North America. Investment in one major new LNG liquefaction project has downstream transportation and distri- been sanctioned in more than a year and bution networks is also behind, particularly a half, a marked slowdown compared to in the IEA European region. previous years. Reports pointing towards the formation of a gas producers’ association, Investment in LNG shipping is running analogous to OPEC, will do little to improve ahead of requirements through to 2015, this situation. but this additional capacity will add necessary increased fl exibility to the LNG The global demand for raw materials and industry. Similarly strong investment is talent has pushed up costs (dramatically in occurring in regasifi cation capacity within some cases) and reduced the effectiveness each IEA region which will also contribute of each investment dollar spent compared to fl exibility, although in Europe many to the situation reported in the GMR 2006. new terminals are yet to be sanctioned As well as affecting existing projects, and geographical imbalances persist. increasing costs have been blamed for the postponement and cancellation of Gas demand drops in 2006, signifi cant new developments worldwide. but gas remains expensive At the same time, the companies with the skills to deliver these increasingly complex An unusually mild winter in 2006 had a projects are seeing reduced access to strong dampening impact on gas demand reserves. Encouraging production in IEA for residential use worldwide. In North countries, in particular a renewed focus America and North West Europe, prices on producing from “fallow” (economic but responded to the decrease in residential undeveloped) fi elds, could help take some demand and consequent record inventory of the pressure off non-IEA investment in levels by falling well below expectations in the short to medium term. the GMR 2006. Prices have been below oil parity, resulting in increased substitution There is a distinct defi cit of new long away from oil products in stationary distance pipeline investment in the period applications. A similar substitution effect to 2015, noting that investments in has occurred in Japan and Korea for different transportation over increasing distances reasons. In the majority of IEA European show a distinct preference for LNG. countries, gas prices remained relatively Regulatory uncertainty and NIMBY (“not static, refl ecting their link to oil prices. in my backyard”) issues continue to slow investment in downstream pipeline and other infrastructure, especially when Natural Gas Market Review 2007 • Executive Summary 19

In the medium term, forecasts of tight of gas and electricity is raising concerns supply underpin high gas price expectations. about security, reliability and competition Gas demand growth looks set to remain because gas increasingly meets electricity strong, although a little weaker than in the demand peaks, notably in summer, where GMR 2006, refl ecting these expectations as an increasing number of IEA countries well as increased concern over security of are experiencing peak power demand. In supply. Overall, gas prices in all IEA regions many regions, gas-fi red plant sets the price are still considerably higher than the level of electricity a signifi cant proportion of of USD 4/MBtu or below, which were seen the time. Expensive gas therefore means as recently as 2002. Prices in 2006 ranged expensive electricity. For these and many from USD 6.50/MBtu in North America, other reasons, policy makers must appreciate USD 7/MBtu in Japan, USD 7.40/MBtu in the growing intertwining of gas and the United Kingdom, and USD 8.30/MBtu electricity industries, and design markets at the German border. Gas is cheaper than and regulatory systems accordingly. oil, but expensive when compared with coal. Gas security is deteriorating

Gas-fi red power demand stays strong The GMR 2006 highlighted the growing dependence of IEA countries on gas Gas-fi red power remains the default option imports. The situation has continued to for new power generation. In Europe, deteriorate over 2006, only alleviated almost two-thirds of new electricity plant by weakening demand from mild under construction is gas-fi red. In North weather. There is concern about the America, the proportion is half. Demand rate of development of gas reserves for new gas-fi red power generation in countries as diverse as Russia, Iran, capacity continues to grow as political Indonesia, and Bolivia. Moves towards a commitments in some countries to avoid “Gas OPEC” will raise concerns further. or phase out nuclear and reduce carbon At the same time, more gas is being emissions have left gas as the default transported over increasing distances option. Uncertainty over climate change in a more uncertain world. Hence the policy is slowing investment in new coal- overall risk to gas supplies is growing. fi red plant in Europe and to a lesser extent, This heightens the need for short-term North America. and long-term gas security measures. Gas emergency policies are needed to deal There are large numbers of new coal and with short-term gas supply disruptions, nuclear plants planned, but construction while longer-term policies are required needs to start soon if new plant is to be to ensure suffi cient investment as well operational before 2015. Renewables can- as increased diversity of suppliers, supply not fi ll the gap in this timeframe; to the routes and energy sources, especially in contrary, increasing shares of intermittent the electricity sector. renewables such as wind may increase the need for fl exible gas-fi red power as back-up. The growing interdependence Natural Gas Market Review 2007 • Executive Summary 20

The increasing links between gas and of supply, competitive pricing and rational electricity offer both a threat and an response in crises. Governments, especially opportunity regarding energy security. in Europe, need to step up their efforts Effi cient gas and power markets tend to to ensure such markets develop and are reduce gas demand as prices increase, maintained. Long term security is dependent saving gas at times of high demand or on adequate and timely investment across low supply. In addition, some gas-fi red the board in production, transport, pipelines equipment can continue to operate but and distribution. Ensuring that gas is used switch fuel, reducing gas demand at the effi ciently is paramount; the Alternative expense of oil. In addition, government- Energy Scenario set out in the World Energy sponsored measures to save electricity Outlook 2006 estimates that strong policy “in a hurry” can be used to reduce power action to improve energy effi ciency and consumption, and hence gas demand, in promote low carbon alternatives can reduce the event of a shortage. global gas demand by between 4% and 5% in 2015, an amount equal to Russia’s current Consuming countries need to upgrade gas gas exports to IEA countries. emergency policies to cope with possible supply disruptions. Strategic storage is The world “dodged a bullet” in 2006 but one method of addressing specifi c security gas remains vulnerable and expensive concerns. However, the high costs and limitations of strategic storage need to be A very mild winter in 2006 and in some well understood and their development and regions 2007 took signifi cant pressure possible deployment should not undermine off gas demand in what was becoming a commercial storage investment. A suite strong suppliers’ market. This should not of measures to address general security lure decision makers into a false sense issues can be much more effective and of security. Supplies remain tight, and effi cient than storage alone. Such measures new projects under development are could take into account fuel-switching, subject to rising costs and increasing interruptible contracts, demand restraint delays. A return to more normal winter and storage where good sites are available. conditions in consuming countries will Growing globalisation in gas markets and put strong pressure on gas supplies. expansion of electricity markets means Colder-than-normal weather in the winter that it is increasingly necessary to check (or indeed hotter weather in the summer) the international interdependency of could quickly see supply diffi culties re- policies and market responses, particularly emerge in some areas. There are very real in a situation where they might be applied concerns that upstream investments and simultaneously. Possible impacts of national long distance pipelines will not develop measures on wider oil and electricity quickly enough to meet growing demand, markets need to be assessed. especially if power generation investment continues to favour gas. In the longer term, open, transparent and fully functioning markets with strong cross-border links, offer important benefi ts in security Natural Gas Market Review 2007 • Point of Departure 21

POINT OF DEPARTURE

The authors recognise that recent atten- balance. In the latter group, Middle East tion on natural gas will attract readers and North African countries dominate; with various backgrounds ranging from gas plays only a small part in meeting the policy makers to industry experts, from rapid growth in energy needs of China regional consumers to global strategists, and India. from energy specialists to students and the interested general public. Bearing Gas has tended to be used in the region in mind this diversity of readership, the where it is produced because of relatively following section has been included to high transport costs; less than one-sixth provide the general fundamentals of the of demand is met by inter-regional trade. natural gas industry. Interested readers As production in OECD countries plateaus are also advised to benefi t from earlier IEA or declines, trade will become a more publications. important feature of this market and hitherto regional markets will interact Natural gas provides about 20% of global more strongly with each other. energy supply, in a range of generally sta- tionary uses, including industrial process heat, residential and commercial space Three regions dominate and water heating, as well as, increasingly, natural gas trade power production. Gas use for power has more than doubled in the OECD over the last fi fteen years. OECD countries account Natural gas is used around the world but for 52% of gas use, transition economies, the major areas of trade correspond to especially Russia, use about 23%, with the OECD regions: North America, Europe developing countries accounting for the and Asia-Pacifi c.

Figure 1 Traditional OECD countries’ gas markets Natural Gas Market Review 2007 • Point of Departure 22

North America has been largely self- prime example. Gas provides a quarter of suffi cient, with Canada being an important IEA Europe’s primary energy supply. exporter of natural gas to the United States. About one-sixth of the gas used The Asian gas industry has developed from in the United States, the world’s largest the 1970s, as Liquefi ed Natural Gas (LNG) gas user, comes from Canada. Gas prices became available as a means to import gas in this market are set through gas-to-gas from Malaysia, Brunei, Indonesia, Australia competition, meaning that in times of and the Middle East. Japan and Korea are oversupply, prices will be low and in times almost entirely dependent on LNG imports of tight supply, prices will be high. Prices for their gas supplies and gas is a relatively can and have been quite volatile, especially smaller proportion of the total energy in recent years. At times of high prices, it supply of Asia-Pacifi c (14%), although gas is up to the consumer whether to continue is quite important in the Japanese power paying, to reduce gas use or switch to sector. Gas prices are linked to oil in Japan other fuels. Gas accounts for nearly 23% of and Korea, but with a formula that differs primary energy supply in North America. from that of European gas users, so that at current oil prices, gas is cheaper than oil. IEA Europe is partly self-suffi cient but In Australia and New Zealand prices are set relies for more than 40% of its gas supplies by gas-on-gas or gas-on-coal competition. on imports, mainly from the former Soviet Union (about 23% of supplies from Russia, the world’s largest gas producer and Gas is transported through exporter) and Algeria. Intra-regional trade pipelines and as LNG is also important, with Norwegian exports increasing and Netherlands and United Kingdom both exporting and importing There are two principal ways of transporting though the UK has been a net importer gas from the production source to the market: since 2004. Generally the gas price in through pipelines or in the form of LNG. Both Continental Europe is directly linked to are capital-intensive, with long construction the price of oil. Hence gas prices will go times and therefore a considerable period is up when the price of oil rises, irrespective needed to pay back the initial investment. of whether or not the supply of gas is Pipelines are more cost-effective over short tight. This also means prices have been distances. They do however tie the consumer generally higher than North American to the supplier which creates a negotiating prices in recent years. Customers are less position which sometimes favours the likely to adjust their demand since they do supplier and sometimes the consumer, but not receive timely or necessarily relevant always involves a certain amount of trust. price signals. On the other hand, suppliers Customers can however be reasonably sure are perceived to be less able to manipulate that gas keeps fl owing as long as they pay prices. Certain countries in Europe are the right prices and the gas resource is now moving towards the North American adequate, since it is generally in all parties’ system although at various speeds, with interests to keep an expensive pipeline fully the North West European market as a utilised. Natural Gas Market Review 2007 • Point of Departure 23

Liquefi ed Natural Gas (LNG) is natural gas be considered to be fl exible; pipelines that has been cooled down to -160°C to do not offer the same ability to market make it liquid. This is done in a liquefaction to different destinations. The cost of train, a series of process operations from production of LNG is now low enough gas to LNG. Often a liquefaction plant to be competitive in most parts of the starts with one or two units (“trains”). world. A few liquefaction plants have now Once these trains have proven successful, started to supply all three OECD regions, both technically and commercially, more plus emerging markets; that is, they are trains can be added at lower marginal marketing on a global basis. Competition cost (“brownfi eld expansion”) if the gas for the approximately 10 to 12% of un- resources are suffi cient. After liquefaction, contracted production (“spot cargoes”) is the gas is transported in specially designed on a global scale. Since LNG is the marginal ships. At the point of arrival the liquid is supplier in some markets it means that heated to return it to a gaseous state in regional markets are beginning to be a regasifi cation terminal. LNG technology exposed to each other. The previously allows the development of large so-called regionalised gas markets are interacting “stranded” gas reserves that are often more strongly at a global level through remote from major markets. High capital both physical and price interactions, with costs associated with LNG production and important implications for change in the transport have encouraged a business model structures of gas consuming markets. based on long-term, (typically 20 years) take- or-pay purchase obligations, agreed well in advance of plant construction (typically Gas consumption 5 years before fi rst production). While still the rule, this model is beginning to As noted above, natural gas is used mostly be modifi ed. More fl exible, shorter term by three sectors: Residential and commer- sales, such as seen in the oil trade, are now cial consumers, industrial consumers and becoming much more commonplace. LNG power generation companies. has been essential for the development of gas use in Japan and Korea and its use is The residential and commercial sector now growing in the rest of the OECD. The uses gas for heating, cooking, hot water last fi ve years have seen LNG production and to a limited extent cooling. Since grow by about 50%, with growth set to heating uses most gas, demand is heavily continue at this rate to at least the end of reliant on weather conditions, but is the decade. More than 90% of output is otherwise relatively predictable. In some destined for OECD markets. countries gas consumption in this sector can be several times higher in winter than Since the LNG ships are relatively free to in summer. Residential users often have determine their destination, it is easier no or little alternative over the short-to- for LNG to end up in the market which medium term and are therefore called offers the highest price, even when it was “captive”. Since residential consumers are originally contracted to another market. only periodically confronted with their By 2015, some 25% of LNG output could energy bill, it is diffi cult for them to react Natural Gas Market Review 2007 • Point of Departure 24

to short-term price changes. They can and generation. Gas use in the power sector has do however react to continuing periods of grown from one fi fth of IEA gas demand to high prices e.g., by adjusting their energy nearly one third since 1990. However, the effi ciency. price of gas can be a disadvantage to power companies, compared to the low marginal Industrial consumers use gas for heating, costs of sources such as nuclear or coal. This for melting, as feedstock, or sometimes disadvantage can be offset if electricity to drive their own small power plants. Gas prices are high enough; the difference demand in this sector is relatively stable and between gas and electricity prices is called dependent on process parameters. Some the “spark spread”. Gas is particularly suited industrial users can change to other fuels; to meeting peak power demand, such as air all can optimise their energy effi ciency. It is conditioning demand on hot days, or as a not uncommon that industrial consumers supplement to intermittent sources, such which are directly exposed to high energy as . Gas and electricity markets prices reduce gas demand by decreasing or are therefore increasingly interacting, stopping the production of their goods, or which is particularly apparent in liberalised moving production to locations where gas markets. is cheaper.

Apart from gas, the power sector uses Units coal, uranium, oil and hydro and other renewables to produce electricity. Gas has The three regions have traditionally a variety of operational, commercial, and developed different units to measure environmental benefi ts, not the least being quantities, prices and energy fl ows. In a greenhouse gas emissions signature this report the following units are used as about half that of coal in newer plant. The much as possible: for volumes billion cubic development of the combined cycle gas meters (bcm); for prices United States turbine (CCGT) has been a technological and Dollars (USD); for energy content: Million economic breakthrough, with effi ciencies British thermal units (MBtu). Wherever of gas fi red power increased to almost 60% possible, alternative units are given in – the highest effi ciency of any thermal brackets. Natural Gas Market Review 2007 • Recent Events 25

RECENT EVENTS

North American fundamentals North American market is starting to see a strong power demand peak in the summer After a record 2005 hurricane season on the – the summer of 2006 saw two consecutive United States’ Gulf Coast, two warm winters weeks of natural gas withdrawals in late have seen gas demand fall dramatically. July and early August for power generation Demand in the industrial sector was to run air conditioning units. These were affected fi rst, but residential users also the fi rst-ever large scale withdrawals from reacted to higher prices, albeit with a time storage during summer. delay. Production recovered from 2005, leading to record stocks and depressing Though natural gas prices are well below prices dramatically from the expectations the 2005 peak price of USD 15/MBtu, they of late 2005. A return to more normal cold are well above the 2002 price range of conditions in early 2007 has seen demand USD 3 - 4/MBtu, averaging USD 6.40/MBtu in increase, and a record amount of natural gas 2006. According to the Energy Information was withdrawn from storage in February administration (EIA), the benchmark Henry 2007, but stocks still remain slightly above Hub natural gas price is projected to the fi ve-year average. average between USD 7 - 8/MBtu in 2007 and 2008. This is predominantly due to While gas demand for industrial and infl ationary pressures of a tight market for domestic use has fallen, gas use for both rigs and skilled labour increasing the electricity generation continued to grow, cost of drilling. North America is also ex- increasing 6.5% year on year in 2006. The periencing declining production in some

Figure 2 United States’ gas production

570

bcm 560

550

540

530

520

510

500

490 2000 2001 2002 2003 2004 2005 2006

Source: EIA data. Natural Gas Market Review 2007 • Recent Events 26

mature regions, particularly in the Although LNG imports declined again in offshore Gulf of Mexico which appears to 2006, most observers predict a more rapid be mimicking the faster-than-expected increase in LNG imports in the future decline of gas production in the . than projected a year ago. Regasifi cation capacity will be adequate as 12 terminals There is a strong correlation between gas with 150 bcm of capacity will be in prices in the United States and the number place by 2012 (25% of 2005 demand). of wells drilled to explore and produce more The geographic concentration of these gas. Since 2002, the number of natural gas terminals may however be an issue wells drilled annually in the United States because most of the terminals are being has increased by 90% to an estimated built in the Gulf of Mexico. However, 32 000 drilled in 2006. The situation is much a substantial network of pipelines and the same in Canada, with the number of storage fi elds required to move regasifi ed new wells doubling to an estimated 17 700 LNG from terminals to market are already in 2006. in place for these terminals.

Despite record gas drilling in the United During the next 10 years, the underlying States, production remains essentially use of natural gas to generate electricity fl at. However continued expansion of is likely to continue to increase. New gas unconventional production may be plants are increasingly being used for suffi cient to hold the United States’ base-load generation (at all hours) rather production at constant levels or even than just to supply peak demand at only expand production modestly for several certain times of the day. This means that more years. Nevertheless, with fewer utilisation rates of installed gas capacity natural gas reserves being added for are expected to steadily increase from every dollar spent on exploration and the 35% observed in 2006. By burning gas production, higher gas prices are needed in underused plants, the United States to maintain production. These same will be able to increase power generation high prices make LNG more attractive, output without investing in new plant. exposing the North American market to global supply and demand trends and to Estimates of likely gas demand in the power some extent vice versa. sector are highly dependent on progress in new coal build. About 10 GW of new coal The United States natural gas prices have plant is under construction, with much remained high enough to keep large more planned. Progress on the latter may infrastructure projects such as Mackenzie be affected by uncertainty over climate Valley and Alaskan North Slope pipelines change policy, as in other IEA countries. alive. High prices increase the value of the gas in the market-place making the In Mexico, already facing natural gas projects more attractive; however project shortages due to lack of investment, the cost increases driven by raw materials virtual collapse at Cantarell – the world’s and labour cost infl ation have tended to second-biggest oil fi eld in terms of output counteract this. –at the start of 2006 will raise the pressure Natural Gas Market Review 2007 • Recent Events 27

Figure 3 Canadian gas consumption

bcm 100

95

90

85

80 2000 2001 2002 2003 2004 2005 2006

Source: IEA data. on Mexico’s new President Calderon to and demand trends in the rest of the world, open the country’s closed energy market communicated through the LNG market. to foreign investors. In the absence of a turnaround in the hydrocarbon sector, gas imports look set to rise. Japan

Canadian gas demand continues to grow as oil-sands projects start up, see Figure New policy emphasising security 3. These projects are major users of gas for the process of steam-assisted-gravity- In May 2006, Japan’s Ministry of Economy, drainage which essentially heats the oil Trade and Industry (METI) made public the sands deposits in-situ so that they fl ow into country’s New National Energy Strategy, wells. Although Canadian gas production which has energy security as its core. The is projected to increase, exports of gas policy provides numerical targets in: 1) to the United States will fall as domestic energy conservation; 2) reduction of the demand grows. share of oil in the primary energy mix; 3) reduction of the share of oil in the transport As overall demand in North America grows sector; 4) development of nuclear power; rapidly, production is not projected to keep and 5) ratio of oil developed by Japanese pace. The North American market is set to companies. Those numerical targets were receive increasing volumes of gas from a clear message of the country’s energy abroad. The United States and Canada will security concerns in the wake of changing increasingly be infl uenced by gas supply dynamics of the Pacifi c energy market. Natural Gas Market Review 2007 • Recent Events 28

Procurement activities are recent price differential by converting to at high levels natural gas. This has driven LNG demand growth at the expense of oil. LNG imports Japanese companies are busy procuring to Japan under long-term contracts were LNG for short-term supplies until 2010 to over USD 4/MBtu cheaper than JCC oil meet a sharp gas demand increase caused prices (Japan Crude Cocktail, the average by fuel switching in the industrial sector price of crude oil imported into Japan) in as well as power generation demand 2006. This price gap fi rst appeared in 2002 resulting from nuclear problems. Supply and has widened since, as can be seen from defi cit concerns are being felt because Figure 4 (note that the spike in gas demand of some possible project delays. The in 2003 was caused by increased gas-fi red S-Curve formula, under which many import power generation which substituted for contracts operate, keeps gas and oil prices nuclear generation). in line within a “normal oil price” range, e.g. USD 16/bbl to USD 24/bbl. Outside this Major recent developments in range, gas prices respond more slowly to procurement activities oil prices, meaning that at USD 60/bbl oil, gas is substantially cheaper than oil per The fi rst Australian North West Shelf unit of energy. contracts that started in 1989 are set to expire in March 2009. The contracts involved Industrial customers who were still using eight Japanese foundation buyers for a total oil-based fuels have responded to the of 10 bcm per year (7.33 mtpa). Renewal

Figure 4 Increase in Japanese LNG imports driven by oil price differential

88 10

86 9

ts (bcm) 84 8

82 7

LNG impor 80 6

78 5

76 4

74 3 LNG discount to oil price (USD/Mbtu)

72 2

70 1

68 0 2000 2001 2002 2003 2004 2005 2006 LNG imports (LHS) LNG price discount to oil (RHS)

Source: IEA data. Natural Gas Market Review 2007 • Recent Events 29

deals are being negotiated between the buyers are eager to see the 2008 start of sellers’ consortium and the individual LNG delivery as currently anticipated. buyers, rather than the buyers’ consortium as was the case for the original contracts. Some Japanese gas and electric power The renewals are also being negotiated at companies are negotiating with Qatar for reduced volumes for most of the buyers – at long-term supplies from the Middle East a total of 7 bcm per year (5.13 mtpa). They producer’s mega-trains, originally planned have shorter durations and possibly higher to supply LNG to the United Kingdom and pricing arrangements. United States markets. These volumes may be available in the short term as Two contracts between Indonesia’s prices at NBP in particular are lower than Pertamina and six buyers in western Japan, expected. amounting to 16.3 bcm per year (12 mtpa) and representing 20% of Japanese LNG Warmer than average winter consumption, are expiring in 2010 and 2011. Although the two sides agreed in Much of Japan had higher-than-normal principle to renew half of the volume in temperatures in the winter of 2006-07. The 2005, no fi nal agreement has been reached warm winter weather slowed down LNG yet. Now at least 4.1 bcm per year (3 mtpa), consumption in Japan in the residential and potentially as much as 8.2 bcm per year and commercial sectors, counteracting to (6 mtpa), is expected to be renewed. This issue some extent the increases in industrial and was also on the agenda of intergovernmental power use. National gas use in 2006 grew talks when the Indonesian president visited by 7.2%, mostly driven by a strong increase Japan in November 2006. of 13% in industrial sector consumption, requiring the import of 86 bcm (62 million Nine Japanese gas and power companies tonnes) of LNG. have contracted to purchase 6.7 bcm per year (4.94 mtpa) of LNG from the Sakhalin Despite the relatively warm winter and II venture in Russia’s Pacifi c region. Two of consequent low demand for domestic the buyers expected to receive cargoes heating, last quarter 2006 gas use seems from 2007 having reached agreements to be increasing by some 14% year on with the venture in 2003. But when year. In December 2006, Japan imported Shell, then majority owner of the project 7.3 bcm (5.33 million tonnes) of LNG, up company, announced doubling of the 10.3% from a year ago. This was partly project cost in summer 2005, it was also due to the ongoing substitution of gas in revealed that the commencement of the industrial applications, and partly because project would be delayed to 2008. After power utilities consumed more LNG to 18 months of controversy over the cost cover for nuclear generation which was increases and revenue sharing, alleged scaled back. environmental violations, and Gazprom participation, the foreign partners agreed to hand over a majority stake to the giant Russian gas company. The Japanese Natural Gas Market Review 2007 • Recent Events 30

Korea 3.5% through 2020, to 45.6 bcm in 2015 and 54.9 bcm in 2020. Gas distribution for Korea’s gas demand has been growing at residential, commercial, and industrial use 9% per year since 2000 and the country is forecast to grow at 5.4% a year, while seems to be facing a looming supply gap. the power sector consumption is forecast Korea Gas Corporation (Kogas) forecasts a to remain fl at at 2006 levels. Power demand shortfall of between 7.5 and 8.2 bcm per growth is expected to be met increasingly year (5.5 - 6.0 mtpa) in 2011 or 2012, which through nuclear power expansion. could prove conservative. Actual imports increased 55% from 19.9 bcm (14.6 million Kogas is trying to secure two long-term tonnes) in 2000 to 30.7 bcm (22.6 million supply deals from Qatar, totalling 5.7 bcm tonnes) in 2005. In 2006, demand grew by per year (4.2 mtpa). The fi rst one started 13.4%, to 34.8 bcm (25.6 million tonnes). delivery in 2007 and the other is expected to begin in 2009. These deals are the In December 2006, Ministry of Commerce, fi rst long-term supply deals signed since Industry and Energy (MOCIE) announced the re-instatement of Kogas’ status as the country’s Eighth Long-Term natural “quasi-monopoly buyer” in the summer gas Supply/Demand Plan, for 2006-2020. of 2006. This re-instatement of Kogas’ According to the plan, LNG consumption is status temporarily reverses decisions by expected to grow at an average annual rate of the government in 1998 to increasingly

Figure 5 Korea’s eighth long-term natural gas supply/demand plan (2006-2020)

bcm 50

40

30

20

10

0 2006 2007 2011 2015 2020 Power Residential, commercial & industrial gas

Source: MOCIE. Natural Gas Market Review 2007 • Recent Events 31

allow private companies to bypass Kogas While Kogas has some “winter-weighted” and directly import LNG only for their contracts which deliver lower volumes of own consumption. Only two companies, gas in the summer, storage continues to Posco and K Power have started importing be useful in meeting seasonality. LNG directly. A third, GS-Caltex also has permission but has not yet started Volatile LNG market in 2006 receiving LNG deliveries. Sales growth in the fi rst half of 2006 In addition to the high year-on-year came from stronger demand in the power demand growth, seasonal differences sector, leading to a demand surge of 10% in consumption are another important compared with the same period in 2005. issue in Korea. Winter peak gas demand is However, in the latter half of 2006, sales up to 3 times summer consumption due declined by 5% compared to 2005. Kogas’ to demand for space heating. In order to sales declined by 10% in the last quarter in handle seasonal fl uctuations, Kogas plans 2006 compared to the same period in 2005 to increase LNG storage capacity by 69% as demand was dampened by warmer- from 2007 to 2013 (to 8 240 000 m3). Kogas than-usual weather conditions. Despite has also signed an initial deal with ’s the fact that the company’s LNG imports state gas company to build and operate for the year increased by 10% to 33.1 bcm two 200 000 m3 tanks in the Sultanate. (24.3 million tonnes), the company’s gas

Figure 6 Kogas’ monthly gas sales

2.5

bcm

2.0

1.5

1.0

0.5

0 1 234567 8910 11 12 2006 2005

Source: MOCIE. Natural Gas Market Review 2007 • Recent Events 32

sales for all of 2006 rose by only 2.8% “gas market opening” in July 2007, when from 2005 to 32 bcm (23.5 million tonnes) the vast majority of domestic customers leading to an increase in end of year in the 450 million person trading zone storage volumes. become eligible to switch suppliers. It is however clear from the reports below that Power generators bought 13 bcm (9.54 by July 2007 the vast majority of domestic million tonnes) from Kogas in 2006, 8.2% customers will have little choice other than more than 2005. But its year-on-year sales their traditional supplier. to retail gas companies in 2006 decreased for the fi rst time, down 0.5% from 2005 On 10 January 2007, the eagerly awaited to 19 bcm (13.96 million tonnes). The sales results of the competition report on the decline was due to warmer weather in the energy sector inquiry were released.1 The latter half of the year and a slowdown in key fi ndings of this report are summarised economic growth. below.

As in many IEA countries, this winter has At the wholesale level, gas (and electricity) seen low domestic demand due to warm markets remain national in scope, and weather. In Korea, this has lead to high generally maintain the high level of storage volumes and considerably less concentration of the pre-liberalisation market tightness than in the previous period. The current level of unbundling of winter (2005/06) when Kogas was extremely network and supply interests has negative active in the spot LNG market. repercussions on market functioning and on incentives to invest in networks. Cross- border sales do not currently impose Recent developments any signifi cant competitive pressure, so in Europe incumbents rarely enter other national markets as competitors. There is a lack of reliable and timely information on the The European commission and regulators markets. More effective and transparent body have both released reports in early price formation is needed. Competition 2007 on the state of the European gas at the retail level is often limited. markets. The introduction of competition Currently, balancing markets often favour in Europe’s gas and electricity markets is incumbents and create obstacles for new- an integral part of European energy policy comers. The size of the current balancing which is directed at achieving the three zones is too small, which leads to increased closely related objectives of: a competitive costs and protects the market power of and effi cient energy sector, security of incumbents. supply and sustainability. As part of the sector enquiry, the commission The reports are seen as a critical litmus launched individual investigations into a test in the run up to the much-vaunted number of energy companies:

1. http://ec.europa.eu/comm/competition/sectors/energy/inquiry/index.html Natural Gas Market Review 2007 • Recent Events 33

16 May 2006. Investigations at the The group proposes the following four key premises of gas companies in Austria, actions: Belgium, France, Germany and Italy, and The development of integrated single at the premises of electricity companies grids for the EU internal market in in Hungary; electricity and gas. 29 May 2006. Investigations at the Regulatory oversight at national and EU premises of electricity companies in level including a European regulatory Germany. The Commission has since body. announced proceedings against one of Democratic accountability. the companies concerned for allegedly interfering with the conduct of the Effective separation of transportation investigation; and and trade functions (unbundling). 12 December 2007. Investigations at There is a clear growing consensus that the premises of German electricity competition is inadequate within Europe, companies. that investment in several key areas is lagging, and that regulatory uncertainty The Sector Inquiry has identifi ed a number is a key cause. As a result of these of serious shortcomings which prevent weaknesses, Europe’s energy security and European consumers from reaping the full competitiveness are suffering. benefi t of competitive gas markets. The inquiry also noted the slow progress in IEA energy policy reviews integrating European markets more closely It has been the IEA view that the majority through expanded gas transmission links of IEA European member countries in across national frontiers. the EU could do much more to introduce competition in the gas sector. Our reviews of European regulators group for the following countries have recommended electricity and gas (ERGEG) that additional steps be taken to increase liberalisation in the EU: Germany, 2007; The European regulators group welcomed Greece, 2006; Belgium, 2005; Spain, 2005 the sector inquiry results,2 saying: and The Czech Republic, 2005. A single European energy market does not currently exist; nor does a comprehensive The IEA intends to publish a study in late level regulatory framework to facilitate 2007 devoted to the topic of gas trading and oversee such a market. The existing in the Europe. regulatory picture is one of primarily national frameworks, although within a growing United Kingdom regional framework. Present EU legislation addresses only a limited subset of cross- supply developments border issues. The resultant “regulatory gap” creates uncertainty which acts as a In 2006, two new pipeline infrastructure barrier to the necessary investment. projects were delivered in the United

2. Available at http://www.ergeg.org Natural Gas Market Review 2007 • Recent Events 34

Kingdom market, both secured by long- Langeled South will in late 2007 be term contracts indexed to the United connected to gas production Kingdom spot gas price (the NBP). via onshore Norway. Because the pipe had The Langeled South and BBL pipelines no dedicated production at the time of were commissioned in October 2006 commissioning in 2006, there was some and December 2006 respectively. Two further infrastructure projects were uncertainty as to what the volume of also completed, the expansion of the fl ows through the Langeled would be. In Interconnector with Belgium and the the summer of 2006, futures prices for the Teesside LNG terminal, planned and built next winter were trading at USD 18/MBtu in under a year. because of this uncertainty. However, for now the pipeline is being fed by gas from Langeled South is the largest underwater the Troll area through a junction point gas pipeline built and can carry 25 bcm in the Norwegian offshore system. The per year (more than a quarter of United fl ow of gas through the Kingdom demand) into the United has been consistently high ever since Kingdom from onshore Norway. It is a commissioning, causing a USD 2/MBtu groundbreaking achievement technically, drop in the monthly NBP price to around but also fi nancially – because it is part USD 4/MBtu. Indeed, the day that the of the fi rst large-scale gas production commissioning fl ows came ashore in to project in Europe that it is not fi nancially the United Kingdom’s system, the daily underwritten by oil-indexed gas sales. NBP price briefl y became negative.

Figure 7 New import infrastructure for the United Kingdom market

120 Dragon 2 Grain 3 100 Grain 2 South Hook 2

Volume in bcm 80 Dragon South Hook 1 Teeside Gasport 60 IUK 2 BBL 40

Langeled 20 Grain 1 IUK 1 0 2005 2006 2007 2008+ Pipeline LNG Planned LNG

Source: Published sources & company announcements. Natural Gas Market Review 2007 • Recent Events 35

Figure 8 Investment reverses the trend of increasing United Kingdom winter prices

20 3.5 bcm 18

3 16 USD/MBtu

14 2.5 12 2 10

1.5 8

6 1 4 0.5 2

0 0 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Grain LNG Net Interconnector imports Langeled BBL

Source: National Grid, IUK, the United Kingdom Government.

BBL is a uni-directional pipeline which can per year) and a new LNG terminal (4 bcm supply up to 16 bcm per year from onshore per year). The LNG terminal is particularly Netherlands to the United Kingdom. noteworthy because it was built in clear Physical fl ows are expected to be shaped response to the spot price signals from the in order to match higher prices in the last winter. Excellerate Energy applied for winter which are caused by increased and built an LNG terminal in the North East demand. There was some concern before of the United Kingdom. From conception the winter as to where the physical gas to delivery, this LNG terminal took less would come from for delivery through the than one year. BBL, particularly in a cold winter. However, the winter 2006/07 has so far turned out The fl ows in the Interconnector between to be relatively mild across Europe, so Belgium and the United Kingdom have been continental players were left with excess negligible all winter, again proving that contractual commitments which they they do not respond to price differentials were keen to offl oad. in the retail markets of Belgium (above USD 8/Mbtu) and the United Kingdom Two smaller projects were also completed (below USD 5/Mbtu). The reason for this in time for a much anticipated winter is that there is a disconnect between the price spike (which now seems unlikely). wholesale price in Zeebrugge (Belgium) and These were the United Kingdom/Belgian the retail price charged by gas companies Interconnector expansion project (7 bcm in Belgium. Belgian gas companies did not Natural Gas Market Review 2007 • Recent Events 36

need more gas over the 2006/07 winter Belgium. This was followed swiftly by price as temperatures have been mild, but they equalisation between the United Kingdom still charge customers prices near to record NBP and the Dutch TTF gas trading which highs. In contrast to the winter 2005/06 looks on the surface as if an effi cient market when despite the price differential only 50% is operating. Unlike the United Kingdom, of capacity was used to fl ow to the United however, the majority of the Dutch and Kingdom, in 2006/07 the reverse seems to Belgian wholesale and retail markets are be true. Although the United Kingdom has not based on the clearing prices at the enjoyed “half price gas” for the winter with exchanges, so wholesale Zeebrugge and minimal exports, this surely is further proof TTF prices have only a limited effect on that there is a lot of work left to do before a consumer prices within those countries. real European gas market emerges. This explains the relative lack of liquidity compared with the NBP. A real “Northwest European” gas market? In the United Kingdom, the majority of supply companies buy gas at the NBP in order The commissioning of the BBL linked to sell to consumers. In the Netherlands and the United Kingdom and Dutch markets Belgium there are still many legacy contracts physically for the fi rst time, completing linked to other indices which allow the the triangle of pipelines between the buyer to take a volume of gas within a pre- Netherlands, the United Kingdom and determined range each day, month and year.

Figure 9 Northwest European exchange prices converge

10

9

USD/Mbtu 8

7

6

5

4

3

2

1

0 Oct/06 Nov/06 Dec/06 Jan/07 Feb/07 Mar/07 NBP ZEE TTF Natural Gas Market Review 2007 • Recent Events 37

If the winter is cold, demand will increase demand by 27 mcm per day (on average). and the contracted volumes may not be The majority of this response came from suffi cient for the continental suppliers. If the CCGT power stations reducing their winter is mild, then the volumes contracted gas consumption at times of off-peak may be in excess of those needed. However, electricity demand (coal lifted its share of in both cases, the bulk of demand is met power generating needs markedly in 2006, through bilateral contracts, with little see the section on Gas-Fired Power), as liquidity in the exchanges. well as fi rm gas consumers opting to sell their gas back to the market.3 To balance their portfolios, continental suppliers sometimes make use of the Rising wholesale energy prices have had liquidity of the Northwest European the expected delayed effect on end-user market. In the winter 2005/06 the NBP was prices as these customers only see price the balancing market for a region which increases every three months. Domestic found itself short of gas due to the cold consumers were subjected to gas (and – the price spiked as a result. In winter power) price increases in 2006 with all 2006/07, the NBP market has been the the major retail suppliers increasing their release valve for excess gas not needed prices at least twice. The effect of sustained due to the mild temperatures – the price high prices has resulted in a fall in demand has therefore been low compared to oil that has continued into 2007. As wholesale indexed prices. prices have declined in winter 2006/07, so the major retail suppliers have slashed Demand response: winter 2005/06 prices resulting in many residential users switching suppliers. The price reductions In the National Grid “Winter Consultation amongst the retail suppliers have resulted Report 2006/07” an analysis was made in a “gas price war” which was ongoing as of the level of demand-side response ex- this document went to press, with over perienced during the high-priced winter 4 million customers switching supplier of 2005/06. As expected, industrial and since the start of 2006. commercial users were more affected than households for several reasons: the wholesale gas price makes up a greater Gazprom Algeria MOU proportion of their total energy bill; they are metered and charged regularly; Sonatrach and Gazprom signed a memor- and they often have greater individual andum of understanding (MoU) in August fl exibility. 2006, following a visit by Russian President Vladimir Putin to Algeria (accompanied by In order to match supply and demand Gazprom CEO Miller). The visit, the fi rst during the highest priced days of winter by a post-soviet Russian leader, was seen 2005/6, daily metered customers reduced as a strong manifestation of resource-

3. Further information on demand-side market response can be found in the 2006/07 Winter Consultation document. Natural Gas Market Review 2007 • Recent Events 38

diplomacy from the president. The MoU the MoU will result in (other) commercial covers “activities in the oil and gas sector: and technological agreements. geological exploration, production, gas transmission and distribution network In 2004, IEA-Europe depended for 34% development, asset swaps, natural gas and of its gas on Russia and Algeria; Italy oil processing and marketing.” obtained 61% of its gas from these two countries. However, not only does Europe Sonatrach has a long history of agree- rely heavily on Russian and Algerian gas, ments with third parties. For its part, it also constitutes the main market of Gazprom, which has just entered the Gazprom and Sonatrach – the dependency LNG marketing arena, has also concluded is two-fold. Algeria delivered 90% of its several agreements regarding LNG with gas exports to OECD Europe; 70% of Asian companies. Thus, both companies Gazprom’s export volumes went to OECD have been cooperating with various gas Europe, making up some 85% of Gazprom’s players worldwide and the MoU was not gas export revenues and about 60% of its unexpected, particularly given President total gas sales revenues. Italy alone bought Putin’s earlier visit. 40% of Algeria’s gas exports.

The MoU raised some concerns from Europe and its principal suppliers are consuming countries: Gazprom and interdependent, but both are trying Sonatrach hold export monopolies in to diversify their portfolios as much as Russia and Algeria respectively. These two possible. Europe’s gas security discussion has countries are the largest and fourth largest prompted European countries to redouble gas exporters globally, and two of the their efforts to diversify their sources of gas three largest exporters to the EU. Despite imports. Conversely, producers are naturally the concerns about potential export co- looking to other gas markets to hedge their ordination as a result of the MoU, it should dependence on European buyers. Gazprom is be borne in mind that the two companies making efforts to diversify its own markets could come to price (or other policy) for its gas exports, targeting supplies to convergence without such an agreement the North American and Asian markets. For as they could simply adopt parallel its part, Sonatrach is looking to the United behaviour. It seems more likely that in fact States and India.

Table 1 Combined share of Russia and Algeria in Europe IEA 2004 Italy Spain Turkey Europe Russian / Algerian gas imports as % of gas consumption 34 61 50 77

Russian / Algerian gas imports as % of total primary energy supply (TPES) 8 22 9 18

Russian / Algerian gas as % of input in power and heat generation 11 30 13 40

Source: 2004 IEA data. Natural Gas Market Review 2007 • Recent Events 39

There is much talk of possible collusion in Korea, and the remaining 14% to Chinese the gas market, prompted by President Taipei in 2006. Some Arun contracts are Putin’s equivocal reference to a possible due for completion in 2007 while Bontang gas cartel. The growing number of suppliers contracts are due over 2011 to 2018. and energy sources means that any coordination, if planned, would be as diffi cult Ongoing problems in the investment to implement as efforts to form cartels in regime and governance of Indonesia’s other commodities. Unlike oil, gas has many energy sector have led to decreasing substitutes in power generation and steam investment in upstream oil and gas raising applications. The Gas Exporters production over the past decade. Such Forum last met in Trinidad in May 2005; no investment was needed to compensate meeting occurred in 2006, although one is for declining reserves in existing fi elds. In scheduled in Qatar in April 2007, rekindling addition to the call on production to serve discussion of a possible natural gas version export commitments, the Indonesian of OPEC. The Russia-Algeria agreement is government is also trying to increase the likely to raise Europe’s interest in energy share of gas in its domestic energy mix. diversifi cation, in terms of suppliers and in It has made clear that, in response to its terms of the overall energy mix. In addition, gas supply-demand mismatch, its policy renewables, coal and nuclear power need to will focus on meeting domestic demand be maintained as viable alternatives to gas rather than exports. in the power sector. In early 2005, Indonesia’s state company Pertamina negotiated the rescheduling Indonesia of some 51 cargoes of its total 450 cargoes under long-term contracts with Indonesia, which enjoyed the status of the Japan, Korea and Chinese Taipei for the world’s largest LNG exporter for 22 years year (each cargo typically holding 60 000 but lost the top spot to Qatar in 2006, has tonnes of LNG). In December 2005, the in recent years been cutting its contractual country’s upstream regulator BP Migas LNG deliveries because of a slower-than- and Pertamina advised that a total of 61 expected rate of gas reserve replacement cargoes (52 from Bontang and 9 from combined with dwindling feed gas pro- Arun) would be cut from Indonesia’s duction and growing domestic demand. 2006 shipments. According to customs statistics of Japan, Indonesia sold 1.9% The production decline is most pronounced less LNG to Japan in 2006 than 2005, while in the East Kalimantan fi elds that supply the – ironically – it earned 13% more, some Bontang liquefaction plant, although the USD 5.9 billion in 2006. Arun LNG facility has also been affected. As a consequence, Indonesia’s share of global Indonesia currently plans to export 53 fewer LNG trade has halved from its peak of 31% LNG cargoes than contracted, representing a in 1999, to 14% in 2006. Indonesia’s LNG 12% reduction, in 2007. The cargo reduction is supplied on mostly long-term contracts, equates to about 1.6% - 1.8% of the global with about 63% going to Japan, 23% to total LNG trade. Natural Gas Market Review 2007 • Recent Events 40

Japanese buyers hope to renew contracts investments in the Shtokman and Sakhalin for half of the 16.3 bcm per year (12 mtpa) II projects in Russia will have very large of Indonesian supply contracts set to impacts on the Atlantic and Pacifi c gas expire in 2010 - 2011. Their combined markets, respectively, while expansion of contractual volumes of 16.3 bcm account the fl edgling GTL market hinges on only a for about 20% of Japan’s annual LNG few mega-investments. imports. The two sides started full-fl edged discussions on contract renewals in June Shtokman decision 2004 and agreed to key commercial terms for partial extension in September 2005, The Shtokman fi eld is located in the Arctic but no fi nal agreement has been reached. , a tough area for any major At least 4.1 bcm per year (3 mtpa), and project development. The fi eld itself is potentially as much as 8.2 bcm per year estimated to have 3.7 tcm of gas reserves (6 mtpa) is expected to be renewed. and plans have existed for some time to export this gas to markets in Europe and Pertamina announced in December 2006 North America targeting 2012. that it would not extend a 2.0 bcm per year (1.5 mtpa) contract to Chinese Taipei’s In October 2006, Gazprom announced CPC Corp. beyond its end-2009 expiry date that it would proceed on its own with the because Japan is being given preference. giant Shtokman gas fi eld development in CPC has another contract of 2.5 bcm per Barents Sea rather than give 49% of the year (1.84 mtpa) that expires in 2017. project to foreign players. Five Western companies had been short-listed for LNG development, and it was thought the Major project decisions in 2006 chosen companies might be announced around the time of the G8 Summit in Some key investment decisions are St. Petersburg in July 2006. among the developments during the period between this 2007 edition and the Gazprom claimed the fi ve contenders had previous 2006 edition of the Natural Gas been unable to offer assets equivalent in Market Review (GMR). Decisions on large scope and quality to the reserves of the

Table 2 Shtokman, status

Natural Gas Market Review 2006 Natural Gas Market Review 2007

Project partners (possible): Project partners (possible): Gazprom 51% + foreign partner(s) 49% (contenders: Gazprom (Sevmoreneftegaz) 100% for the moment, with Statoil, Norsk Hydro, Total, foreign subcontractors ConocoPhillips and Chevron)

Transportation routes: Transportation routes: Pipeline gas source to Europe (via Phase 2) Murmansk LNG targeting North American probably after 2015, with marginal markets, 16 - 20 bcm per year (12 - 15 mtpa) starting 2012 LNG possibility Natural Gas Market Review 2007 • Recent Events 41

fi eld. While the company insisted that LNG In Russian industry circles, it is suggested remains part of the development plan for that initial production from Shtokman the fi eld, the company also said piping gas is unlikely to begin before 2015, instead to Germany would now take precedence of an earlier 2011 target. Though in the over shipping cargoes to North America, GMR 2006 Shtokman LNG exports were where Gazprom has not yet secured any tentatively marked for an expected date fi rm capacity at existing or planned LNG of 2011, given the unclear circumstances receiving terminals. of the project, notably its location, it appears that little gas will reach markets Preceding this announcement, after from Shtokman before 2015. his meeting with German Chancellor Merkel at the end of September, Russian Sakhalin II settlement President Putin mentioned the possi- bility of redirecting future gas supplies The Sakhalin II project is already being from Shtokman away from the North built on Sakhalin Island, developing gas American market to the European market, and oil resources off the Russian Pacifi c suggesting that Russia could sell between coast, mainly targeting the Pacifi c energy markets. 25 and 45 bcm per year from Shtokman to Europe via the Nord Stream pipeline across In December 2006, Gazprom took over a the Baltic Sea. In December 2006, however, controlling 50%-plus-one-share stake in President Putin reiterated that the subject the Sakhalin II export venture in return for of foreign participation in the project could a cash payment of USD 7.45 billion, putting be considered again if interesting proposals an end to an 18-month saga over the were to be made by foreign partners. In project’s massive cost increases and alleged January 2007, Gazprom approached the environmental violations. The existing fi ve LNG fi nalists again, inviting them to partners are left with halved stakes of the work as subcontractors. project company: 27.5% for Shell, 12.5% for Mitsui and 10% for Mitsubishi. Sevmoreneftegaz, a wholly owned sub- sidiary of Gazprom, which holds the The production sharing agreement (PSA) for license to develop the Shtokman fi eld, the Sakhalin II was signed in the mid-1990s plans to review reserves in the Shtokman when the country was in considerable fi eld in 2007. Although the total reserves fi nancial distress. The PSA is seen by many fi gure of 3.7 tcm is not expected to Russians as unduly advantageous to foreign change signifi cantly, commercial reserves, shareholders. which now total 2.9 tcm, are likely to be increased with new exploration results. After the share-transfer agreement, The company says it would determine Gazprom confi rmed that all the supply the capacity of a pipeline (supposedly to commitments from the project would supply Russian domestic markets and also be met on time, starting in late 2008. connecting to Nord Stream) and possibly a Construction work at the planned liquefac- liquefaction plant for the project. tion plant is on schedule to complete the Natural Gas Market Review 2007 • Recent Events 42

Table 3 Sakhalin II, status

Natural Gas Market Review 2006 Natural Gas Market Review 2007

Project partners: Project partners: Gazprom 50% + 1 share, Shell 55%, Mitsui 25%, Mitsubishi 20% Shell 27.5%, Mitsui 12.5%, Mitsubishi 10%

Transportation routes: Transportation routes: 13 bcm per year (9.6 mtpa) LNG deliveries in 2008 Gazprom confirming all supply commitments would to Japan, Korea and Mexican west coast be met on time, starting in late 2008 Controversies over cost increases, alleged environmental The cost and environmental issues apparently being violations resolved

fi rst 6.5 bcm per year (4.8 mtpa) train in 2007 Qatar placed a moratorium on new and the second train of the same capacity development of its reserves in the North six months after that. Since feedgas will Field and is awaiting the results of technical not be available until 2008, the trains are studies into the performance of the fi eld. to be commissioned by importing LNG, Adding the effects of this moratorium to regasifying and reliquefying the gas. The other recent developments in the global project has already signed up long-term gas industry, the future of GTL now looks customers in Japan for 6.7 bcm per year, more uncertain than a year ago. Korea for 2.0 bcm per year and Mexico for 2.2 bcm per year. Deliveries are still During the past year, GTL projects’ expected to start as scheduled. costs have been the victim of rapidly increasing costs endemic in the energy Gas-to-liquids (GTL) industry. Early in 2007, Exxon announced that it had cancelled the 154 000 b/d The potential demand for GTL products is Qatari plant which it postponed in 2006 huge because they can be used in the gas due to the moratorium on Qatari gas oil and diesel oil markets which represent production. As of February 2006, the 13 mb/d of OECD consumption. GTL diesel costs of Pearl GTL had doubled from itself has two market applications for USD 5 Billion to USD 9 Billion. Shell an- cleaner transport fuels; it can be blended nounced in January 2007 that it has broken with conventional diesel to meet lower ground on the Pearl GTL project, but that sulphur specifi cations, or it can be sold as the cost for this project had now increased a spec product for use by buses, trucks to USD 19 Billion. Other developments or other utility vehicles to alleviate air have changed the picture of the following pollution problems in major cities. Table 4 which has been taken from the GMR 2006, but updated as of February In the GMR 2006, Gas-to-Liquids (GTL) 2007 with the changes highlighted. capacity planned and under development for commercial scale projects exceeded The economics of GTL processing can be 773 000 b/d, with the bulk of these summarised as the value of the product investments planned in Qatar. In 2006, and the cost of production: The value of Natural Gas Market Review 2007 • Recent Events 43

the product depends on market prices of of capacity. With the announcement by the liquids produced and as such is largely Shell and Exxon that costs have increased driven by the expectations of better fuel up to USD 135 000 per daily barrel of standards in OECD countries. The principal capacity, it is clear that economics of GTL costs include plant construction, gas production have changed rapidly. feedstock and process effi ciencies, such as product yields and energy effi ciency of Meanwhile, price expectations for LNG in the plant. There are also opportunity costs the United States have decreased even which can be summarised as the value as LNG price expectations for Europe of alternative products such as LNG or and Pacifi c markets have increased. Price domestic gas uses, as well as the value of expectations for LNG projects affect the delaying production. netback on LNG facilities which compete for the feed-gas that GTL projects use. GTL Based on industry estimates in the GMR processes typically require about 10 MBtu 2006, the capital costs for historical GTL of gas to produce one barrel of fuel. Thus, projects tended to be in a range of between a change in the opportunity cost of gas USD 20 000 to USD 30 000 per daily barrel feedstock of USD 0.50/MBtu would shift

Table 4 Global GTL projects

Project name Capacity ( kb/d) Status (2007) Company Location

Bintulu 14.7 Existing Shell Malaysia

Mossel 25 Existing PetroSA South Africa Sasol, Chevron and Oryx 34 First product Qatar Qatar Petroleum (QP) Escravos 34 Under construction Chevron/NNPC Nigeria

Pearl 140 Under construction Shell, QP Qatar

Oryx (expansion) 76 Advanced planning Sasol, Chevron and QP Qatar

Tinhert 36 FID postponed Sonatrach Algeria

Palm 154 Cancelled Exxon Qatar Postponed due to moratorium Sasol Qatar 130 Sasol Chevron Qatar on North field Postponed due to moratorium Conoco Qatar 80 Conoco Qatar on North field Postponed due to moratorium Marathon Qatar 120 Marathon Qatar on North field Ivanhoe 45 Speculative Ivanhoe Energy, Egas

Russia ? Speculative Shell Russia

Iran ? Speculative Sasol Iran

Source: IEA data, company statements. Natural Gas Market Review 2007 • Recent Events 44

the synthetic fuel production cost by The growth in gas prices and the loss of oil around USD 5/bbl. tax preferences are already having serious economic implications for Belarus. This also raises concerns about Belarus’ ability Russia/Belarus gas to pay the increased gas bill. There are and oil negotiations concerns that it may in fact build up a debt to Gazprom – in past negotiations with other countries, Gazprom has been able to In 2006, Russia and Belarus negotiated at convert such debts to downstream equity. the political level over several intermingled issues: gas prices, gas transit tariffs and oil Belarus has been trying to offset the price taxes. About 20% of Russian gas exports increases by introducing various measures. (40-44 bcm) and nearly one third of Russia’s For example, it renegotiated with Russian oil exports (31-33 million tonnes per year) companies the terms of crude oil supply transit Belarus. Belarus imports nearly all from February 2007. Belarus also raised its gas (20-21 bcm) and approximately oil transit tariffs by over 30% in February 90% of its crude oil from Russia. 2007 and announced a plan to charge a duty for the use of land under oil and gas In 2006, the Russian government sought transportation pipelines. to eliminate special treatment for Belarus in terms of oil and gas pricing and move to While the gas agreement was reached market relations, as it has been doing sys- just in time (2 minutes before the threat tematically with all CIS countries (see later to shut off supplies expired) the oil section on Russia). Belarusian offi cials were negotiations carried on through 2007, concerned about the economic implications resulting in oil delivery problems on the of these moves. The parties reached an Belarus pipeline. While the oil negotiations agreement on gas prices and transit tariffs are now over, the stability of both the gas on 31 December 2006 (see Box) but the oil and oil agreements between Russia and negotiations continued in 2007. Belarus is uncertain.

Box 1 Gas agreement of 31 December 2006

Gazprom will charge Belarus USD 100/1 000 m3 (USD 2.65/MBtu) for gas supplies in 2007. The price will grow to the Western European level (minus the transportation component) by 2011: Belarus will pay 67%, 80% and 90% of the European price in 2008, 2009 and 2010. The fee for transiting Russian gas through Belarus grew from USD 0.75 to USD 1.45/1 000 m3/100 km (USD 0.02 to USD 0.04/MBtu/100km). Gazprom will buy a 50% stake in the state-run Belarusian gas transportation company, Beltransgaz, for USD 2.5 billion, paying for it in cash over four years. Natural Gas Market Review 2007 • Investment 45

INVESTMENT

Insuffi cient investment in the gas sector clarity in the regulation of cross-border to 2015 is a serious cause for concern infrastructure. – the existing bottleneck in the gas market is in worldwide gas production, There is also mounting concern in and this is likely to get worse. North America, particularly about impediments to investment in local For a selection of 13 LNG projects and regional grids. analysed, there is now an average delay of nearly a year along with an The investment chapter has been written average increase of costs of some with reference to the IEA’s World Energy USD 2.26 billion per project, resulting Outlook 2006 (WEO 2006). We assess in a considerably worse situation that current gas sector investment by activity expected in the Natural Gas Market with reference to the WEO 2006 reference Review 2006 (GMR 2006). scenario which analyses investment needs There is also a distinct defi cit of in the global energy industry to 2030 investment in new transmission over assuming no signifi cant change in existing the period to 2015 driven particularly energy policies. In this scenario, investment by regulatory and political uncertainty. requirements across the entire global gas Investments in transportation over industry amount to some USD 156 billion increasing distances show a distinct per year. preference for LNG over new pipelines in order to mitigate transit risk. General cost infl ation Storage investment is also lagging substantially in IEA Europe, where All construction costs have increased market price signals are largely absent. sharply in recent years. In part, this has It is progressing well in IEA North America and the UK where signals are resulted from higher basic material strong. costs, such as steel and cement, but cost infl ation has also been driven by a sharp IEA countries need to ensure that their increase in demand for equipment and domestic gas markets are fl exible, or manpower as companies have sought to they will miss out on securing LNG respond to higher energy prices. A vicious regasifi cation capacity and hence LNG circle has been started whereby the costs supplies. Siting and approval procedures of obtaining energy, raw materials and need to be strengthened. human resources are increasing the cost Investment in downstream transpor- of incremental supplies of the same basic tation and distribution networks is factors of production. also deteriorating when compared with the assessment in the GMR 2006, An increase in the number of large-scale particularly in the IEA European region projects being developed at the same where infrastructure investment essen- time, their remoteness and greater tial to cope with new fl ows of gas caused complexity and the increasing need for by increasing import dependence is costly production enhancement at large not being sanctioned in the absence of mature fi elds have added to the upward Natural Gas Market Review 2007 • Investment 46

Upstream oil and gas industry investment in Figure 10 nominal terms and adjusted for cost inflation

300

250

200

Index (year 2000 = 100)

150

100 year 2000

50 2000 2002 2004 2006 2008 2010 Upstream investment Upstream investment assuming zero cost inflation since 2000

Source: IEA database and analysis. pressure on cost. This phenomenon has could tighten the balance and make this been seen across the oil and gas industry. situation worse. Figure 10 is taken from WEO 2006 and There are certain factors within the control shows the increase in actual and planned of project managers which could help reverse spending in the oil and gas industry this trend as well as simply postponing or from 2000 to 2010 against the infl ation- cancelling a project, these include: adjusted spending over the same time period. It shows that in 2010 the industry Scope and cost review for each element will be spending around 170% more than of the project; in 2000 in nominal terms, but will achieve Modular construction approach, rather an infl ation-adjusted increase of less than lump-sum turn-key contracting; than 50%. Economy of scale by expanding or merging projects; Exploration plans themselves will be hampered by the shortages of rigs and Use of identical designs; manpower over the next one to two years. Competitive engineering bidding This is likely to result in a shortage of new processes (using different companies). projects awaiting development when the current wave of upstream developments A 2005 benchmarking survey of 30 oil and is completed early in the next decade. gas companies and 115 university studies Further, such infl ationary pressures will is cited in WEO 2006. It estimates that the cause delays in ongoing projects which demand for petroleum industry personnel Natural Gas Market Review 2007 • Investment 47

will increase by around 7% per year for the to be exported, including as LNG (Russia, next ten years. Demand for experienced, Central Asia, Nigeria, Middle East and qualifi ed personnel far outstrips current North Africa). If problems were to arise availability and there are regional shortages within these countries or between these of petroleum geology and engineering countries and importers, it would be less university graduates. The biggest short- likely that all the required investments ages of local graduates are in North in export-related infrastructure would America, the Middle East, Russia and other be forthcoming. A large volume of gas is transition economies. Venezuela, Mexico, produced from fi elds which contain both India, China and Indonesia are among the gas and oil.4 Any deferral of upstream oil few countries with excess graduates in investment may therefore have a knock- petroleum disciplines. Globally the supply on effect for gas production. should meet demand if all petro-technical graduates were to join the industry. A While most upstream investment continues historically low intake of suitably qualifi ed to go to development of fi elds already in graduates into the industry is pushing up production, the increase in spending since the average age of the workforce across the start of the current decade has been all disciplines: it currently ranges from 40 focused on development of new fi elds that to 50 years (Deloitte, 2005). A signifi cant were already discovered by 2000. Spending gap also exists between the supply of, on exploration has risen in absolute terms and demand for, mid-career experienced since the beginning of the current decade, industry personnel. but has continued to decline as a share of total upstream investment. Exploration continues to be successful in discovering Upstream fi elds of a diminishing size – many more of which are needed to offset decline at For gas projects, the upstream absorbs the super-giant fi elds developed last century. majority of total investment, accounting On the one hand there is an increasing for 56% of total gas sector spending, or need for investment in declining gas fi elds, USD 87 billion per year. As OECD regions but on the other hand the new greenfi eld look to import more gas, it is clear that sites such as Alaskan North Slope or Yamal the majority of this investment will have in Russia are of the order of four to fi ve to be committed in non-OECD countries. A times more expensive to develop than particular concern is whether the high rates was existing gas production. of increase in exports projected for some regions, especially the Middle East, are Oil and gas companies based in OECD achievable in light of institutional, fi nancial countries continue to dominate global and geopolitical factors and constraints. A upstream investment. Although the share small number of countries are expected of total investment made by national to provide the bulk of the incremental gas oil companies in the Middle East and

4. “Wet gas fi elds” are primarily gas fi elds with associated liquids, fi elds with large volumes of liquids often contain “associated gas” which can be produced or fl ared. Natural Gas Market Review 2007 • Investment 48

transition economies is projected to be Investment to 2015 higher in the second half of the decade than in the fi rst, it is still remarkably small, For projects that target fi rst production at less than 10%. Unit development costs at the end of 2010-12, fi nal investment are however signifi cantly lower in the decisions must be taken before the end of Middle East and onshore Caspian regions 2007. Even then, the project must progress than in remote green-fi eld, deep water or very smoothly if it is to hit the 2010 arctic regions. deadline. Final investment decisions (FID) on the investment in gas-supply capacity The international oil and gas companies are that will come on stream in the fi rst period uniquely equipped to undertake complex, have largely been taken and investment large-scale projects, thanks to their project- capital is feeding into construction. management skills, their access to advanced Signifi cant capacity should be available technology and their fi nancial resources. by 2010 to meet the rise in demand, but But opportunities for them to invest are there are considerable risks of delays and in fact receding as a result of government cost overruns. Our analysis suggests that policy, civil confl ict or geopolitical risks – there is little margin for error with mostly especially in the Middle East, Russia, Africa downside risk for time and cost. and South America. The willingness and ability of national oil companies to develop The GMR 2006 noted that cost overruns reserves are in many cases very uncertain and construction delays were expected (see separate sections on South America to have a substantial impact on upstream and MENA). project delivery in the current investment cycle. This is now much more of a concern. There may be more that OECD Although most engineering contracts are governments can do domestically to signed at fi xed rates, service companies do ease any future tightness in the market. not provide full insurance against raw ma- Those OECD countries with gas reserves terials and human resource cost pressures. should examine their domestic production Infl ationary effects will materially increase policies and verify that these policies the industry’s required call on upstream indeed suffi ciently encourage the econ- capital to 2010-2012 and beyond. The per- omic production of gas. Governments’ formance of upstream LNG investments attention should be drawn particularly in the Table 5 below illustrates this risk of to the experience of the United Kingdom infl ation and slippage, showing an aver- and Norway who have recently modifi ed age delay of around one year amongst the their upstream policies to maximise the projects noted and average cost increases economic output from their reserves and of some USD 2.26 billion per project. returns to the state. These policy revisions have particularly focussed on encouraging Greenfi eld projects are increasingly development of so-called “fallow fi elds” – complex, and LNG is no exception, with economic reserves held by companies but only a few specialist producers able to not in production (see sections on Norway supply key components. Because of this, and United Kingdom). cost infl ation and delays are likely to be Natural Gas Market Review 2007 • Investment 49

Table 5 Selected global LNG projects Previous expectations Latest expectations and estimates Cost and delay Before July 2005 December 2006 Sakhalin 2 12 months USD 10 billion USD 22 billion (Russia) USD 12 billion Production in 2007 Production in 2008 December 2005 December 2006 Gorgon (When marketing looked good) USD 12 billion+ (for upstream and 12 Months (Australia) USD 8 - 9 billion environmental reasons) USD 3 - 4 billion FID 2006, Production in 2010 FID mid 2007, production in 2011 Pluto FID mid 2007, production in 2010 So far, no apparent problems (Australia) North West June 2005 FID August 2006 Shelf Train 5 USD 0.5 billion USD 1.5 billion, start 2008 Cost 30-35% up, start 2008 (Australia) October 2004 December 2006 El Andalus 8 months USD 1 billion (+2.1 upstream) USD 3.95 billion (EPC bid) (Algeria) USD 0.85 billion Production by November 2009 Production probably after mid 2010 February 2007 Skikda June 2005 USD 2.7 billion (EPC bid) 12 months (Algeria) Production in 2009 or 2010 Production in 2010 or 2011 NLNG 7 Plus March 2006 (buyers short-listed) February 2007 (SPAs signed) 21 months (Nigeria) Production in 1Q 2010 FID in 2007, Production end 2011 August 2006 December 2005 (partners reorganised) Brass LNG (buyers short-listed) 12 months USD 7 billion (excluding upstream) due (Nigeria) USD 4 billion USD 3 billion to site issues Production in 2010 Production in 2011 February 2006 February 2007 OKLNG (project development agreement) USD 9.8 billion 12 Months (Nigeria) USD 6 billion (+ USD 2 billion upstream) USD 3-4 billion FID in 2006, production in 2010 FID 1Q 2007, production in 2011 September 2005 Angola LNG February 2007 12 months (integrated marketing strategy) (Angola) EPC 1Q 2007, production in 2011 USD 3 billion Production in 2010 Snøhvit LNG March 2002 March 2007 24 months (Norway) USD 6 billion, production in 2005 USD 9 billion, production in 2007 USD 3 billion Train X (5) Domestic industrial sector has taken Mooted in 2005 (Trinidad) center stage Peru LNG April 2004 January 2007 (EPC awarded) 12 months (Peru) Production in 2009 USD 1.5 billion, production in 2010 Source: Media reports. concentrated in bottlenecks. Upstream land ownership and border demarcation investment coupled with international along the pipeline route. Delays in pipeline pipelines is also at risk of infl ation and projects therefore cannot be explained slippage. However, there tend to be many purely in terms of cost factors (for a other related factors also at play in such discussion of some other factors related to projects such as environmental concerns, pipeline construction please see below). Natural Gas Market Review 2007 • Investment 50

The LNG industry is in the middle of a rapid The Qatar advantage expansion of capacity – a classic “boom”. Enormous (25 Tcm) gas reserves with Despite this, no fi nal investment decisions high liquids content were taken in the whole of 2006 for new LNG supplies and in the fi rst quarter of Well developed port (Ras Laffan) with 2007 there was only one such project space for expansion sanctioned. Peru LNG was the fi rst new Quick government decision making LNG project for 18 months. Meanwhile Only 2 partners in RasGas II and III and Qatar, the world’s largest exporter and Qatargas II, III and IV when investment a key driver of current supply growth, decisions taken is maintaining its moratorium on the super-giant North fi eld, meaning that the Stable political climate (credit rating) world’s third largest reserve holder will not Well co-ordinated commercial and invest in new projects until the end of the public policy environment current investment period, at the earliest. Good geographic location for LNG The future growth of the GTL industry also has been called into question as the fi rst quarter of 2007 also saw Exxon Mobil production such as raw materials and cancel plans for its Palm GTL project (see human capital are slowing the rate of Recent Developments section). new investment which will will inevitably impact global gas supplies beyond 2010 Concerns over investment beyond 2012 and perhaps precipitate some degree of are already surfacing in the industry. defl ation in services sector costs. This While the pipeline industry has continued current trend of service sector expansion to provide for the bulk of globally traded and future contraction is symptomatic gas, LNG has provided the majority of of the cyclical nature of the industry. incremental supply that matches global Nevertheless, should the paucity of FID demand growth. Global LNG liquefaction continue in the next few years, very capacity itself will have doubled in size serious concerns will arise about the from 2005 to 2010, but if it is to continue suffi ciency of gas sector investment in this stellar growth then new projects must the period to 2015. be sanctioned soon. But is there another Qatar, which became world LNG leader We believe that a good portion of greenfi eld in under a decade? We have augmented investment in this period will be a fi rst wave the list of key success factors in the of large scale investment in new basins, such case of Qatar, shown by leading industry as the Russian Arctic and deep-water Caspian consultant Andy Flower.5 as well as basins already identifi ed for LNG projects such as Nigeria, Australia and Iran. Hence, it is far from certain that all the gas The sensitive investment and environmental investment needed will occur worldwide. climate and/or lack of existing infrastructure Current high costs of basic factors of will mean higher capital investment per

5. “[email protected] Natural Gas Market Review 2007 • Investment 51

Box 2 LNG vs pipeline gas investment

Whether a gas reserve is to be developed as LNG or connected via pipeline to markets, very large amounts of capital are needed. A “typical” greenfi eld LNG project is likely to start producing around 10 to 12 years after initial development plans are drawn up. Brownfi eld expansions can however take place in as little as 5 to 7 years. Commercial LNG projects also benefi t from a certain amount of fl exibility. Approximately 30% of new LNG project investments are regarded as “price sensitive”, meaning that if market conditions in the intended destination are not suitable, the owner can market the gas somewhere else. Although it is diffi cult to put a price on a “standard” new LNG value chain, we estimate that a company approaching a new greenfi eld site would budget in the order of USD 3 - 5 billion for liquefaction, USD 2 billion for shipping and a further USD 0.8 - 1 billion per terminal for regasifi cation. By contrast, major international pipeline projects often have to cross multiple frontiers, and can take any length of time upwards of ten years. Pipeline investments tie reserves and markets together for long periods of time. Pipeline investors therefore need large deep and liquid markets to ensure that they will be able to place large volumes of gas at a satisfactory long-term average price. Pipeline costs themselves have increased rapidly with the price of steel, perhaps resulting in a cost of between USD 1 - 2 billion per 1 000 km of large diameter pipeline depending on the terrain and conditions. Transit issues, legal and regulatory hurdles ensure that investment cost is joined by many other critical business factors in order to ensure investments in new gas pipelines are made. In some markets, investors seek fi nancial exposure to the oil market rather than relying on gas fundamentals – either way, long-term contracts are necessary to obtain fi nancing for such deals. As with any investment, the commitment of large volumes of capital to gas supply requires management of commercial risks and mitigation/minimisation of non- commercial risks. The regulatory, institutional and political barriers to new pipeline investment can be formidable, while these are much smaller in the case of LNG. We believe that this is a principal reason why the number of proposed LNG projects continues to grow more rapidly than the number of long-distance pipeline projects.

unit production capacity in these regions. methane, tight sands and tight shales gas Technological advances will play an im- plays. These production zones tend to portant role in accessing reserves in an require more investment than traditional environmentally sensitive manner. But new gas fi elds in order to maintain production technology is almost always accompanied and manage declines. It will be important by initial growing pains. to closely watch the production profi le of these fi elds as they mature and it may be The period to 2015 will also see the necessary to revise investment require- maturing of the current wave of coal-bed ments accordingly. Natural Gas Market Review 2007 • Investment 52

Shipping of requirements through to 2015, but this additional fl exibility will be necessary for For LNG shipping, we look at two critical increased short-term optimisation in the factors, the physical capacity of the fl eet LNG industry. and the availability of crews. The number of ships is increasing rapidly even as the On the other hand, the availability of average volume of ships is also increasing. trained crews is a much greater concern, A record 35 ships are scheduled to be although information on recruitment delivered in 2007, adding to the current and training is much more diffi cult to 220 carriers. Another 47 ships are expected obtain. On one side, we are confi dent that in 2008. The global fl eet will number companies making an investment of some approximately 350 vessels by 2010 and is USD 200 - 300 million in each ship will widely expected to approach 400 by 2015. plan crew availability. On the other hand, The average capacity of a new ship will grow the sheer scale of the human resource from 140 000 m3 in 2005 to 180 000 m3 in challenge seems daunting. Between now 2008. We believe that physical shipping and 2010, there is a need to train some capacity is therefore unlikely to be a 9 000 seafarers, including nearly 3 000 bottleneck in the gas industry to 2015. qualifi ed offi cers (see LNG Section for a Investment into shipping is running ahead fuller discussion).

Figure 11 LNG shipping fleet capacity and crew requirement

)

3

50 25 000

40 20 000

Crew requirement

30 15 000

Fleet capacity (million m

20 10 000

10 5 000

0 0 1980 1985 1990 2000 2005 2010 Fleet capacity (left axis) Crew requirement (right axis)

Source: IEA data. Natural Gas Market Review 2007 • Investment 53

Transmission pipelines will have take into account the regulations of each of the 5 countries lying along the We are particularly concerned by what we path from Turkey to Austria. Meanwhile, believe to be considerable underinvest- if Chinese investment in Caspian region ment in transmission pipelines for the gas results in piped gas to China, the period to 2015. Despite the continuing Chinese call on future LNG supplies may preference for investment in LNG as a be lower. This would free more LNG for the means of moving large volumes of gas Atlantic. If more pipeline gas investments over large distances, there are some are directed at the Eurasian market, then regions where pipelines are essential European LNG demand is likely to be lower for geographical reasons. Clearly in a to 2015, having the reverse effect. globalising market, global pipeline and LNG trade are complementary in meeting global Both Russian greenfi eld basins, Yamal and gas demand. With increasing investment Shtokman, are (somewhat optimistically) in pipeline gas, there will be less pressure slated for fi rst gas in 2011. These on the global LNG market. Conversely, developments are for delivery by pipeline if pipeline investment continues to lag to domestic and European markets, requirements (as appears to be the case), though an LNG option for Shtokman has the LNG market will remain tight. not been ruled out. These pipeline projects present signifi cant technical challenges, For illustration, we have mentioned a few particularly those linking the Yamal fi elds of the more substantial pipeline projects with the existing pipeline networks from planned to deliver gas to OECD markets. Western Siberia. Planned fl ows from Since all IEA regions will increasingly Yamal approach 140 - 180 bcm per year. participate in the global LNG market, Investment costs are correspondingly these pipeline projects give an idea of the high, with estimates approaching some investment balance. USD 15 - 20 billion just for the pipeline link to the existing network. Gazprom experts In order to market Caspian gas in Europe, have been studying the permafrost in the Russia or China, large scale pipeline Yamal region for several decades with investments will need to be made. China a view to this development; while they has recently announced an expansion should be uniquely placed to make this of its internal West-East pipeline, while investment, it will nevertheless represent Gazprom is negotiating a framework a substantial call on capital. in order to expand the capacity of its central Asian pipeline system to Europe. The 50 bcm per year North Slope and The USD 5 - 7 billion European Nabucco 20 bcm per year MacKenzie Valley pipelines project targets the same basin with the are planned to deliver North American gas promise of brining 30 bcm per year of to market around 2015 or later costing gas to a premium market, but such an some USD 25 billion and USD 15 billion investment will need substantial political respectively. With the increasing fl exibility backing if it is to be realised in the 2015 of Atlantic basin LNG, we see considerable timeframe. Apart from this, the investors competition between these projects and Natural Gas Market Review 2007 • Investment 54

the major pipelines above which will furnish IEA North America, it is most clearly in IEA European demand. Any North American gas Europe that infrastructure investment is surplus or defi cit is likely to be made whole being impeded. While policy makers must by increased movement of LNG away from be mindful of the effects of environmental or to United States receiving terminals. policies and not-in-my-backyard (NIMBY) In this sense, it will be important to see resistance, it is too easy to blame these whether Yamal, Shtokman and North-Slope factors alone for the underinvestment in pipeline investments are made in the same downstream pipelines in Europe, though time period, in which case the Atlantic they clearly do contribute. LNG investment could be delivered to the Pacifi c. Two general themes of this book are that OECD regions are becoming increasingly There is much talk of piping Eastern Russian import dependent and that downstream gas reserves to markets in Japan, Korea and gas industries are also becoming increas- China before 2015. (Sakhalin LNG will move ingly market-based. The twin effects of to Pacifi c markets next year). The plans of a structural shift in supply and a change Russian producers in the relevant regions in the investment environment create suggest that it is unlikely that investment substantial challenges for downstream in production and transport from green- investment. Regulators must focus on fi eld sites will be made to deliver gas to facilitating new infrastructure additions Pacifi c markets before 2015. However, if in a market based manner in order to investment plans were given suffi ciently handle increased imports from different high priority, it is possible that gas could sources. In most cases the market is best be fl owing eastwards from Kovytka or East placed to decide what infrastructure is Siberia before that time. Any pipeline gas needed; regulations should ensure that into the Pacifi c markets would reduce the call such investments are made in a way that on Pacifi c LNG, which we would then expect enables infrastructure to be made available to see traded into the Atlantic market. to all market participants. Regulators and governments need to have a role in managing increased import dependence Downstream and must have a more sophisticated role than simply decreasing the costs of using The amount of investment in downstream existing infrastructure. gas infrastructure in consuming countries – including transmission pipelines, storage Pipeline regulation is new to many facilities and distribution networks – will European countries, where downstream by shaped by the effectiveness of the infrastructure should now be regarded as regulatory framework in channelling a natural monopoly and separated from private sector fi nance. The recent trend in the competitive business of gas supply. private equity fi nancing demonstrates that In this environment of change, there there is a large amount of money available are serious problems with commercial if the conditions are right. While there are incentives to invest in new infrastructure, some problems in regulatory approaches in largely the fault of regulation designed Natural Gas Market Review 2007 • Investment 55

solely to perform other functions, namely Because of these twin defi ciencies in increasing competition and reducing costs. regulation effects, a serious lack of The end result is that within many European investment in Europe can be seen. This countries, infrastructure investment essential comes at a time when investment is to cope with new fl ows of gas is not being desperately needed to allow the market sanctioned. to cope with the structural shift towards greater import dependence and greater Within Europe, but across several countries, competition. European regulators indi- there is an even greater problem, which vidually must see it as their mission to is that there is no harmonisation of promote investment as well as effi ciency regulatory structures within the region, and competition. nor a European regulatory body. This means that a project to build a gas pipeline between two countries might be profi table Storage on one side of the border but not on the other. Even if it were profi table at all, such a pipeline faces formidable obstacles to be Commercial storage built in the current environment because of a lack of timely regulatory decisions. The rate of investment in storage has slowed Pipeline projects which must cross several considerably in IEA Europe, but increased European countries face considerable in IEA North America in recent years. LNG regulatory risk and uncertainty if they are storage in the Pacifi c region is keeping pace to proceed. with trends. Storage in Europe is lagging investment requirements substantially by In particular, investments such as Nabucco, some USD 1 - 2 billion per year although a USD 5 - 7 billion import project which investment in the United Kingdom is travels though fi ve different IEA European against this trend, notwithstanding some countries, will not be realised unless a planning problems. Another country which broader view of regulation is adopted. For is developing large amounts of new storage such a pipeline, various factors must be is Germany, where many projects were individually negotiated, including the rate of started under the old vertically-integrated return, third-party-access regime, approvals market and are still progressing. The process, length of time to approval and the general trend of underinvestment in Europe roles of the national and EC authorities. This is very worrying for consumers because pipeline would be extremely important the volume of gas imports to Europe is for European supply security as it would increasing, as are the distances over which open a new “corridor” and supply source it must travel. More disturbingly, domestic from the Caspian. Nevertheless, large scale production, and the fl exibility that it international projects such as Nabucco guarantees, is decreasing fast. These are all perhaps give the clearest example of the good commercial arguments to build more way in which Europe is threatening its own storage, but because of market design, future supplies of gas through regulatory the investment signals are obscured from uncertainty. potential investors. Natural Gas Market Review 2007 • Investment 56

In order to encourage competition, some regimes for building storage in Europe incumbent companies who used to build as storage is not subject to regulated storage under the old integrated business third party access under the second gas model are now impeded from investing directive. As with pipeline investment under the same terms. This is positive for in Europe, regulatory institutions seem competition, but negative for investment. focussed on liberalisation as a process, to In a properly competitive Europe-wide the detriment of investment outcomes. market, current demand and supply trends would result in a strong business case for The aggressive expansion of investments storage developers. However, the lack of in North American storage capacity bears gas-on-gas competition in most European testament to the ability of players in markets means that wholesale price liberalised gas markets to make storage seasonality (or volatility) is not present, investments. An increase in storage so the case for independent storage investment in the world’s most liquid investors is weak. They therefore look to market will allow North America to regulators to provide a model whereby increasingly provide storage services to their investment is guaranteed a fi xed the global LNG market. In a globalising return which refl ects the risks of storage market, Japan and Korea will benefi t from development. this investment trend as they have few domestic storage options and have large The comparative lack of storage projects demand for fl exibility services to augment elsewhere in IEA Europe seems to be largely their long-term LNG contracts. caused by national gas markets being stuck “in limbo” between unliberalised and liberalised market design. This means that market actors are not yet suffi ciently separated or suffi ciently specialised to make decisions from the “bottom up”, as in the United Kingdom, nor can they see the fundamentals of the whole value chain from the “top down” perspective of a vertically integrated company as was the case in Germany (until recently). Holding companies owning storage arms receive confl icting incentives across their wide business interests.

In the absence of price signals to act as the glue holding the value chain together, many European players look to regulation as the “sticking plaster” until a competitive market structure is established. However there are few supportive regulatory Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 57

REGIONAL DEMAND & SUPPLY BALANCE TO 2015

This chapter provides an overview of Asia furnished largely by domestic and regional demand and supply balance to pipeline gas sources. Demand rises at the 2015, based on the Reference Scenario of fastest rates in Africa, the Middle East, the IEA World Energy Outlook 2006 (WEO and developing Asia, notably in China and 2006), which projects energy balances over India. The shares of gas in China and India the period until 2030. are expected to grow relatively rapidly, but will remain small, from 3% and 4% in 2004 to 4% and 5% in 2015, respectively. Demand The share of gas in the global primary Primary gas consumption is projected to energy mix stays at the same level in 2015 increase in all regions over the period 2004 as in 2004 at 21%. The IEA’s gas-demand - 2015 in the WEO 2006 Reference Scenario, projections in most regions have been from 2.8 trillion cubic meters (tcm) in 2004 scaled down over the last year, mainly to 3.6 tcm in 2015. Globally, demand grows because underlying gas-price assumptions by an annual average of 2.5% per year. have been raised, creating an incentive The biggest increases in volume terms to use more coal in power generation. occur in the Middle East and Developing Nevertheless, there is considerable

Table 6 World primary natural gas demand in the reference scenario (bcm)

1990 2004 2010 2015 2004 - 2015*

OECD 1 028 1 453 1 593 1 731 1.6%

North America 623 772 830 897 1.4%

Europe 321 534 592 645 1.7%

Pacific 84 148 171 188 2.2%

Transition Economies 767 651 720 770 1.5%

Developing countries 280 680 932 1 143 4.8%

Developing Asia 88 245 337 411 4.8%

China 17 47 69 96 6.7%

India 12 31 43 53 5.0%

Middle East 96 244 321 411 4.9%

Africa 36 76 117 140 5.7%

Latin America 60 115 157 180 4.2%

World 2 075 2 784 3 245 3 643 2.5%

*Average annual growth rate. Source: World Energy Outlook 2006, IEA. Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 58

Table 7 World final gas consumption (bcm)

1990 2004 2015 2004 - 2015*

OECD 714 902 1,018 1.1%

Transition economies 370 274 336 1.9%

Developing countries 130 296 477 4.4%

World 1,213 1,473 1,831 2.0%

Industry 666 681 875 2.3%

Residential, services and agriculture 510 708 856 1.7%

*Average annual growth rate. Source: World Energy Outlook 2006, IEA. potential upside to gas demand if coal Some oil-producing developing countries plants do not progress past the planning continue to encourage switching to gas in phase (for a discussion please see separate order to free up more oil for export. Both “Gas for Power” section). these latter factors are discussed later in sections on Russian and MENA. The use of gas in the power sector increases by 3.1% per year from 2004 to 2015. In absolute terms, gas demand in the power Supply sector increases most in the Middle East, where it is the main alternative to premium priced oil as a fuel. Final gas consumption Resources and reserves grows markedly less rapidly than primary gas use – by 2.3% a year in industry and Gas resources are more than suffi cient to 1.7% in the more mature residential, meet projected increases in demand to services and agricultural sectors. Final 2030. amounted to 180 consumption slows in the OECD because of trillion cubic metres (tcm) at the end of 2005, saturation effects, sluggish output in the equal to 64 years of supply at current rates heavy manufacturing sector and modest (Cedigaz, 2006). Were production to grow increases in population. Demand grows at the 2% annual rate (2.5% in 2004-2015 more strongly in developing countries and and 1.7% in 2015-2030), reserves would transition economies along with rising last about 40 years. Close to 56% of these industrial output and commercial activity. reserves are found in just three countries: Residential gas use nonetheless remains Russia, Iran and Qatar. Gas reserves in OECD modest compared with OECD countries, countries represent less than a tenth of because incomes are often too low to the world total. Nevertheless, worldwide justify the investment in distribution proven gas reserves have grown by more infrastructure. End-use effi ciency gains than 80% over the past two decades, with in the transition economies also temper large additions being recorded in Russia, the growth in residential gas demand. Central Asia, and the Middle East. Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 59

Figure 12 World reserves of natural gas (as of January 2006)

180 Latin America

tcm Africa 160 56% of reserves are found in just 3 countries 140 Qatar 120 Middle East 30% 100 Iran

80 Developing Asia

60 Transition 40 economies 26% Russia

20 OECD OECD countries have less than 1/10 0

Data source: Cedigaz.

Much of the world’s gas reserves have Production been discovered while exploring for oil. In recent years, the larger share of reserve Projected trends in regional gas production additions has come from upward revisions in the WEO 2006 Reference Scenario to reserves in fi elds that have already been generally refl ect the relative size of reserves discovered and are undergoing appraisal and their proximity to the main markets. or development. As with oil, the gas fi elds Production grows most in volume terms that have been discovered since the start in the Middle East and Africa. Most of the of the current decade are smaller on incremental output in these two regions average than those found previously. will be exported as LNG, mainly to Europe and North America. Production is expected In sum, recoverable gas resources including to grow less rapidly in Russia, despite the proven reserves, reserve growth and region’s large reserves; much of that gas undiscovered resources, are considerably will be technically diffi cult to extract and higher than reserves alone. According to transport to market. There are also doubts the United States’ Geological Survey, they about how much investment will be directed could total 314 tcm in a mean probability to developing reserves in the transition case (The United States’ Geological Survey, economies. Developing Asia sees slower 2000), some 75% higher than proven growth, as Indonesia struggles to develop reserves. Cumulative production to date its reserves for export to other countries in amounts to only around 15% of total the region. Europe is the only region which resources. experiences an absolute drop in output Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 60

Table 8 World natural gas production in the Reference Scenario (bcm)

1990 2004 2015 2004 - 2015*

OECD 879 1128 1205 0.6%

North America 641 756 820 0.7%

Europe 211 328 312 -0.5%

Pacific 27 44 72 4.6%

Transition economies 841 802 964 1.7%

Developing countries 362 874 1517 5.1%

Developing Asia 131 304 422 3.0%

China 17 47 69 3.6%

India 12 28 43 4.0%

Middle East 100 283 600 7.1%

Africa 69 158 277 5.2%

Latin America 62 129 217 4.8%

World 2082 2804 3686 2.5%

*Average annual growth rate. Source: World Energy Outlook 2006; IEA, Natural Gas Information 2006, IEA. between now and the end of the projection Natural Gas: Reform and Climate Change, period, as North Sea production peaks early IEA 2006; Towards a World Free of Flares, in the next decade and gradually declines World Bank, 2006). thereafter. In aggregate, annual world production expands by almost 0.9 tcm, or Non-conventional gas production, including 31%, between 2004 and 2015. coal-bed methane (CBM) and gas extracted from low permeability sandstone (tight Most natural gas supplies will continue to sands) and shale formations (gas shales), come from conventional resources. The increases signifi cantly in North America. share of associated gas is expected to The United States is already the biggest pro- fall progressively as more non-associated ducer of non-conventional gas, mainly tight fi elds are developed to meet rising demand, sands gas and CBM from Rocky Mountains. despite a further reduction in amount of Together, they currently amount for about associated gas fl ared. Several countries, 10% of total United States’ gas demand. especially in the Middle East and Africa, In most other regions, information on the are implementing programmes to reduce size of non-conventional gas resources is gas fl aring. Around 150 bcm of gas is sketchy. In some cases, there is no incentive fl ared each year, mostly in the Middle East, to appraise these resources, as conventional Nigeria and Russia (Optimising Russian gas resources are large. Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 61

In general, the share of transportation in including Russia, for the top spot of the total supply costs is likely to rise as reserves largest regional supplier to Europe. In light located closest to markets are depleted and of current investment plans, there are supply chains lengthen. Pipelines will remain doubts about whether Russia will be able to the principal means of transporting gas in raise production fast enough to maintain North America, Europe and Latin America. current export levels to European markets LNG is set to play an increasingly important given rising domestic needs and potential role in gas transportation worldwide over sales eastwards. China currently obtains the projection period, mainly to supply gas supply from Australia and is expecting Asia-Pacifi c and Atlantic Basin markets to take deliveries soon from Indonesia. but increasingly as the glue which binds After 2012, possibly Russia and Central regional markets together. Asia may supply gas to China. Russia is also expected to begin exporting gas to OECD Inter-regional Trade Pacifi c by 2008 from Sakhalin.

The geographical mismatch between re- Pipeline gas continues to be traded on source endowment and demand means a largely regional basis, as there are few that the main gas-consuming regions large physical connections between the become increasingly dependent on im- main regional markets of North America, ports. In volume terms, the biggest Europe/Russia, Asia-Pacifi c, Middle East increase in imports is projected to occur and Latin America. Despite the lack of in OECD Europe. Imports in that region physical interconnection, these markets increase by 120 bcm between 2004 and are already beginning to integrate as trade 2015, reaching 333 bcm – more than half of in LNG expands. In this way LNG can be inland consumption. North America, which seen as a virtual interconnection between is largely self-suffi cient in gas at present regional markets. Increasing LNG trade will also emerges as a major importer. By 2015, expand integration, leading to a degree imports to North America – all of which are of convergence of regional prices. LNG in the form of LNG – meet 9% of its total accounts for almost 70% of the increase gas needs. Chinese gas imports also grow in inter-regional trade since 2004. Inter- from around 1 bcm in 2004 to 27 bcm by regional exports of LNG grow from 90 bcm 2015. The country’s fi rst LNG terminal, with in 2004 to 150 bcm in 2010 and 200 bcm in a capacity of 6 bcm per year (3.7 mtpa) was 2015. Total liquefaction capacity worldwide commissioned in 2006. Nonetheless, gas still is expected to grow from 242 bcm per meets only 4% of Chinese energy needs by year in 2005 to 600 bcm in 2015 if all the 2015, marginally up from 3% today. projects under development are completed on time (though some will undoubtedly be The Middle East and Africa account for delayed or cancelled – see separate section the majority of the increase in global on Investment). exports between 2004 and 2015. The bulk of the exports from these two regions go North America is expected to see the to Europe and the United States. Africa biggest increase in LNG imports over the contends with the transition economies, period between 2004 and 2015. All the Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 62

LNG destined for the United States market gas based on spot markets, and LNG to is likely to respond to short term price the Pacifi c market is likely to be based trends rather than be fi xed volumes on on a combination of oil indexed and hub long term contracts. This will mean that prices. The interaction between global North America makes a large entrance on, and regional LNG and pipeline fl ows is and contribution to, the globalising gas globalising the markets. market.

Taking a more conservative view of LNG Supply and demand development, output by 2015 could be summary to 2015 “only” some 440 bcm, still a massive growth. Of this, 80 bcm is likely to go to OECD North America, 160 bcm to OECD OECD regions will increase their dependence Pacifi c and Chinese Taipei, some 40 bcm on interregional imports of gas from to China, India, and Thailand and the 23% to 30% (from 328 bcm to 526 bcm). remaining 160 bcm to Europe. LNG imports Dependence on LNG will grow from 11% to to Europe will interact with pipeline gas between 17% and 22% (from 164 bcm to sold on oil and hub prices. LNG imports to between 302 - 382 bcm). North America will interact with pipeline

Figure 13 Summary of inter-regional natural gas trade in the Reference Scenario

4 000 Interregional bcm pipeline 3 500 Latin America imports Africa Interregional imports unknown modes LNG could meet LNG Middle East 9-13% of world 3 000 Interregional total demand pipeline Latin America imports Developing Africa Asia 2 500 Middle East LNG Consumption Developing in transition Asia Transition economies & Consumption economies 2 000 developing in transition Transition countries economies & LNG dominates economies developing in Pacific countries 1 500 Europe Pacific ’s import dependence grows from 1 000 Europe 40% to 52% OECD OECD North domestic In domestic America 500 production ,LNG production North consumed grows from consumed America within 2% to 9% of within total demand 0 2004 2015

Source: World Energy Outlook 2006, IEA; Natural Gas Information 2006, IEA. Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 63

Figure 14 OECD North America gas outlook

bcm 800

600

400

200

0 2004 2010 2015 Regional production LNG imports

Source: World Energy Outlook 2006, IEA; Natural Gas Information 2006, IEA.

Assuming a modest increase in the also upstream investment in traditional United States gas production over the pipeline suppliers and demand growth period, as predicted by the United States elsewhere (such as China). and Canadian government agencies, OECD North America’s depen-dence on The OECD Pacifi c region dependence on interregional imports (in the form of LNG) LNG (both interregional and intraregional will grow from 2% to 9% (from 18 bcm imported) will grow from 74% to 77% to 77 bcm). Should North American gas (from 109 bcm to 145 bcm) as demand production not increase to the extent growth in Japan and Korea outstrips projected, obviously demand on LNG growth in the domestic pipeline markets markets will tend to increase. of Australia and New Zealand.

OECD Europe’s dependence on interre- As a result of the massive investment gional imports will grow from 40% to 52% already sanctioned in global LNG supplies, (from 214 bcm to 333 bcm). Its dependence the dependence of global gas demand on on imported LNG will grow from 7% to LNG will grow from 6% in 2004 to between between 12% and 24% (from 37 bcm to 10% and 12% by 2015. In the context of a 80 - 160 bcm). OECD Europe will however global gas market expanding at some 2.5% see its import demand satisfi ed by both per annum, LNG is expanding very quickly. LNG and pipeline gas, so the growth in LNG imports themselves depends not only on LNG production developments, but Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 64

Figure 15 OECD Europe gas outlook

bcm 600

400 LNG: 60-100 Bcm in 2010, 80-160 Bcm in 2015

200

0 2004 2010 2015 Regional production LNG imports Pipeline imports

Source: World Energy Outlook 2006, IEA; Natural Gas Information 2006, IEA.

Figure 16 OECD Pacific gas outlook

bcm

150

100

50

0 2004 2010 2015 Regional production LNG interregional imports LNG intraregional trades

Source: World Energy Outlook 2006, IEA; Natural Gas Information 2006, IEA. Natural Gas Market Review 2007 • Regional Demand & Supply Balance to 2015 65

Figure 17 Possible LNG sales by region: one scenario

420-440 bcm bcm in 2015 400 Developing Asia

OECD North America 300 This portion could be either LNG or pipeline 80-160 bcm imports into OECD for Europe Europe 200 Developing Asia OECD Europe OECD North America OECD Europe 100 OECD Pacific OECD Pacific

0 2004 2015

Note: Possible LNG imports into Latin America are not included. Source: World Energy Outlook 2006, IEA, Natural Gas Information 2006, IEA.

Natural Gas Market Review 2007 • Gas Security 67

GAS SECURITY

Recent supply disruptions Because of this, the North American market has a well interconnected, web-like in IEA countries structure. Prices and price expectations at hubs on the transportation web are the Recent supply interruptions in a number signal used by suppliers and consumers to of IEA regions, plus growing reliance determine their actions. For example, as on imports over longer distances, are price decreases at a hub, so producers scale rekindling a debate on energy security, back production and consumers increase including available responses to short- consumption. As prices of gas decrease, term, or even medium term disruptions. consumers burn gas in boilers instead of Sharp or sustained increases in demand oil and decrease coal-fi red generation in can produce similar effects to reduction of favour of power generation from gas. Price supplies. Such increases in demand can not differentials between hubs can signal the only be driven by extreme cold weather need for more interconnection. which leads to a rise in gas demand for space heating, but also extreme hot Gas can be freely traded between the hubs weather leading to a rapid rise in gas-fi red on the gas pipeline network, so the effects power demand to run air conditioners. of the hurricanes in the Gulf of Mexico late in 2005 were spread throughout the North In the absence of additional supply to a American gas market. The loss of 147 mcm region (either through unused production per day gas supply (equivalent to 10% or import capacity–including LNG), the of North American consumption) would principal response to a supply disruption have been devastating to the affected is to temporarily decrease gas demand. In region were it not for this sharing effect, competitive markets demand reduction for example it would have lead to a loss of happens automatically as gas prices in- 62% of gas supply to Texas if confi ned to crease, whereas in non-competitive mar- just that market. kets demand must be reduced through administrative means. In the examples However, prices did rise substantially, outlined below, countries or regions suf- initially to around USD 14 and then fered supply shortages from a variety of USD 15/MBtu, about double previous prices. factors, and managed them in different The principal response to a supply disruption ways. in the North American market was demand reduction by users. Industrial demand in IEA North America the United States after the hurricanes of 2005 was lower by approximately 68 mcm The IEA North American gas market is per day compared to the previous year, fully integrated across both IEA member due to these high prices, notably in the countries – the United States and Canada. chemical sector. Residential consumption This means that gas moves across the also decreased, but this is more diffi cult region towards areas of higher price. Price to attribute to the effects of higher prices signals are determined by the supply and rather than temperatures, because domestic demand of gas at any given time, so any gas use tends to rise and fall strongly with predicted or existing structural bottleneck the ambient temperature. Also price lags is usually resolved over the medium term in this sector can often be substantial, so by new investment in pipeline capacity. immediate effects are muted. Natural Gas Market Review 2007 • Gas Security 68

While the United States market did not Niigata, Kagoshima). In such a situation, manage to attract extra supply in the the affected Japanese consuming area may form of LNG cargoes, the effects of the make use of an emergency plan to ration supply disruption were felt by most LNG the use of gas locally, particularly drawing importing countries. The price of gas in the on power companies to switch from using North American market became the “price gas to oil. In emergencies, some of the to beat” for any company worldwide to smaller gas companies can manufacture import spot LNG cargoes. Thus, Japanese, gas from naptha or LPG, while the larger Korean and Spanish buyers tended to pay companies consider that they have access higher gas prices for LNG imports in order to well diversifi ed LNG terminals. to out-bid the North American market. In recent years, long-term supply from Indonesia, previously the world’s biggest IEA Pacifi c LNG producer and the major Japanese supplier, has fallen below annual contract Japan and Korea receive almost all their levels by at least 10%. These supplies have gas, as they do oil, by tanker. Japan has been successfully replaced by supplies substantial import capacity at 26 LNG obtained from the growing LNG spot terminals (230 bcm per year), and Korea market. This in turn has been made possible has 4 terminals (77.4 bcm per year). This by mild weather in other IEA markets, capacity offers great fl exibility in the which has freed up LNG from the Atlantic case of an upstream gas supply disruption Basin for delivery to Pacifi c markets. because it is over double total demand (Japan, 85 bcm per year and Korea 30 bcm In Australia, disruptions at gas processing per year, 2005). Emergency plans exist in facilities have impacted on gas supplies. both of these countries in the case of an In 1998, an explosion at the Longford import problem in order to share remaining gas facility caused rolling gas supply supply between different demand centres. interruptions affecting approximately The emergency plans of both countries 1.3 million households and 89 000 busi- include large scale fuel-switching by power nesses across Victoria, parts of South generation companies to save gas and use Australia and New South Wales over a more oil. This would ensure a basic level two-week period. The economic impact of of gas imports to each of the regional gas gas supply rationing was signifi cant. Over markets, although the effect on the global 150 000 workers were stood down during oil markets could be signifi cant. the crisis and resulted in an estimated cost to Victoria of USD 1 billion (or 1% of Gross Japan lacks a national pipeline network State Product). Export earnings were cut which would interconnect its consuming by USD 150 million. areas such as exists in Korea (although Korea is admittedly smaller). The possibility On 1 January 2004, a gas leak and fi re of a signifi cant disruption at one LNG shut down production at the Moomba terminal in Japan therefore poses potential gas plant, in northern South Australia. supply security issues for the area served Production at the plant was returned to by that terminal. While most Japanese full capacity by 14 February 2004. In this consuming regions have access to more case, new interconnections for both gas than one LNG terminal, some do not (e.g. and electricity were available between Natural Gas Market Review 2007 • Gas Security 69

South Australia and the state of Victoria, plant closures by administrative decree, and supplies of both power and gas were temporary relaxation of environmental maintained throughout the Moomba plant standards to allow fuel oil to be burnt, and outage without rationing. This highlights gas rationing. the importance of interconnection for smaller consuming regions, and also Over the same winter 2005/06, the the potential role of electricity and grid United Kingdom encountered supply interconnection in gas security. shortages, as cold weather coincided with an unexpectedly rapid fall in domestic IEA Europe production. Late in the winter, a fi re at the country’s major gas storage facility IEA Europe is in the middle of a transition exacerbated the situation, and saw to a North-American-style competitive prices spike to USD 30/MBtu. In response, market, with the most advanced countries industrial demand was curbed, for example located in North West Europe (NWE - United in fertiliser production, glass making and electricity production which shifted to Kingdom, Belgium and the Netherlands) coal. Gas-fi red power consumption was and the Iberian Peninsula (Spain and down almost 3%, with a corresponding Portugal). The bulk of continental Europe rise in coal-fi red power, in the context of remains dominated by long-term take- year-on-year electricity market growth of or-pay contracts, with prices adjusted about 2%. Coal use continued to grow in periodically, linked to oil. Hence any price 2006. Import infrastructure was in place response to shortages is at best muted, but contractual issues limited its use, or even non existent. The weak (or in at least initially. High prices have been a some cases non-existent) interconnection powerful incentive to expand importing between European countries means that infrastructure rapidly, which has indeed they have been affected more severely occurred in 2006 and early 2007. Curiously, by gas supply shortages than would have the high prices did not draw incremental been the case in a strongly connected gas from the lower-priced continent, market such as North America, despite unused transportation capacity linking the two markets. An example of such a shortage was seen in Italy over the winter of 2005 and 2006, where a combination of cold weather and higher Gas storage use of gas-fi red power led to a daily shortfall of up to 10% of demand, or around 40 mcm Gas storage is the physical stockpiling of per day. In the context of total European natural gas. It is used by gas companies to gas demand some 50 times larger than this match variations in supply with variations shortfall, this was relatively small, but the in demand. The variations of supply with weak interconnectivity and poor market demand occur over different timescales fl exibility (for example gas prices cannot and so are matched using different forms respond to higher demand from the power of storage. sector) meant Italy suffered gas shortages which had to be met by emergency meas- At LNG receiving terminals, tankers arrive ures. These included fuel switching and every few days to discharge their cargoes Natural Gas Market Review 2007 • Gas Security 70

of LNG into short-term6 storage tanks, from Low probablility: where it is turned into a gas and sent out to high impact events consumers at a more constant daily rate. Despite the relatively predictable nature of Gas demand increases in the evening gas use, there is always a small chance of an (for example from cooking) or to meet event with a high impact. Some IEA countries peak power demands, so short-term have rules to ensure that the industry/ underground storage is used to increase market is able to cope with a particularly supply or to increase provision to gas- cold winter – for example a “one-in-fi fty” fi red power stations. These daily or diurnal standard ensures that companies plan for a variations are relatively predictable. recurrence of the coldest winter in the last fi fty-year period. In such a situation, there Over the course of a year, a regular fl ow would be demand for more gas for heating of gas imports does not fi t the increased purposes and therefore a greater demand domestic use of gas in the winter compared for seasonal gas storage. with decreased use of gas in the summer (seasonal variation) – this variation is However, no reasonable company would matched using underground seasonal invest in an asset which is only productive storage. LNG storage can also be used to once every fi fty years. A gas company cope with periods of peak demand. therefore needs an externally imposed incentive or obligation in the form of a In fact, gas storage is one of a range of reliability standard in order to invest in fl exibility services that can be used in extra storage which may only be used order to match supply to demand of gas. irregularly, e.g. once in fi ve decades. In Gas producers can themselves provide the Netherlands, companies are obliged fl exibility services, called “swing”, by to perform to a temperature standard, producing gas at either a higher or lower with the Transmission System Operator production rate. Customers can also charged with the responsibility of in- provide fl exibility services, by agreeing cremental gas provision between minus to be interrupted a few times per year in 9 and minus 15 degrees Celsius. return for lower priced gas supplies – these are interruptible contracts (see below). Governments or regulators are in a good position to weigh the cost and benefi t Fortunately, the broad demand patterns of to society of such reliability standards. gas use are relatively predictable, so average A higher standard will result in greater winter or evening demand is to be expected investment but at a greater fi nancial burden by any gas company. Over the course of on consumers, for it is the consumer who several years, there are also some changes in pays in the end for this protection. Within use – for example, there is a tendency across a competitive market, a reliability standard many countries for greater use of gas in works by requiring all companies to plan summer as air conditioning is often powered for a more severe winter than they would by electricity generated from gas. if there were no standard – this increased

6. LNG inventories are increased and decreased to manage daily fl uctuations in supply and demand. They are not completely emptied, as removing all the -160oC liquid would let the tanks warm up to ambient temperature. In some countries, there is surplus LNG tank capacity which enables a substantial working inventory all year round. Natural Gas Market Review 2007 • Gas Security 71

demand drives up the price for fl exibility re-develop depleted fi elds, particularly services. In turn, more fl exibility will be those held by incumbent gas producers. contracted and more storage will be built. Production licenses are diffi cult to trans- form into gas storage licenses and rules If a minimum reliability standard exists in for upstream operators are often very a country, it is essential that companies different to rules for storage operators plan adequately for that event. The market in the wholesale market. Part of the will not plan adequately if it believes that challenge for governments is to streamline a government would intervene to ensure procedures to lower these barriers. extra supplies if such an event were to Governments also need to recognise their occur. For example, if a one-in-fi fty standard increased role in competitive markets exists and a one-in-fi fty winter occurs, it to ensure that detailed demand and is essential that companies understand supply data is available to the market so that they will have to cope on their own potential investors can increase security without external intervention. Where the for consumers by building commercial gas markets of two or more countries are storage. NIMBY issues for onshore storage linked, it is advisable to harmonise these should also not be underestimated, and rules to avoid preferential supply of one set need to be addressed. of customers at the expense of another. The logic for increased commercial storage Normal market conditions investment is strengthening as IEA regions and commercial storage import more gas over longer distances, because the loss of domestic production As defi ned by the government, the mini- capability usually means loss of the mum standard becomes normal market associated ability to increase or decrease conditions. The amount of gas storage production in line with demand (so called which must be contracted by market players swing production capacity, as seen for in order to operate under normal market example in the United Kingdom). As more conditions is referred to as commercial gas is used in the power sector, there is also gas storage. A favourable investment cli- increasing demand for shorter cycle gas mate for commercial storage is essential storage, such as salt caverns, in addition in order to encourage companies to make to the more common depleted fi eld these investments at the right time with storage better suited to meeting seasonal the right mix of technologies. As import variations. Regions which do not have the dependence grows in IEA regions, it is geological potential for domestic storage expected that more commercial storage are investing in facilities in those that do. should be built. Furthermore, as IEA countries move towards competitive gas Commercial storage investment markets, governments have a strong role to play in ensuring that the commercial However, governments can unintentionally incentive to build storage is not diluted by undermine commercial drivers, resulting barriers to investment. in underinvestment in commercial gas storage. In competitive markets, future Across IEA countries, potential storage daily or seasonal price volatility is the investors argue that there are some primary signal for storage investors – it regulatory reasons they are not able to is also their source of revenue. Therefore Natural Gas Market Review 2007 • Gas Security 72

government action to cap prices or the North American market can store artifi cially reduce volatility will increase more gas per unit consumption (1:5) that the risk of underinvestment. IEA Europe (1:7) or IEA Pacifi c (1:12) regions. The IEA European region - considered as a If governments decide to put in place whole - encompasses countries with high strategic gas storage, all players must storage per unit consumption and those have a clear idea of what release policies with low storage per unit consumption. will be adopted. If there is a perception Nevertheless, as progress is made towards a that governments will release strategic European gas market, the regional average gas stocks in normal market conditions, is more relevant than country-by-country this would introduce a substantial risk of data. IEA Pacifi c region has markedly underinvestment in commercial gas storage. less storage per unit consumption than This underlines the need for Governments other IEA regions as the two largest gas to impose clear responsibilities on market consumers, Japan and Korea lack suitable players and operators, within which it is a sites for underground storage. commercial responsibility to address supply From the perspective of market design it is issues (see Investment section). interesting that the North American market, which relies only on spot gas markets to The fi gure below shows the annual provide investment signals for storage consumption of gas in the three IEA development, has the highest degree of regions and the volume of working gas commercial storage per unit consumption storage in each. As can be seen from the of any IEA region, despite also having the ratios of consumption to stored volume, lowest degree of import dependency.

Figure 18 IEA regional gas consumption and volume of commercial gas stocks by region, by type

711 795

mcm 300 000 524 600

200 000 Total 148 554 storage

Total 100 000 storage

Total storage 0 IEA North America IEA Europe IEA Pacific 1:5 1:7 1:12 Annual gas demand Aquifer Depleted gas/oil field Salt cavern LNG

Source: IEA Database. Natural Gas Market Review 2007 • Gas Security 73

Strategic gas stocks: A survey of investment in underground commercial gas storage facilities currently what are they? under construction suggests that the initial, capital cost of gas storage is Strategic gas stocks are physical stockpiles between fi ve to seven times the cost of 8 of natural gas which are not available underground oil storage facilities per toe to the market under normal conditions. stored. The capital cost of LNG storage Because they are not part of the gas facilities currently under construction is market, strategic gas stocks are normally approximately ten times the cost of stocks owned and/or controlled by governments7 in oil tanks or approximately fi fty times who judge that they want to protect the cost of underground oil storage per consumers against a non-market risk. A toe stored. Capital costs of gas stocks are non-market risk is defi ned as a risk that therefore much more expensive than oil cannot be expected to be covered by the stocks. market under normal conditions. A non- Assuming suitable sites could be found, market risk therefore falls outside the the total capital cost of constructing reliability standards for a particular market. facilities necessary to hold 90 days9 of A simple example of a non-market risk in a net gas imports in 2015 would be in the country with a reliability standard of a one order of USD 54 billion (in 2005 USD). The in fi fty winter is the development of winter cost of purchasing gas (or LNG) to fi ll these conditions more extreme than that. storage facilities would be approximately USD 40 billion (at average 2005 IEA gas Besides protecting against particularly prices). While it might be argued that cold winters, strategic gas stocks are commercial stocks already provide a part also understood to offer protection for of that fi gure, the previous discussion consumers against non-market supply has explained why commercial and stra- disruptions. Such supply disruptions may tegic stocks should be separated. In fact, be caused by freak weather conditions, commercial stocks rarely exceed two such as hurricanes Katrina and Rita in months supply, and are often well below the US which caused the release of IEA that in some countries at some times of the countries’ oil stocks in September 2005. year. Gas stocks in Belgium, when full are Strategic gas stocks in themselves are only equivalent to two weeks’ consumption. one way of providing fl exibility beyond According to IEA research, variable normal market conditions. They are often costs for maintaining gas in storage viewed as the “equivalent of strategic oil are also signifi cant. The variable cost stocks” where in fact gas and gas storage of maintaining enough gas in strategic differs markedly from oil. One of the key storage to satisfy a 90-day net import differences from the point of view of the standard across the IEA is USD 5.4 billion user is the difference in cost. per year (2015 capacity). Variable costs

7. Though they are often provided by companies, eg through government tendering process. 8. Toe = Tonne of Oil Equivalent. An energy equivalent of one tonne of oil. 9. Assuming countries without geological sites built LNG tanks; 90 days is a period chosen for example. Natural Gas Market Review 2007 • Gas Security 74

for gas storage are determined by various ground” between these extremes, as the economic factors such as interest rates, injection and withdrawal rates are higher maintenance, and cost of personnel, but than depleted fi elds but the costs are lower also include another factor specifi c to gas than for LNG. However, salt storage is only storage – gas leakage. Gas leaks at slow possible where large salt deposits exist. rates from high pressure underground storage but the rate differs depending As with IEA oil stocks, it is likely that a mix of on the geological structure. Commercial fast and slow withdrawal gas storage would storage sites undergo a full cycle of fi lling be needed in order to enable a complete and emptying at least once a year, so it is strategic gas storage capability with a diffi cult to estimate the rate of leakage for range of withdrawal rates. Building a range a gas facility which may be full for several of storage types including salt caverns years before being needed. We have used would increase the cost of constructing a leakage rate of 2% per annum, which we storage facilities for an equivalent volume consider to be conservative. of gas beyond USD 54 billion.

It is worth also noting the practicalities of putting in place such massive gas storage Why do gas stocks cost – it would take a long time and have an appreciable impact on the global gas so much more than oil? balance. Absolute minimum lead time for conversion of a depleted fi eld into a storage The principal reasons that gas stocks are so site is two to three years (onshore and expensive compared with oil are two-fold. offshore respectively). The volume of gas Natural gas, like any other gas, needs to needed to fi ll enough storage for 90-days be fully contained at all times to prevent net imports for all IEA countries in 2015 is it mixing with the air and/or escaping. As equivalent to the entire 2008 combined well as needing confi nement, natural gas gas exports of both Canada and Norway. has a lower energy density than oil which Of course, the additional demand for fi lling means that, at standard temperature this storage requirement is likely to be best and pressure, a volume of gas contains met by new greenfi eld production, but much less energy than the same volume new project development takes almost a of oil. To be economic for storage, the decade from proven reserves to fi rst gas.10 energy density of gas must be increased The release rate of gas from existing – gas must therefore be stored either commercial depleted fi eld storage at very high pressures or at low-enough sites is similar to the release rate of oil temperatures that it forms a liquid. from underground strategic storage, approximately 1-3% of total volume per High-pressure environments require special- day. Similarly to oil tanks, LNG tanks have ist materials such as thick steel pipelines much higher release rates of up to 50% per and powerful compressors. When using day. Gas storage in salt caverns is a “middle depleted fi elds for gas storage, the pressure

10. The largest IEA green-fi eld gas project due to commence production in 2007 is Ormen Lange whose reserves were proven in 1997. This development cost some USD 10 billion and will account for approximately a quarter of Norwegian exports in 2008. Natural Gas Market Review 2007 • Gas Security 75

of the fi eld has to be maintained at all times Why are gas stocks less otherwise the geological structure could be altered. This means that even when the fi eld effective than oil stocks? is technically empty of working gas it must have suffi cient gas in store to maintain There may be a few specifi c risks that high pressure. The volume of gas left in a countries decide that they want to gas storage site emptied of useful working ensure against, for example one part of gas is referred to as the “cushion gas”. The the gas system regarded as particularly volume of cushion gas required to develop a vulnerable. Where this is the case, then large underground storage can account for strategic stocks can be built to guard up to half the cost of the investment. against the specifi c risk; for example to Cooling gas to liquid form (-160oC) requires manage risks of a supply disruption to a considerable energy and confi ning it major trunk pipeline system or damage requires specialised materials such as to a particularly important part of the gas nickel/steel alloys. At -160oC natural gas is supply infrastructure. If geology allows, a boiling liquid, so small amounts escape as a storage site can be selected near the off-take point of such a pipeline system, a gas. Cooling the gas back to a liquid and designed specifi cally to match the nature returning it to store uses energy, and adds of a potential disruption. In these cases, to costs. In some cases the “boil-off gas” is gas storage could be extremely effective consumed for useful purposes instead of in mitigating specifi c risks. Nevertheless, being re-liquefi ed, but in that case it must strategic gas storage suffers from some of be replaced - again adding to costs. the disadvantages of strategic oil stocks – namely that suitable geology must be Handling diffi culties mean that gas needs found for underground facilities and that specialised equipment to get it into or out strategic stocks carry a risk of discouraging of store. Operating costs for gas storage investment in commercial storage. are also well beyond those of oil storage, but it is diffi cult to give a range because In order to address a wide spread of risk this depends on the cost of energy to drive factors, encompassing the increased volume compressors and pumps. and distance of imports, it is important to recognise that strategic gas stocks may be The cost of purchasing the gas to fi ll the less effective than strategic oil stocks. These store is considerably lower than the capital arguments have been summarised below. cost of constructing the facilities needed Downstream gas transport is always to hold it. The price of gas is usually similar performed by fi xed infrastructure. to, or slightly lower than the price of crude Strategic gas storage will therefore be oil (per ton of oil equivalent) but actual ineffective if transport infrastructure prices depend on various factors including is damaged between the storage site the consuming country and the time of and the customer. This argues for year. placement of strategic storage near to consumption centres. Natural Gas Market Review 2007 • Gas Security 76

Example: While there are many downstream to release gas storage across for the oil distribution pipelines in use, a large benefi t of the region. scale disruption to one could be isolated Excess gas transportation is more and replaced with tanker trucks. Smaller expensive than oil transportation. This oil leaks can be detected much more easily means that strategic gas storage would than leaks on gas pipelines since gas leaks have to use existing gas transportation just escape into the atmosphere. Repairs to infrastructure, so more strategic storage oil pipelines are also less costly than repairs sites are required to cover every potential to gas pipelines because of the elevated supply disruption. pressure of the gas system. Gas is rarely transported to consumers in trucks, which Example: The largest LNG tanker is the means that the distribution system is less “Qatarmax” class vessel which costs four resilient. Where oil tanker trucks are used to fi ve times more than an oil tanker instead of pipelines the loss of a tanker carrying a similar amount of energy, e.g. truck will hardly affect the distribution of Aframax (USD 65 million). On a small scale, oil. If any part of a major gas trunk pipeline increasing the capacity of a gas distribution is destroyed, supply downstream to a whole network is much more expensive than region is stopped until the damage can be building a series of petrol stations. Long repaired or the pipeline replaced, alternative distance gas pipelines have to withstand arrangements by road are not an option. far greater pressures than oil pipelines, Gas transport is less capable of being which also makes them up to fi ve times scaled-up than oil transport. While more expensive. Building surplus gas there is an option of building dedicated infrastructure costs much more time and infrastructure for use only by strategic money than oil. Repairing damage to gas gas storage, the ideal location for infrastructure is similarly more costly. gas storage is much closer to the consumption site than for oil. Fixed gas installations, which might be damaged by extreme weather events, Example: At times of extreme oil demand, cannot be easily bypassed. This means more oil trucks can deliver more oil to that strategic storage must be physically petrol stations via the road system. built near to physical interconnections Moreover, there are generally empty of major pipeline systems or that tanker trucks available at any one time in expensive physical interconnections any one region. At times of normal winter must be built near to strategic storage. peak gas demand, underground pipelines cannot carry much more gas. It is therefore Example: Oil has a much more robust much more diffi cult to increase the and interconnected infrastructure than amount of gas distributed to consumers does gas; oil receiving ports, storage sites in times of crisis than it is to deliver more and refi neries can be lost to the regional oil to consumers. If the disruption is due distribution system and replaced to a to action by a producer, then oil stores in certain extent by increased transportation the consuming country can be mobilised to or from other installations. The loss of to any demand centre. If upstream gas one gas distribution pipeline can not be supplies are disrupted, poorly interlinked replaced by quickly building an alternative. markets, such as Europe would be unable In order to isolate a damaged gas facility Natural Gas Market Review 2007 • Gas Security 77

or gas pipeline, the market must be very competitive markets, where market based well interconnected to other potential mechanisms can act as policy levers to supply sources via a web of pipelines. In create an optimum balance. this respect, the physically interconnected North American and Korean markets and Supply response the Japanese market, interconnected by LNG, are better off than the largely Gas markets with access to spare import national markets of the IEA European capacity from LNG terminals or unused region, with its limited physical and pipeline capacity might be able to benefi t contractual interconnectivity. from some type of supply response to a gas Summary. Gas stocks are not as effective emergency if contractual circumstances a solution to general supply disruptions permit. as are oil stocks, though they may be well suited to mitigate specifi c risks in In the pipeline market, this response would certain countries or as part of a suite of rely on their being unused pipeline capacity other measures. with associated production fl exibility. IEA Oil stocks can quickly be released in the Europe for example, had a total import 11 case of an emergency from any site to capacity of over 350 bcm in 2005, yet only cover a supply shortage anywhere within received imports of slightly over 200 bcm. a reasonable distance and can rely on a Some of this import capacity can be used by fl exible transportation system to bring the capacity owner to increase purchases from upstream suppliers, if supply is them to local or even global markets. Even available and contractual conditions allow. in well interconnected gas markets, stocks could not rely on such an extensive global In the LNG market, a supply response would transportation network. This means that have to rely on purchase of additional LNG gas stocks might not be in the right place tanker cargoes as most LNG contracts to manage a supply disruption. specify limited buyer fl exibility (this is changing slowly – see LNG chapter). There What are the other options are two sources of available LNG cargoes: The “spot” LNG market. besides strategic stocks? LNG cargoes diverted from original destination by agreement of stakeholders. Where markets are liberalised, prices can rise in the event of disruptions, producing both supply and demand side responses As the LNG spot market expands, a fl exible in the market. In the absence of such supply response is possible into each markets, different tools will be required. regional IEA market. Spare LNG receiving Even when markets are working well, capacity was present in all IEA regions governments may use some of the tools in 2005 and is expanding. With spare discussed below where economies may capacity, regions could buy gas from be severely damaged. Many of these tools the uncommitted “spot” LNG market. will also be present in well functioning, However, this market is global, meaning Natural Gas Market Review 2007 • Gas Security 78

that increased buying by one region supply emergency. Where gas markets reduces supply in the other two. In the rely on LNG supply response in case of a event of a supply disruption, the “spot” supply disruption, careful evaluation of LNG market might not be large enough to this global market is needed in order to meet demand, and so reliance on the spot understand the international linkages market alone is likely to be insuffi cient for between buyers and sellers which have major supply shortages. made the LNG market what it is today.

It must be remembered that the LNG The gas market has a history of strong market is growing in size and fl exibility collaboration between buyers and sellers, even outside of the spot market. In 2005 so dialogue with producer countries is it was already fl exible enough to handle vitally important. As more gas is traded large-scale disruptions to traditional worldwide, it is increasingly important for contracts such as those resulting from the globalising industry to get transparent, the Indonesian supply shortfall – 11% reliable information about investment of cargoes from the worlds largest LNG and production plans. Dialogue with producer were replaced in this way. producing countries in order to secure supply fl exibility is as important in gas Most LNG production trains run at less than markets as it is in oil markets. 100% capacity, but it is possible within the framework of existing long-term Demand response LNG contracts for customers to request that suppliers increase production. Where One way of rationing the use of gas with traditional relationships are in place, predictable economic impact is through this arrangement can increase the total demand response. Demand response volume of LNG supplied to the buyer. LNG occurs when customers decide to modify cargoes can also be released from servicing their consumption depending on the their normal obligations under long-term price of gas in a market. Two examples contracts and diverted to alternative (explained below) of such a response destinations, if both buyers and sellers might be chemicals manufacturers, e.g. agree. This would, in effect swap cargoes in the fertiliser industry, and merit order from the long-term contract market into fl exibility in the power market. the global “spot” market, but would only be a net gain in supply if the buyer was There is a global market for industrial also able to decrease domestic demand. chemicals such as fertiliser, so by comparing the global sales price to the price of A combination of demand reduction production, a company can decide to in unaffected regions, plus increased temporarily stop making fertiliser locally; production and cargo diversion could switch production to an offshore plant and constitute a global LNG response to a import the product or buy fertiliser from

11. Source: Gas Infrastructure Europe (GIE) and IEA data. Natural Gas Market Review 2007 • Gas Security 79

the global market and deliver locally. This measures might need to be considered to appears to have been the major response promote demand reduction in sectors not mechanism in the North American market exposed to short-term price changes. after the hurricanes in 2005. Interruptible customers Another example of this behaviour is in the power sector where changes in the These are industrial customers who consume relative price of fuels (coal, gas and oil) can large volumes of gas per year and agree result in changes in the merit order. This to have their gas supply interrupted for a means that (all other things being equal) maximum number of days in a year in order as gas prices rise, there is a preference to to obtain a reduction in gas price. On average, reduce gas demand and increase power customers with these contracts agree to a generation from coal, oil or nuclear units maximum of 10-20 days of zero supply (if where spare capacity exists. In effi cient necessary) in a year. Whilst interruptible power and gas markets, it is possible to customers are certain to have their gas get good demand response to a gas crisis supplies cut in a supply disruption, the as higher gas prices reduce consumption. volume saved is unlikely to be suffi cient to This appears to have been the mechanism completely mitigate large-scale disruption. by which the United Kingdom market Nonetheless, this option can be useful as reduced gas demand after a fi re at the part of a suite of tools for dealing with such principal storage facility in 2006. interruptions.

In some cases, there is often a time lag Direct rationing between wholesale price changes fi ltering through to certain classes of consumer, One option which has been used by for instance in the residential sector. IEA countries is government-determined This time lag might justify government rationing. This option requires careful action to make domestic gas consumers preparation by governments in consultation aware of a supply disruption. Short-term with users and industry to identify costs, gas saving measures might be required capacities and legal/technical issues well in to reduce demand over relatively short advance of activation of the plan. Planning periods. Given the increasing use of gas in such as this needs to be regularly tested power generation, these measures should and updated because gas markets and their also consider stimulating action in the dependents (such as electricity markets) electricity sector (Saving electricity in a tend to change rapidly. In the absence of hurry, IEA 2005). functioning gas markets or if a disruption is very large indeed, such actions may be an Those countries with gas prices determined important crisis management tool. by supply and demand would see an automatic reduction of consumption of Fuel switching gas as the price increases. Where price is determined by some other means, this There is a class of gas customers who exhibit would not happen. In any case, government a very useful type of demand response for Natural Gas Market Review 2007 • Gas Security 80

managing a gas emergency situation as response times. Differences in oil and gas they can rapidly switch what fuel is burned prices are not possible if gas prices are to power the same equipment. This means determined by oil prices, such as in much that the response is faster and there is of continental Europe (Japan and Korea less potential disruption to customers less so). This means that fuel switching than in the case of a demand response capacity would have to be imposed from shutting production and relying on administratively (by gas companies or imports of the product. In most cases, the by governments). In this situation, fuel choice of alternative fuel is technically switching should be tested regularly to limited to oil or oil products, as oil can ensure capability. be injected into gas turbines or sprayed into boilers (this is rather more diffi cult for coal). While there is a penalty in terms Conclusion of effi ciency and increased maintenance, some gas-fi red power stations in Europe12 All three IEA importing areas are now and North America can often switch to importers of natural gas and each will light oil (gasoil) and some in Korea and Japan can often burn crude oil if necessary. import more natural gas in 2015 than in In order for these plants to switch fuel, 2005. Gas will increasingly come to market several conditions must be met13 – above across longer supply routes from countries all, there must be adequate stores of oil with more abundant reserves. available at the site. Natural gas is very important for basic functions of heating and cooking. It is Equipment such as dual fuel burners and becoming more important for power oil stocks are expensive, so there must generation, and is also used as a chemical be adequate incentives if companies are feedstock for industrial processes. An expected to maintain such investments. ideal emergency response to a natural In competitive markets, companies often gas supply crisis would result in gas make generation decisions based on fuel saving (from lower demand) in all of these costs and therefore have some fi nancial applications, but particularly from low incentive to maintain oil storage and dual value-added industrial processes such as fi ring capability. However, if dual fi ring basic industrial processes. capability is imposed by the government, it is tempting for companies to save A prolonged gas supply disruption could money by for instance, storing less oil have a very high impact on IEA member than governments may deem prudent. countries. It is clear that physically interlinked markets such as North America The potential for gas saving through fuel or virtually interlinked markets such as switching clearly depends on the amount Japan and Korea can better survive supply of dual fi ring capability in any given region disruptions, especially of the smaller type. or country, noting differences in costs and A disruption of 2 bcm in an isolated market

12. Switzerland has one of the largest switching capacities of in IEA countries, with 40% of gas demand (by volume) mandated to be technically able to switch to oil if necessary, and with a reserve of 40 days of oil. 13. E.g. Environmental conditions: emissions permits; marginal cost considerations; contractual arrangements etc. Natural Gas Market Review 2007 • Gas Security 81

of 10 bcm will have serious implications; be part of an effective gas emergency the same interruption in a continental policy – particularly to insure against a sized market of 500 bcm can be much more specifi c disruption at an identifi ed weak easily handled. It is therefore imperative for point in the system. IEA countries to actively encourage larger, more interconnected gas networks that The IEA advises: are driven by fl exible gas markets, capable those countries with no explicit gas of responding to changing circumstances. emergency policy to put one in place in order to mitigate the effect of the loss Whilst the development of interlinked gas of the weakest point in the system for markets in many IEA countries remains a reasonable repair period. slow, there is a greater risk of impacts from a supply disruption, so alternative those countries with an emergency (temporary) approaches should be ident- response mechanism to check its ifi ed. Where markets function well, there is effectiveness regularly, as the gas still a chance that non-market events might market is developing globally and occur. This means that supplements to changing rapidly. the market should be carefully considered; all countries to use a mix of measures provided that such measures stand apart in a gas emergency response plan. If from the market so that they do not crowd gas stocks are a part of such a plan, to out commercial investment. ensure that they are as cost-effective The logistical and political risk of a natural as possible. gas supply disruption is increasing. The IEA advises all governments, in concert Indeed – some IEA countries already have with other stakeholders to: emergency response mechanisms, including government-controlled storage. Therefore, clearly defi ne, through a reliability there is a compelling case for all countries to standard or some other means, exactly develop some kind of emergency response what is expected of actors under normal mechanism for natural gas markets. market conditions. Countries should ensure that all stakeholders carefully design an emergency – including suppliers, national and local response mechanism drawing on a full pipeline system operators, regulators and suite of measures which does not affect consumers – have clearly-defi ned roles and commercial investment driven by the responsibilities in a crisis. gas market. Governments are well advised to put in clearly defi ne the role and responsibility place emergency response mechanisms of every stakeholder under an emergency for gas supply disruptions which draw on response mechanism. the above suite of measures and which ensure that the conditions under which look beyond just strategic gas storage as a an emergency response mechanism will general solution to a gas crisis; gas stocks be used are transparent to the market. are more expensive, less fl exible and less effective than oil stocks. In certain make use of market mechanisms circumstances, however, gas stocks may wherever possible, in order to ensure Natural Gas Market Review 2007 • Gas Security 82

emergency response mechanisms are Data in the gas industry is poor, notably in cost-effective. IEA Europe. Much more needs to be done to improve transparency of gas fl ows, consider the international consequences within and across frontiers, both physical of their emergency response mechanisms, and contractual, if member governments including the consequences for regional are to understand how their markets power markets and the global oil market. might function in an emergency. The IEA secure in advance statutory powers already has an important initiative in this that might be necessary to implement area, with some key results set out in the emergency measures. Annexes. As part of efforts to increase transparency in IEA Europe, more detailed data collection is now being attempted. Some examples of gas security policies in IEA member countries are at Annex A. All IEA countries are interested to improve data availability in IEA Europe given the increasingly global interactions of regional Data transparency initiative markets. All LNG importing regions will benefi t from greater understanding of gas fl ows and market functioning in this region. Physical, international flows Figure 19 for pilot countries The Annexes provide an overview of Flow from Oct - Dec 2006, in bcm best available data showing imports and exports to all three IEA regions. Figure 19 NORWAY provides a complete picture for a selection SWEDEN 6.0 of six highlighted European countries who 3.6 2.9 participated in an IEA pilot study. The 3.5 0.3 trade shown below summarises physical DENMARK gas fl ows at European borders over the 0.8 1.1 UK 0.5 last quarter of 2006. 0.1 0.6 IRELAND NETHS. 0.1 1.0 8.3 0.2 3.9 1.3 GERMANY LNG 1.1 BELG. 0.6 0.1 LNG 3.2 0.2 LUX. 3.1 1.9 AUSTRIA

LNG 4.0 FRANCE SWITZ. 6.0 SLOVENIA 0.04 1.5 0.02 0.06 0.4 4.4 CROATIA 0.03 ITALY 0.3

SPAIN 6.1 2.2 LNG 0.8

ALGERIA LIBYA

The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

Source: IEA pilot study. Natural Gas Market Review 2007 • Developments in LNG markets 83

DEVELOPMENTS IN LNG MARKETS

Global LNG production capacity is set to Overview grow rapidly and LNG will make up 14% - 16% of global gas demand by 2015. The rapidly changing world of LNG The majority of gas sector investment has been focussed on developing LNG 2006 saw world LNG production grow by production. In Japan and Korea, LNG 11% to 218 bcm, continuing the strong will retain its central role but for the growth that has seen output increase North American and European regions, by more than 50% in fi ve years. Qatar LNG will be an essential supply source. surpassed Indonesia as the world’s largest LNG exporter in 2006, for the fi rst time 2006 saw world LNG production grow since 1984 when Indonesia took the place by 11% to 218 bcm, continuing the of Algeria. Qatar exported 33 bcm of LNG strong growth that has seen output in 2006, followed by Indonesia’s 30 bcm increase by more than 50% in fi ve and Malaysia’s 28 bcm. years. Qatar surpassed Indonesia as the world’s largest LNG exporter in 2006, China and Mexico started importing LNG in exporting 33 bcm. 2006. Gazprom entered the LNG business, taking its fi rst majority equity stake in an No fi nal investment decisions for any LNG project, Sakhalin II, late in 2006, and LNG export projects were made in 2006, selling spot LNG cargoes into Asia for the refl ecting the diffi cult investment en- fi rst time in summer 2006. vironment caused by a tight engin- eering market and cost increases. In early 2007, a USD 1.5 billion construction contract was awarded for a 6 bcm per Regional price movements have driven year liquefaction plant on Peru’s southern some “globalisation” of gas trade coast, the fi rst on South America’s Pacifi c commodities, particularly from the coast, to Chicago Bridge & Iron (CB&I). The Atlantic to Pacifi c regions, although project’s partners are Hunt Oil, Spain’s volumes remain relatively minor. Repsol, and Korea’s SK Corporation. The These movements have also been Peru project represents the only new facilitated by the changing business project sanction for the period June 2005 models of the LNG industry. This trend to March 2007. will accelerate even further because a substantial number of more fl exible No fi nal investment decisions for any LNG exporting plants, which could supply export projects were made in calendar cargoes to both Atlantic and Pacifi c 2006, the fi rst year with no announcements LNG markets, are to be installed in since 1998. This refl ects the diffi cult in- Middle East countries. vestment environment caused by a tight engineering market and cost increases.

The fi rst dockside LNG regasifi cation terminal began operations at Teesside in northern in February 2007, with Natural Gas Market Review 2007 • Developments in LNG markets 84

a remarkably short lead time (roughly American and European regions, LNG will one year). Turkey started using its fi rst become an essential supply source. receiving terminal built by a private company, not state-controlled Botas, Regional price movements have driven virtually forced to do so by signifi cantly some “globalisation” of gas trade , although reduced pipeline gas delivery from Iran in volumes are relatively minor. These move- the winter 2006/07. ments have also been facilitated by the changing business models of the LNG Norway imported its fi rst LNG cargo at the industry. Traditional LNG trades have beginning of 2007. This was to commission been done between designated sellers and its fi rst LNG liquefaction facility, also the buyers. Today, more integrated oil and gas fi rst within the Arctic Circle, the Snøhvit majors and national oil and gas companies project. are securing their own long-term LNG supply fi rst through upstream equity 30 newly built LNG carriers were delivered holding and/or contracting. They then to the market in 2006, representing a 16% directly market LNG cargoes into multiple increase in total LNG fl eet in the world and outlets. While many of the outlets are a 19% increase in total shipping capacity. secured also on long-term basis, they tend to have more fl exibility in diverting Korea’s residential gas sales were down in cargoes to different places. These trends 2006 due to warmer-than-normal winter naturally increase the ratio of cargoes for the fi rst time since the country started counted as “spot,” although originally importing LNG in 1986, although imports contracted on long-term basis. grew some 10% on the back of the power sector. Japanese imports were also up This trend will accelerate even further more than 6%, despite warmer weather because a substantial amount of more reducing demand in certain sectors, fl exible (hybrid) exporting plants which especially early in 2006. could supply cargoes to both Atlantic and Pacifi c LNG markets, are to be installed in LNG production will steadily grow Middle East countries, notably in Qatar, and fl exibility will increase and also substantial shipping tonnage is going to be delivered in the coming years. Global LNG production capacity is set to Such fl exible capacity in the Middle East grow rapidly from 240 bcm per year in could represent 25% of the global LNG 2005, to 360 bcm in 2010, and 500 - 600 exporting capacity by 2015. bcm per year by 2015, growing by 7.5- 9% a year. LNG will make up around 20% The Pacifi c remains a key to the of OECD gas supply as soon as 2010, and LNG market but Atlantic markets 14 - 16% of global gas demand by 2015. will grow in infl uence The majority of gas sector investment has been focussed on developing LNG Japan is currently the largest LNG importer production. In Japan and Korea, LNG will in the world and Korea the second. By retain its central role but for the North the end of the review period, however, Natural Gas Market Review 2007 • Developments in LNG markets 85

the Atlantic LNG market will grow to having similar distances to either market, at least equal, or may even surpass, the will increasingly link the Pacifi c with the Pacifi c market. Shares of Japan and the Atlantic, carrying price signals between Pacifi c will decrease during the period, them. More regasifi cation capacities are potentially dropping from 42% and planned in the more liquid Atlantic gas 66% in 2005 to 16% and 35% by 2015, markets, which is also likely to contribute respectively. Middle Eastern LNG exports, to greater fl exibility in cargo movements.

Figure 20 Traditional and recent models of LNG business

Upstream Liquefaction Shipping Regasification End-use markets

Traditional models Sellers Sales Buyers

Recent models Intergrated players (Majors, NOCs) Some buyers go into upstream

Table 9 Countries and regions involved in international LNG trades

Import Atlantic Pacific United Kingdom (1964-1994), France (1964), Spain (1969), Japan (1969), Korea (1986), Chinese Taipei 1964- 2000 Italy (1969), United States (1971), Belgium (1987), Turkey (1990) (1994), Greece (2000), Puerto Rico (2000) Dominican Republic (2003), United Kingdom (2005), 2000-2006 India (2004), China (2006) Mexico (2006) Chile (2010), Mexico (2011), Thailand (2012), Future Canada (2009), Brazil (2009-2010), Netherlands (2010) Singapore (2012) Export Atlantic Hybrid (Middle East) Pacific Alaska (1969), Brunei (1972), Algeria (1964), Libya (1970), Abu Dhabi (1977), Qatar (1997), 1964 - 2000 Indonesia (1977), Malaysia (1982), Trinidad (1999), Nigeria (1999) Oman (2000) Australia (1989)

2000-2006 Egypt (2005)

Equatorial Guinea (2007) , Sakhalin (2008), Peru (2009), Future Norway (2007), Angola (2010), Yemen (2009), Iran (2011) Myanmar (2013), Papua New Russia (2012), Venezuela (2011) Guinea (2013)

*For future importers and exporters, the year in the parenthesis indicates earliest possible start date. Source: IEA data. Natural Gas Market Review 2007 • Developments in LNG markets 86

Figure 21 Expected regasification import capacity by region: regas capacity is ample

1 000

bcm per year 800

Atlantic America 600 Europe 400 Pacific America

200 Asia Pacific

0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Source: Company announcements, moderated by IEA analysis.

The increase in European gas pipeline supplies from Algeria and Russia, imports will be met through both accounting for 61% of total gas demand. LNG and pipelines In the United Kingdom, two new onshore LNG terminals are being built and existing Two thirds of Spanish gas demand is met capacity is being upgraded. through LNG imports, making it the third largest LNG market after Japan and Korea. The increase in North American The Spanish market has grown at around imports will be met through 15% per year, with two terminal expansions LNG alone and one new terminal completed in 2006 and further expansions are expected to be Canada is currently the largest gas online in 2007. In Italy, where only one LNG exporter to the United States, the world’s import terminal is currently in operation, largest gas consumer; accounting for 15% two more are under construction. Each of of the United States’ demand. Both the these countries makes extensive use of United States and Canada have seen a large gas in power generation (the two countries increase in gas drilling activity as gas prices added 4 GW of gas-fi red power generation have risen in recent years, but this has not capacity each in 2006) and also has plans resulted in a corresponding production to increase pipeline infrastructure. The response. Flattening North American gas availability of LNG terminals allows Spain production, combined with rising demand to draw on a diverse range of gas supplies; will see LNG becoming more important by contrast Italy is heavily reliant on in the North American gas supply. By the Natural Gas Market Review 2007 • Developments in LNG markets 87

end of the review period, LNG will supply with another in Shanghai, scheduled for up to 9% (80 bcm per year) of the North 2009. Meanwhile, Indian gas demand is American market through a number of outpacing supply, resulting in shortfalls, new import terminals. The North American despite import terminals operating below market will increasingly be linked to world capacity. Domestic gas pricing reform will markets and vice versa. be needed to enable potential customers to secure imports and to encourage domestic China and India represent gas production. LNG imports seem unlikely massive latent demand for gas to exceed 40 bcm per year by 2015. This at lower prices means that the vast bulk of LNG will be consumed in IEA countries. Chinese gas demand was only 3% of primary energy use in 2005 and is virtually Qatar has emerged as a major gas all satisfi ed by domestic production. exporter, but Indonesia is slipping The current high international price environment has slowed construction of Qatar emerged as the world’s largest LNG infrastructure necessary to provide growth producer in 2006 and its share is rising in gas use. LNG imports commenced with rapidly, with its fi rst “mega” liquefaction the inauguration of the fi rst terminal in facility expected to be online in early 2008. 2006 in Guandong. A second terminal in It could supply more than 20% of the world Fujian should start receiving LNG in 2008, LNG market in 2010 as a result of successful

Figure 22 Expected LNG export capacity by region

600

500

bcm per year

400

300 Atlantic

200 Hybrid

100 Pacific

0 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015

Source: Company announcements, moderated by IEA analysis. Natural Gas Market Review 2007 • Developments in LNG markets 88

efforts to attract overseas investment in Australia is emerging its abundant reserves. Qatar is positioned as a greater force to sell its huge volumes into both Atlantic and Pacifi c markets, further linking these With declining LNG exports from Indonesia, gas markets. Australia is gaining momentum towards a greater share of the Pacifi c LNG market, with Meanwhile, Indonesia, which currently the addition of a brand-new exporting plant supplies a quarter of Korean and Japanese at Darwin (Northern Territory) in 2006, the gas demand and was the world’s largest fi rst since the opening of the North West LNG producer, lost its title to Qatar in 2006. Shelf in 1989 (now operating at 16 bcm per A lack of investment in gas production has year), and several grassroots and expansion meant that existing LNG production is projects are on the horizon for starting declining, resulting in lower deliveries to in early 2010s. Though there are some its buyers. Efforts to substitute domestic hurdles to clear, including environmental gas in the current oil dominated energy agreements, high construction costs, and mix seem likely to further reduce gas State-based policies of domestic resource availability for exports. usage, project fundamentals are generally good.

Production Starting Bayu-Undan export

The Darwin LNG project started exporting Indonesia is diminishing its LNG to its Japanese customers in early dominant position in Asia 2006. The project is unique in a couple of aspects: the feedgas is the fi rst provided Indonesia, which has dominated the Asia- from the joint petroleum development Pacifi c LNG market since its fi rst LNG area (JPDA) between East Timor and export in 1977, is decreasing exports after Australia where other gas reserves have peaking at 38 bcm (28 million tonnes) in been identifi ed; the project size is relatively 1999 and 35 bcm (26 million tonnes) in small (5.0 bcm per year (3.70 mtpa)) in this 2003. Not only the North Sumatra Arun era of mega projects; participation from liquefaction plant, where gas reserves are long-term buyers in Japan into the whole dwindling, but also the country’s fl agship value chain encouraged the development; Bontang venture in East Kalimantan, are and early extraction of natural gas liquids both showing disappointing performances (NGLs) was critical to the project. Plenty in LNG production. Indonesia is expected to of space and potential feed gas sources export 11% less than previously contracted for expansion are available, as approvals in 2007. Some buyers are busy replacing have been granted for up to 13.6 bcm per the anticipated losses for the next couple year (10 mtpa). Unusually for Australia, of years. The country does not expect a the plant is well-located, close to existing signifi cant increase in LNG production until infrastructure of the city of Darwin. the scheduled start up of the Tangguh plant in 2008 (see details below). Natural Gas Market Review 2007 • Developments in LNG markets 89

Figure 23 Australia’s LNG projects PAPUA NEW GUINEA Port Moresby Darwin LNG Bamaga Trial Bay Weipa

Broome North West Shelf LNG Townsville Port Walcott Carnarvon Basin Dampier Great Mount Isa Thevenard Is. Artesian Basin Gladstone Alice Spring Carnarvon AUSTRALIA Jackson Brisbane Geraldton Cooper/Eromanga Basin Kalgoorlie Bourke Perth Kwinana Newcastle Bunbury Port Bonython 0Miles 500 Sydney Esperance Adelaide Kurnell 0Km 500 Albury Albany Canberra Gas pipeline Melbourne Portland Gas pipeline planned or under const. Gas fields LNG export plant Tasmania LNG export plant planned Hobart NEW ZEALAND

Source: Company announcements, The Petroleum Economist Ltd.

Pluto: progress in marketing The company started site preparation and engineering work for storage tanks of a standalone liquefaction plant in early 2007, after its Quick progress has been made in market- request to share facilities with the existing ing and engineering of the Woodside’s North West Self venture was declined. The wholly-owned Pluto project, close to the fi nal investment decision is expected in existing North West Shelf plant on Burrup mid-2007. Peninsula, since the company discovered signifi cant reserves in the fi eld in April Gorgon: progress but some 2005. After securing commitment from environmental and cost hurdles Japanese buyers late in 2005, the company started front-end engineering and de- Marketing efforts of the Gorgon LNG sign (FEED) work in fall 2006, targeting project, which has been mooted for more commencement of the project in 2010. than 15 years, made considerable advances This ambitious schedule would amount to in late 2005 by signing up buyers from Japan one of the fastest LNG exporting projects for the operator Chevron’s share of output. ever developed. The project may keep The project generally enjoys support from 1.3 bcm per year (1 mtpa) of its output state and federal governments and is on for fl exible marketing out of its planned the way to start exporting in 2011 from the capacity of 6.8 bcm per year (5 mtpa). planned 13.6 bcm per year (10 mtpa) plant Natural Gas Market Review 2007 • Developments in LNG markets 90

Figure 24 North West Shelf’s long-term sales commitments

20

bcm

15

10

5

0 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Japan Trains 1-3 Japan Trains 4/5 Korea China

Source: Company information. on Barrow Island off Western Australia. The Mexico, where Shell has 50% of the import Gorgon partners – Chevron (50%), Shell capacity. India’s Petronet says it hopes to (25%) and ExxonMobil (25%) – have been sign a sale-and-purchase agreement for marketing their equity LNG separately. term imports of ExxonMobil’s share of Gorgon output by June 2007.

High CO2 content of the feedgas and environmental siting issues as well as North West Shelf: Train 5 engineering and cost issues, may still delay construction and some this development. The state government Train 4 glitches gave environmental approval to the project in December 2006. The fi nal investment The fi fth liquefaction train at the North decision, which was initially targeted for West Shelf project is under construction. mid-2006, is now expected in 2007, the The 6.0 bcm per year (4.4 mtpa) unit is on partners have said. Marketing arrangements schedule for commissioning in late 2008, for the remaining capacity, assigned according to project operator, Woodside. to partners ExxonMobil and Shell, have Once it is completed, the venture will been less clear. Shell has indicated that it have a total production capacity of 22.2 intended to send its share of Gorgon output bcm per year (16.3 mtpa), out of which to the company’s Hazira LNG receiving the venture will have fl exibility volumes terminal in India, where it has held gas of as much as 2.3 bcm per year (1.7 mtpa) sales talks with Gujarat State Petroleum, as to sell on the spot market. Meanwhile, well as Sempra Energy’s 10.3 bcm per year the venture’s occasional troubles at the (7.6 mtpa) Energia Costa Azul terminal in newest Train 4 might cause concerns about Natural Gas Market Review 2007 • Developments in LNG markets 91

credibility of bigger liquefaction trains the project, which is scheduled to come (earlier trains were 2.7 - 3.4 bcm per year online in 2012. France’s Total agreed to take (2 - 2.5 mtpa) in capacity). a 24% interest in the project. Environmental planning is based on a site off the Kimberly North West Shelf existing coast, remote from existing infrastructure. contract renewals This would be the fi rst development in the Browse Basin. Inpex aims to start The original sales contracts amounting to construction of the plant in the beginning 10 bcm per year (7.33 mtpa) from the Trains of 2009, after making a fi nal investment 1 - 3 of the with decision by late 2008. Japanese foundation buyers are expiring in March 2009. Renewal negotiations are Other companies, including Woodside, underway with the customers, as well as have extensive gas reserves in the with a couple of additional importers in Browse Basin, which could create a major the region, which have forced some of the LNG production hub. The partners are foundation customers to receive smaller investigating options for the Browse gas volumes than they currently import from fi elds, with a production target between the venture. Prices look to be higher but 2012 and 2014. Pilbara LNG has been still linked to the JCC oil prices with a planned by BHP, utilizing gas reserves in wider applicable range. The renewal terms the Scarborough gas fi eld jointly owned only last from 6 to 12 years, compared by the company and ExxonMobil. to 20 years for all the original deals. The terms of these renewals, with increased “Major project facilitation status” has prices, shorter duration and reduced also been given to two gas development volumes, are an indication of current projects in the Timor Sea being planned by market tightness. MEO Australia. The projects are expected to produce around 4.1 bcm per year (3 mtpa) of “Major project facilitation status” LNG and 5 000 tonnes per day of methanol on Ichthys LNG from offshore facilities on Tassie Shoal, a shallow area in the Bonaparte Basin, about The Australian federal government granted 275 km north of Darwin. The projects are a “major project facilitation status” on the also expected to play a hub role to encourage Ichthys LNG proposal backed by Japan’s development of stranded gas discoveries in Inpex Corporation, based on gas reserves the area. found in its WA 285-P gas block offshore northwestern Australia, in August 2006. Western Australia’s new This means that the government’s “Invest domestic gas policy Australia” arm would help advance the project through the regulatory process and In October 2006, the Western Australian identify any programs that could assist its State Government released its policy on implementation. Inpex has begun talks with domestic gas supply. The state considers potential Japanese buyers for the 8.2 bcm that market forces will not deliver suffi cient per year (6 mtpa) of planned output from volumes of low-cost domestic gas to meet Natural Gas Market Review 2007 • Developments in LNG markets 92

Table 10 Australian LNG export project interests North Darwin Pluto Gorgon Ichthys Sunrise Browse Pilbara West Shelf Woodside 16.7% 100% 33.44% t.b.d.

Chevron 16.7% 50% t.b.d.

BHP 16.7% t.b.d. t.b.d.

BP 16.7% t.b.d.

Shell 16.7% 25% 26.56% t.b.d

MIMI 16.7%

ConocoPhillips 56.72% 30%

Eni 12.04%

Santos 10.64%

Inpex 10.52% 76%

Tokyo Electric 6.72%

Tokyo Gas 3.36% 5%? t.b.d.

ExxonMobil 25% t.b.d.

Kansai Electric 5%?

Osaka Gas t.b.d. 10%

Chubu Electric t.b.d.

Total 24% t.b.d.: to be decided Source: Company information. expected future energy demand. The State The federal government and the LNG will negotiate with companies to supply the industry are opposed to the policy and equivalent of 15% of LNG production to the consider that the market should determine Western Australian domestic market. The how and from where gas is supplied. Most policy emphasises the gas commitment can gas produced in Australia is sourced from be met from other projects or via gas trading fi elds in federal government waters, but is schemes, with the price of gas determined processed into LNG on land, where State through commercial negotiations. The approvals are required. A joint state- state has already negotiated an agreement federal working group has been formed to under the policy with Woodside Energy for examine future gas supplies and consider the Pluto LNG project. policy options to secure gas supplies for domestic and export use. Natural Gas Market Review 2007 • Developments in LNG markets 93

Alaska’s Kenai seeks sales extension term sales to China in 2009 (to Shanghai), in addition to the existing long-term sales ConocoPhillips and Marathon Oil have to buyers in Japan, Korea, and Chinese jointly fi led with the United States’ Taipei, as well as mid-term sales to India. Department of Energy for a two-year ex- tension of the export license of the Kenai Yet other potential suppliers LNG facility in Nikiski, Alaska in January emerging: Papua New Guinea 2007. The existing license expires in March and Myanmar 2009, with the project’s sales deal with two Japanese utility buyers. The 2 bcm per year Tightening supplies and rising gas prices (1.50 mtpa) Kenai plant, the only LNG export in the Pacifi c LNG market are encouraging facility in North America, was built in 1969 other potential suppliers, including Papua to commercialize gas reserves discovered New Guinea and Myanmar to monetize in south-central Alaska that surpassed their gas resources. local needs. It was the world’s fi rst long- distance LNG export project and Japan’s Papua New Guinea currently has several LNG fi rst imports of LNG. Since then Japan has proposals. A long-awaited gas pipeline under diversifi ed sources of supply, and Alaska’s Torres Strait to Australia’s eastern states share in Japan’s LNG imports has dwindled. proposed by ExxonMobil and Oil Search was scrapped in early 2007 after a major Brunei may expand capacity setback in summer 2006 when Australia’s AGL and Malaysia’s Petronas withdrew Brunei LNG, a joint venture between from the project – freeing up dedicated Brunei government, Shell and Mitsubishi, reserves for possible export in the form has a fi ve-train plant with a capacity of of LNG. Separately, Oil Search has teamed 9.8 bcm per year (7.20 mtpa). The Lumut up with BG to evaluate an LNG exporting export plant started operations in 1972. project based on reserves not dedicated to Long-term contracts with Japanese and the Australian line. Merrill Lynch, Canada’s Korean buyers are up for renewal in 2013. InterOil and Clarion Finanz are considering A sixth train probably with a 5.4 bcm per LNG exports centered on a potentially major year (4 mtpa) capacity may be planned if discovery in InterOil’s Elk fi eld. more gas reserves are discovered. Daewoo and its partners – Korea Gas Malaysia expanding sales portfolio Corporation (Kogas) and India’s ONGC Videsh and GAIL – are considering an LNG Malaysia LNG’s Bintulu plant is one of exporting project based on resources in the largest single concentrations of LNG the Rakhine Basin, offshore Myanmar. The production capacities in the world with sponsors claim that all the LNG buyers in 31 bcm per year (23 mtpa). It started this region have expressed an interest exports to Japan in 1983. The majority to its request for proposals conducted shareholder of the three production in December 2006, in which Kogas and ventures at the site is the state-owned Japan’s Marubeni were said to be selected Petronas. The exporter plans to start long- as preferred off-takers of the LNG. Natural Gas Market Review 2007 • Developments in LNG markets 94

Some of Qatar’s mega train Kingdom and United States, some of their volumes going to Asia output is likely to be diverted to buyers in Japan, Korea and Chinese Taipei. By selling Qatar has steadily built up its LNG business some of the most recent volumes in Asia, the since 1997 and will triple its exporting Middle East’s largest producer is diversifying capacities from 35 bcm per year (26 mtpa) its markets in terms of both geographic, and at the end of 2006 to 105 bcm per year liquid and traditional market combinations. (77 mtpa) by 2011, with the addition of a In addition to two new Korean long-term 6.4 bcm per year (4.7 mtpa) train in 2007 sales of 2.9 bcm per year (2.1 mtpa) each, and six 10.6 bcm per year (7.8 mtpa) “mega” starting in 2007 and 2009, and a Japanese trains in the coming years. No country has mid-term sale of 1.6 bcm per year (1.2 mtpa) ever exported this quantity of LNG, and from 2008 to 2012, an additional 9.5 bcm Qatar will remain the LNG leader for many per year (7 mtpa) is on the negotiation years to come. For output from those huge table between Qatar and Japan. (see also production facilities, the Middle East producer discussions on the United States and United is going to introduce mega-sized Q-fl ex Kingdom markets later). (210 000 m3) and Q-max (260 000 m3) tankers. It should be noted that there is a major While the mega-train projects were orig- study being undertaken on the country’s inally mostly intended for the United giant North Field on reserve integrity

Table 11 Qatar’s LNG projects: traditional and mega trains Capacity Originally intended Trains Project Start (bcm per Recent Asian and other diversions destinations year) Qatargas 55.4 1997- 1-3 Qatargas 12.9 Japan, Spain 1998 4 Qatargas II 2008 10.6 United Kingdom Chubu likely to buy 1.6 bcm per year 2008-2012 5 2008 10.6 United Kingdom Total could divert 5 bcm per year to France, Mexico 6 Qatargas III 2009 10.6 United States Korea likely to buy 2.9 bcm per year starting 2009 7 Qatargas IV 2010 10.6 United States RasGas 49.4 1-2 1999 9.0 Korea, Spain 3 RasGas II 2004 6.4 India 4 2005 6.4 India, Korea Korea buys 2.9 bcm per year starting 2007 Spain, Italy, Belgium, 5 2007 6.4 Chinese Taipei 6 RasGas III 2008 10.6 United States Half of RasGas III could be diverted to Asia 7 2009 10.6 United States

Note: = Mega trains. Source: Company information. Natural Gas Market Review 2007 • Developments in LNG markets 95

management. The study will not be reserves, 9 Tcf (255 bcm) is earmarked for completed at least until 2009, meaning the LNG project. About two-thirds of the that any new major project decision is only LNG would go to North America and the likely to be made after that. This will mean remainder to Korea. only limited Qatari production increases for the immediate period (potentially three Iran: preliminary deals years and upwards) after the current project with Thailand and China load is completed in around 2011-12. Thailand’s state-owned PTT in summer Abu Dhabi: the fi rst LNG 2006 provisionally contracted for 4.1 bcm exporter in the Middle East per year (3 mtpa) from Iran’s proposed Pars LNG project for 20 years beginning 2011. The Adgas project, a 7.9 bcm per year PTT plans to construct a receiving terminal (5.8 mtpa) plant on Das Island in Abu Dhabi, on the country’s eastern seaboard. China’s the United Arab Emirates, dates back to PetroChina signed a heads of agreement 1977 and is the longest established in the in November for the supply of 4.1 bcm per Middle East. The project is majority owned year (3 mtpa) for 25 years. The Pars LNG by Abu Dhabi National Oil Company with venture includes France’s Total, Malaysia’s foreign partners Mitsui, BP and Total. Japan’s Petronas and the National Iranian Oil Co. Tokyo Electric Power Company buys the (NIOC). The project partners may take majority of the plant’s output on long-term a fi nal investment decision to build the basis, with some mid-term sales to Spain. 13.6 bcm per year (10 mtpa) plant in 2007.

Oman added another train in 2006 NIOC and China National Offshore Oil Corp. (CNOOC) in November 2006 signed a Oman started exports in 2000 to mainly USD 16 billion deal to develop Iran’s North Korea and Japan on a long-term basis, as Pars gas fi eld and build LNG facilities. well as some mid-term sales to Spain from NIOC also inked major gasfi eld/LNG pro- the two-train 9.8 bcm per year (7.2 mtpa) ject agreements with relatively un-known Oman LNG plant at Qalhat. Oman added players in LNG, with Australia’s LNG Ltd for another 4.9 bcm per year (3.6 mtpa) Qalhat development of the Selkh and Southern LNG train in early 2006. Gesho fi elds for LNG export in November 2006 and with Malaysia’s SKS Ventures Yemen advancing toward 2009 for the Golshan and Ferdows offshore start of production gasfi elds in January 2007. China National Petroleum Corp. (CNPC; PetroChina’s parent Yemen LNG is on schedule for its targeted company) is also reportedly fi nalising fi rst production by the end of 2008, since its memorandum of understanding with a turnkey contract for EPC and start-up NIOC to jointly develop a USD 3.6 billion services was awarded in September 2005. upstream and 6.1 bcm per year (4.5 mtpa) The project will have two 4.6 bcm per year LNG project based on gas reserves of South (3.4 mtpa) liquefaction trains in 2009. Of Pars gas fi eld in early 2007. the country’s 17 Tcf (481 bcm) proven gas Natural Gas Market Review 2007 • Developments in LNG markets 96

Despite those talks, NIOC has made no trains at Arzew and Skikda, excluding the physical progress in LNG developments. three trains at the Skikda plant destroyed In the meantime, Iran is struggling to in the explosion in January 2004. The plants cover both domestic demand and existing are operated by state owned Sonatrach. pipeline gas export obligations (see section Spain’s Repsol and Gas Natural along with on Iran). Sonatrach’s minority participation, plan to develop their brand-new El Andalus LNG Both new Egyptian exporting based on gas reserves at Gassi Touil, with plants are considering expansions a 5.4 bcm per year (4 mtpa) liquefaction plant near Arzew, targeted for completion The Damietta LNG plant, which started by November 2009. Sonatrach has a plan production from its fi rst 6.8 bcm per year for a 5.4 bcm per year (4 mtpa) train at (5 mtpa) in late 2004, is likely to proceed Skikda, replacing the destroyed ones. Both to a second train of a similar capacity, with plans apparently have some engineering a recently signed framework agreement issues, possibly causing some delays, cost between the operating company Segas increases and modifi cations to the plans. partners (Union Fenosa, , Egyptian Gas Holding Co (EGAS), and Egyptian General Libya: unlikely to expand soon Petroleum Corp (EGPC)) and BP. Production start is expected to be around 2010 - 11, The Marsa el Brega LNG plant in Libya, one although progress depends on the location of the oldest (starting in 1970), owned by of adequate reserves for the plant, in National Oil Corporation (NOC), used to the light of the government’s stricter have a nominal capacity of 3.1 bcm per year requirements on gas for export use. (2.3 mtpa), although recent exports have been signifi cantly less than that. In fact, BG, one of the major partners and also the country has not exported even at 50% long-term lifters in Egyptian LNG project of that rate since 1981. Due to high Btu at Idku, which started exporting LNG in content, all of the production is supplied early 2005 and currently has two 4.9 bcm to Spain’s Barcelona terminal, where LPGs per year (3.6 mtpa) trains, hopes to build a are stripped out and the heating value of third liquefaction train at the plant, partly the gas is reduced. Shell has been putting fed by gas from Palestinian-controlled Gaza together plans to upgrade and potentially Marine Field in the Mediterranean Sea, expand the aging facility since 2004 and with targeted start up in 2010 - 11. This submitted a “rejuvenation” plan in 2006. also depends on the success of exploration efforts. West Africa’s emergence as a major force Algeria: the Atlantic Basin’s longest established and largest exporter Equatorial Guinea LNG’s steady progress and a likely expansion Algeria, which started exports back in 1964, has an installed production capacity The Marathon-led Equatorial Guinea LNG of 27.2 bcm per year (20 mtpa) from 18 consortium, which also groups state- Natural Gas Market Review 2007 • Developments in LNG markets 97

owned Sociedad Nacional de Gas (Sonagas Brass LNG is also making progress to start GE), Mitsui and Marubeni of Japan, is production in 2011 or later, with Total constructing a 4.6 bcm per year (3.4 mtpa) replacing Chevron to join the project, which liquefaction plant at its Bioko Island site plans to have a capacity of 13.6 bcm per with projected commencement in the year (10 mtpa) from two trains. BG, BP, and middle of 2007. There is a slight concern Suez have already agreed to lift 2.7 bcm per about Marathon’s Alba fi eld, which can only year (2 mtpa) each from the project. The support the project for 12.5 years. BG Group ownership of the project is not clear yet. has purchased 4.6 bcm per year (3.4 mtpa) At the time that Total succeeded Chevron, from the base project over 17 years from the shareholders were believed to be NNPC start up. The FOB contract will allow BG to (49%), ConocoPhillips (17%), Eni (17%) and direct cargoes anywhere in the world. Total (17%). In September 2006, Nigeria unilaterally reduced the stakes of Total to Plans of the project’s second train of 6 bcm 12.5% and ConocoPhillips to 16.5%, and per year (4.4 mtpa) received a boost in planned to give 3% and BG 2%, but December 2006 by a Heads of Agreement a fi nal agreement has not been announced. between Nigeria and Equatorial Guinea for gas supply from Nigerian National Olokola LNG (OKLNG), which groups NNPC, Petroleum Corp (NNPC). The gas is likely to BG, Chevron and Shell, has reached several be sourced from the Oso gas-condensate milestones in siting and engineering fi elds operated by a joint venture between aspects for its two-train, 15 bcm per year (11 mtpa) project, which could be expanded NNPC and ExxonMobil in the Niger Delta. to a four-train, 30 bcm per year (22 mtpa) Cameroon also has some potential to supply at a later date. The target date for the feedgas to EGLNG from its substantial gas production currently stands at 2011. reserves within a 100 km radius of EGLNG. Sonagas signed an agreement to receive It should be noted the election year 2007 pipeline gas from Cameroon’s state-owned might affect the government’s priority National Co. of Hydrocarbons in January concerning new and expansion projects. 2007. The EGLNG consortium has already Although production at Nigeria’s existing started preliminary engineering works for LNG plant in Bonny Island has not been the second train. impacted by ongoing violence in that country so far, there is general concern Nigeria’s incremental plans about security issues among investors, (OKLNG, Brass, NLNGSevenPlus) including LNG developers. Work on the seventh and eighth trains of Russia’s ambitious move 10.9 bcm per year (8 mtpa) each at Nigeria into the global LNG market LNG (NLNGSevenPlus) is slipping and startup will be likely to be delayed by one year to Participation in Sakhalin mid-2011 or later. A fi nal investment decision Construction works at the planned Sakhalin II on the new facilities has been postponed liquefaction plant in the Russian Pacifi c island until the second quarter of 2007. of Sakhalin are on schedule to complete the Natural Gas Market Review 2007 • Developments in LNG markets 98

Table 12 Sakhalin I & II projects

Sakhalin I 8 bcm per year piped gas or LNG ExxonMobil, Sodeco (Japan), ONGC Piped gas to China; LNG call is made (India), -Sakhalinmorneftegas from India and Japan

13.1 bcm per year (9.6 mtpa) of LNG Sakhalin II planned volumes have been sold on 50% + 1 share transferred to Gazprom, Shell, Mitsui, Mitsubishi long-term basis to Asia and West Gazprom Coast North America

Source: Company announcements.

fi rst 6.5 bcm per year (4.8 mtpa) train in 2007 announced the project’s cost doubling to and the second train of the same capacity USD 20 billion in July 2005. The fi gure had within six months after that. Since pipeline grown to USD 22 billion by December 2006. supply of feedgas is not expected until Under the previous negotiation before the 2008 because of upstream development cost increase announcement, Gazprom was delays, plans are to commission the trains set to get a 25% stake in SEIC from Shell by importing LNG, regasifying it and in exchange for a 50% interest in deeper then reliquefying the gas. The project has estimated gas reserves of 500 bcm. Japanese layers of the giant Zapolyarnoye fi eld in customers have an advantage in saving on Siberia. But the massive cost increase, transportation costs by being relatively close which meant reduced and delayed revenues to the exporting project. for Russians, halted the negotiations and angered Russian offi cials. Under the terms The Sakhalin I and II ventures were of the PSA, the shareholders would be “grandfathered” in the Gazprom’s monopoly allowed to recover investment costs from over gas export that Russia’s legislature gas sales before the allocation of profi ts, ‘Duma’ confi rmed in July 2006. Faced with taxes and royalties to the government. growing pressure from the state’s environ- mental agency Shell and its partners in After the share transfer agreement, Investment Co. (SEIC), Mitsui Gazprom confi rmed that all the supply and Mitsubishi of Japan, agreed in December commitments from the project would be 2006 to hand over a controlling 50%-plus- met on time, starting in late 2008. It also one-share stake in the export venture to indicated the possibility of expansions, the Russian giant for USD 7.45 billion in cash potentially using resources from other payment. The Sakhalin II and the country’s deposits in the region. This could include two other production sharing agreements the Sakhalin I gas, although the project (PSAs) were signed in the mid-1990s when operator ExxonMobil says it has agreed to the country was in some fi nancial distress and sell the gas to China via pipeline. have been seen by many Russians as unfairly advantageous to foreign shareholders. Gazprom is establishing agreements with major LNG suppliers and buyers in Gazprom was already negotiating for the world, following the Russian giant’s participation in the project when Shell commencement of LNG trading in the Natural Gas Market Review 2007 • Developments in LNG markets 99

Table 13 Gazprom’s spot LNG deals

Deal Notes

September 2005 First Sale to the United States Sold to Shell at Cove Point, Maryland

November 2005 Gaz de France swap Sold to Shell at Cove Point, Maryland

Spring 2006 - 2007 BP Sale to Gazprom 4 cargoes to the United States and the United Kingdom

August 2006 Sale to Japan An Oman cargo via Celt (Tepco)

September 2006 One of BP sales Sold to Shell at Cove Point, Maryland

October 2006 Sale to Korea An Oman cargo via Celt to Pyeongtaek

Source: Company announcements.

Atlantic Basin in September 2005. In project on Yamal Peninsula, but this August 2006 the company signed a master reserve is also likely to be developed on trading agreement with Japan’s Tepco, the basis of pipeline sales. which resulted in a cargo purchase from Tepco’s and Mitsubishi’s joint venture Celt Norway Snøhvit: Europe’s and the and resale to Chubu Electric. In October Arctic’s fi rst LNG export project 2006, Gazprom signed a master trading agreement with Korea Gas (Kogas). Norway’s Snøhvit LNG project’s target dates for fi rst gas from the project’s Baltic, Shtokman, and Yamal offshore fi elds are mid 2007, in time for LNG projects initial production of LNG by the plant in August, with fi rst shipments in September The Baltic LNG project, which is supposed or October. Regular commercial exports to have a capacity of 7.2 bcm per year from the 5.6 bcm per year (4.1 mtpa) facility (5.3 mtpa) at a site near St. Petersburg by look set to start December 2007. The fi rst around 2010, could be the company’s own LNG exporting plant in Europe and in the fi rst LNG export venture in the Atlantic Arctic Circle imported an LNG cargo at the Basin. Gazprom invited Sonatrach of beginning of 2007 to cool down the loading Algeria to participate in the project in and storage systems and to fuel its utilities January 2007. The giant Shtokman project until its own offshore feed gas comes in in the Barents Sea, for which Western the summer. This project is very novel, and partners for LNG development were has faced many technical challenges, and expected to be announced around the encountered considerable delays. time of the G-8 Summit in St. Petersburg in July 2006, is now more likely to supply Trinidad: the largest exporter gas to Europe via pipeline, after Gazprom in the Americas announced in October 2006 that it would proceed with Shtokman on its own rather The Atlantic LNG plant in Trinidad and than giving 49% of the project to foreign Tobago is the largest export facility in players. There may be another export the Americas. Its geographical position Natural Gas Market Review 2007 • Developments in LNG markets 100

guarantees it numerous long-term outlets plans to build a liquefaction plant on Peru’s in North America. Its share in the United southern coast, which will produce 6 bcm States’ and Puerto Rico’s LNG markets in per year (4.4 mtpa) of LNG to be exported 2006 was 68%. The plant’s fi rst train at to Pacifi c North America, and possibly Point Fortin, on the southwest coast of Chile. Feed gas will come from the Camisea Trinidad, was only the second grassroots fi elds in the southeastern rain forest. LNG exporting facility in the Americas Chicago Bridge & Iron won the engineering, when it started operations in 1999, procurement and construction (EPC) following Alaska’s Kenai plant in 1969. The contract valued at USD 1.5 billion for the second and third trains were commissioned liquefaction plant in January 2007. The in 2002 and 2003, followed by the fourth project is expected to be completed in fi rst in 2005, resulting in the current total half of 2010. The project represents the exporting capacity of 20.6 bcm per year fi rst in Pacifi c South America. (15.1 mtpa). While a fi fth production train (“Train X”) has been mooted for some time, the development structure for the Consuming country project has not been fi rmed up yet. The developments government said in January 2007 that it had commissioned a feasibility study to assess gas supply for a fi fth train. Consolidation of LNG terminals plans in North America Venezuela: still far from exporting In autumn 2006 and early 2007, three import After talk of exporting LNG for more than terminal plans were shelved by major oil 15 years, Venezuela has not seen much companies (BP’s Bay Crossing, ExxonMobil’s progress in its LNG projects. Gas fi elds in Vista del Sol, and ConocoPhillips’ Beacon Port) the Norte de Paria area, which were once and two others were delayed (Sempra’s Port viewed as feedgas sources for Mariscal Arthur and Occidental’s Ingleside Energy Sucre LNG project, are now to be developed Center), all in the Gulf of Mexico area in to supply the domestic market. Gas in the the United States. Possible reasons include Plataforma Deltana area could be used an expected glut in terminal capacity in as sources for an LNG project. There is a the area, and more importantly, shortage possibility that the gas could be processed of long-term supply sources. Further con- at Trinidad’s Point Fortin plant, if talks solidation is likely since fi ve terminals with between the two countries advance in a total capacity of 110 bcm per year are that direction. currently approved for construction, several more projects of 100 bcm per year are under Peru LNG: fi rst in regulatory review and another some 45 bcm Pacifi c South America per year is under consideration. Terminals already available and under construction in The Peru LNG consortium, comprising North America have a capacity of 160 bcm Hunt Oil of the United States (50%), SK of per year, approaching 20% of North Korea (30%) and Repsol YPF of Spain (20%), American gas demand in 2010. Natural Gas Market Review 2007 • Developments in LNG markets 101

North American marketers will deliver to a premium elsewhere, these terminals are these receiving terminals if the price is right, likely to be underused. Similarly, if the North but are not subject to binding commitments American market is attractive, it will attract to do so. Therefore, if they can sell gas at more gas from other markets.

Table 14 North American LNG receiving terminals already available & under construction Terminal Location Capacity (bcm per year) Start Operating Atlantic Everett Massachusetts 8.3 1971 Cove Point Maryland 10.3 1978 Elba Island 15.5 1978 Gulf of Mexico Lake Charles Louisiana 19.1 1982 Gulf Gateway Offshore Louisiana 4.9 2005 Mexico Altamira Tamaulipas, Mexico 5.2 2006 Sub total 63.3 Under Construction East Coast Cove Point expansion Maryland 8.3 2008 Gulf of Mexico Cameron Louisiana 15.5 2008 Freeport Texas 15.5 2008 Sabine Pass Louisiana 41.4 2008 Golden Pass Texas 20.7 2009 Canada Canaport New Brunswick 10.3 2008 Pacific Costa Azul Baja California, Mexico 10.3 2008

Sub total 122.0

Total 185.3

Source: IEA data. Note: Sabine Pass includes a 14.5 bcm per year expansion in 2009; Puerto Rico has an LNG receiving terminal that is not included in this table. Natural Gas Market Review 2007 • Developments in LNG markets 102

Some diversion of long-term middle of August 2006. The commercial volumes from the United States operation of the terminal began in October, to Asia selling regasifi ed gas to state power generator (CFE). LNG is needed to supplement Qatari LNG marketers are executing indigenous gas production and reduce some fl exibility in diverting cargoes from dependence on piped gas from the United three mega trains of 10.6 bcm per year States. This would free up some supply (7.8 mtpa) each under construction in around the borders of the two countries. Qatar, originally designated for the planned The terminal’s initial capacity equates to Golden Pass terminal in Texas, sponsored around one tenth of the country’s average by Qatar Petroleum (QP) itself along with gas demand. Another receiving terminal, ExxonMobil and ConocoPhillips. Substantial Energia Costa Azul, is being constructed in output from the huge production facilities Baja California on the Pacifi c coast, and is in Qatar is now likely to go to Asia on a long- due to start operations in 2008. The state term basis, once negotiations between power generator is conducting bids for Qatar and Asian buyers are concluded. another LNG project on the West coast, Some volumes originally contracted for Manzanillo, which has suffered repeated terminals in the Pacifi c North America delays due to lack of available long-term could also go to Asia later in the decade. supply. The terminal is not likely to be operational before 2012. Mexico receiving fi rst cargoes at the Altamira terminal in United Kingdom: higher LNG the Gulf of Mexico terminal utilisation The Altamira terminal on Mexico’s Gulf In 2006, the Isle of Grain, the only currently Coast successfully received the country’s operating onshore LNG receiving terminal inaugural LNG cargo from Nigeria in the in the United Kingdom, received 45 cargoes,

Table 15 LNG terminals in the United Kingdom

Terminal Sponsors Status Capacity (bcm per year) Start up

Isle of Grain National Grid Operating 4.9 2005

Teesside Excelerate Energy Operating 4.0 2007 Qatar Petroleum / Late 2007 or South Hook I Construction 10.6 ExxonMobil early 2008 Dragon LNG BG, Petronas, 4Gas Construction 6.0 2008

Isle of Grain expansion National Grid Construction 8.7 2008 Qatar Petroleum / South Hook II Construction 10.6 2009 ExxonMobil Potential total 44.8

Source: Natural Gas Information 2006, IEA and company information. Natural Gas Market Review 2007 • Developments in LNG markets 103

after opening in July 2005, receiving only the large volumes from these mega facilities seven in that year. Despite the market into the United Kingdom for several years softness, importers into the terminal have from 2008. Tentative diversions to the been constantly fi lling their allocated slots Asian market in the period are likely. In the with cargoes and are expected to do so longer term (after 2011 - 2012), however, through the winter of 2007, partly because the United Kingdom market is viewed as of the perceived “use-it-or-lose-it” rule very attractive, given the decline in the on terminal capacities. Utilisation of the country’s gas production, and competition Teesside dockside LNG terminal, which was from continental Europe for North Sea gas. developed by the United States’ Excelerate Energy and started operations in February Belgium: expanding LNG terminal (only ten months after the project was and third-party access announced in April 2006), is likely to depend purely on prevailing prices in the United Belgium has an LNG receiving terminal at Kingdom and other markets, as this terminal Zeebrugge, built in 1987. Suez’s Distrigaz is designed to meet winter peak usage (up subsidiary owned 100% of the capacity to 11 mcm per day). Cargoes reserved for until 2006. As expanded capacity comes this terminal could be easily diverted to online in the second quarter 2007, the the other terminal of the same operator in number of capacity holders at the 9 bcm the United States’ Gulf of Mexico or sold to per year terminal rises to three: Distrigas other higher paying customers. (2.7 bcm per year for 20 years), a joint venture between Qatar Petroleum (QP) Likely tentative diversion of and Exxon Mobil (4.5 bcm per year for 20 LNG to Asian markets from years) and Suez (1.8 bcm per year for 15 the United Kingdom years). To facilitate European Commission approval of their proposed merger, Gaz Due to the low prices in the United Kingdom’s de France and Suez in September 2006 market due to increased pipeline supplies proposed creating new gas competitors in from Norway, Qatari LNG marketers, who France and Belgium. The companies would have two 10.6 bcm per year (7.8 mtpa) set up three structures in Belgium out of liquefaction trains primarily targeting the Fluxys, another Suez company. Through United Kingdom markets, may not place all one of them, Fluxys International, the

Table 16 LNG terminals in Belgium

Terminal Sponsors Status Capacity (bcm per year) Start up

Zeebrugge Fluxys Operating 4.5 1987

Zeebrugge expansion I Fluxys Construction 4.5 2007

Zeebrugge expansion II Fluxys Proposed 9.0 2011

Potential total 18.0

Source: Natural Gas Information 2006, IEA and company information. Natural Gas Market Review 2007 • Developments in LNG markets 104

Table 17 LNG terminals in France Terminal Sponsors Status Capacity (bcm per year) Start up

Fos-sur-Mer Gaz de France (GdF) Operating 7 1972

Montoir de Bretagne Gaz de France (GdF) Operating 10 1982

Fos Cavaou GdF, Total Construction 8.25 2nd Half 2007

Montoir expansion Gaz de France (GdF) Open Season 2.5-6.5 2011, 2014

Bordeaux (Le Verdon) 4Gas Proposed 6-18 2011

Antifer (Le Havre) Poweo, CIM Proposed 8-15 2011

Dunkirk EdF Proposed 6-12 2011

Bordeaux (Le Verdon) Endesa Proposed 4-8

Potential total 52-85

Source: Natural Gas Information 2006, IEA and company information. merged group would retain the effective per year in 2009) receiving a positive ownership of the Zeebrugge terminal. response to its environmental impact Fluxys says it will facilitate secondary statement from government regulators capacity rights trading at the terminal. and the Gas Access to Europe (Gate) project (8 - 12 bcm per year in 2010) securing New and expansion plans customers for 5 bcm per year of access at advancing in the Netherlands, the terminal. Taqa - the national energy Spain, Italy and United Kingdom company of Abu Dhabi, the United Arab Emirates - announced in February 2007 Four LNG terminals are being planned in that it is going to build an LNG installation the Netherlands. Two import projects off the coast near Rotterdam, utilising proposed for Rotterdam in the Netherlands onboard regasifi cation technology and are making progress, with LionGas (9 bcm offshore depleted gas fi elds for gas

Table 18 LNG terminals in the Netherlands Terminal Sponsors Status Capacity (bcm per year) Start up Rotterdam (Gate) Gas Transport Services, Vopak Proposed 8 2010

Rotterdam (LionGas) 4Gas Proposed 9 2010

Rotterdam (offshore) Taqa Proposed ?

Eemshaven ConocoPhillips, Proposed 5 2011

Potential total 22.0

Source: Natural Gas Information 2006, IEA and company information. Natural Gas Market Review 2007 • Developments in LNG markets 105

Table 19 LNG terminals in Spain

Terminal Sponsors Status Capacity (bcm per year) Start up

Barcelona Enagas Operating 17.3 1969

Huelva Enagas Operating 13.6 1988

Cartagena Enagas Operating 9.9 1989

Bilbao Bahia de Bizcahia* Operating 8.0 2003

Sagunto Saggas** Operating 6.0 2006

Mugardos (El Ferrol) Reganosa Group*** Construction 3.6 2007

Sagunto expansion Saggas Proposed 2.0 2008

El Musel Enagas Proposed 7.0 2011

Bilbao expansion Bahia de Bizcahia Proposed 2.5 -

Potential total 69.9

*BP, Repsol, Iberdorola, EVE. **Endesa, Iberdrola and Union Fenosa Gas along with the Oman government. *** Endesa, Union Fenosa Gas, Galicia’s Tojeiro group, Algeria’s Sonatrach, the Galician government, Caixa Galicia, Banco Pastor and Caixanova. Source: Natural Gas Information 2006, IEA and company information.

Table 20 LNG terminals in Italy

Terminal Sponsors Status Capacity (bcm per year) Start up

Panigaglia GNL Italia (Snam) Operating 3.5 1969 Qatar Petroleum, Rovigno offshore Construction 8.0 2008 ExxonMobil, Edison Livorno offshore Endesa, Amga, Belleli Construction 3.0 2009

Brindisi BG Group Site preparation suspended 8.0 2010

Potential total 22.5

Source: Natural Gas Information 2006, IEA, company information. storage. ConocoPhillips and Essent Energie been granted some approvals. In the United are planning their terminal at the Port of Kingdom, in addition several expansion Eemshaven in the North . phases at the operating Isle of Grain terminal and two land-based projects in Italy, which has one operating terminal Milford Haven in Wales, the United States’ Panigaglia, has several LNG terminal plans Excelerate Energy Teesside terminal in under regulatory review, some of which northern England entered service early in (Livorno, Brindisi and Rovigo) have already 2007. Natural Gas Market Review 2007 • Developments in LNG markets 106

In total, these plans, in France, as well as generators to burn more gas, in the latter those in Italy, Spain, United Kingdom, half the sales declined by 5% on year-on- Netherlands (Rotterdam in the south, and year basis due to the milder weather. Eemshaven in the north), and Germany, indicate that companies expect healthy Over the next decade, the government demand growth and prices stable and projects that gas demand will grow by high enough to justify their LNG import about 5% annually, to over 41 bcm per plans. Interest in using terminals is strong, year (30 mtpa) by 2017. including cross-border fl ows from the terminals (e.g. EdF’s capacity commitment In addition to the high demand growth, for 3 bcm per year at the -Vopak the seasonal difference of consumption Gate terminal in Rotterdam). is another important issue. Winter peaks are 2.5 - 3 times as big as summer lows. In Japan fuel switching and nuclear order to handle seasonal fl uctuations, the problems boost gas demand company plans to increase LNG storage capacity from current 4 880 000 m3 to Japan is currently the largest importer of 8 240 000 m3 (+69%) by 2013. Kogas has also LNG in the world and is expected to be signed an initial agreement with Oman’s for several years to come. The country state gas company to build and operate two has 28 LNG receiving terminals nominally 200 000 m3 tanks in the sultanate. Kogas capable of regasifying 230 bcm per year has also talked with the sponsors of an LNG (170 mtpa) of LNG, used by 17 companies. storage hub project in Dubai. While Kogas Fuel switching in the industrial sector (a has some winter-weighted contracts, +13% gas demand increase in 2006) and storage continues to be the key. nuclear problems supported an increase in LNG imports in 2006 (+7%, or +5.4 bcm Chinese Taipei’s second (4 million tonnes) to 86 bcm (62 million terminal is under construction tonnes) in total). Another notable point in the year was increasing imports from Chinese Taipei’s CPC Corporation started the Atlantic Basin, which represented a importing LNG at Yung An terminal in third of the year’s incremental imports, the southern part of the island in 1990. compared to no spot cargoes from the The island’s LNG import growth was 8.4% Atlantic in 2005. in 2006 with an import total of 10.5 bcm (7.7 million tonnes), compared with an Korea’s demand up in the fi rst average 10.0% growth a year experienced half, down in the second 2006 since 2001, due to the slow down of deliveries from Indonesia. The loss was 0.5 Gas sales by Korea Gas Corporation (Kogas), bcm (0.4 million tonnes) in 2006 in total, the state-controlled gas importer, rose or 11% of the contracted volumes. CPC 3% to 32 bcm (23.5 million tonnes) in 2006 currently buys LNG from Indonesia and from 31.2 bcm (22.9 million tonnes) in 2005. Malaysia under long-term contracts. The While in the fi rst half of the year, demand company also has a long-term contract surged by 10%, as rising oil prices led power with Qatar’s RasGas for 4.5 bcm per year Natural Gas Market Review 2007 • Developments in LNG markets 107

(3.3 mtpa) from 2008, with 2.3 bcm per year the state of Kerala, which targets an initial (1.68 mtpa) dedicated to the 4.27 GW Tatan capacity of 3.4 bcm per year (2.5 mtpa) in power plant. The gas would be supplied 2010, eventually expandable to 6.8 bcm per through CPC’s Taichung terminal under year (5 mtpa). Petronet is also expanding construction in the central part of the capacity at the Dahej terminal from current island, targeted for completion in 2009. 8.8 bcm per year (6.5 mtpa) to 17 bcm per year (12.5 mtpa) by December 2008. China rationalizes its numerous LNG receiving plans The company says it hopes to sign a purchase agreement for 3.4 bcm per year (2.5 mtpa) China’s fi rst LNG receiving terminal in from ExxonMobil’s share of LNG from Guangdong started to import cargoes in Australia’s Gorgon project by June 2007. It May 2006. The operator of the terminal, secured recently another 2 bcm per year state-controlled CNOOC, is developing a (1.5 mtpa) of LNG supply under medium-term second receiving terminal in Fujian and is contracts from Algeria, Malaysia and BG. now forging ahead with a third facility at Those supplies are sold to the Dabhol power Shanghai (with Shanghai utility company, plant in the western state of Maharashtra. Shenergy, holding the controlling stake). The regasifi ed LNG will be transported Construction offi cially started in January through a Dahej-Dabhol pipeline, to be 2007. This may be the last receiving terminal completed in 2007. The 6.8 bcm per year to be built by the end of this decade in the (5 mtpa) Dabhol LNG import terminal will be country. Although some progress is seen in a source of gas from early 2009. projects in Hong Kong, Zhejiang, Liaoning, and Hebei, new LNG supplies are now likely Petronet is also talking with Shell to buy to be post 2012. The number of realistic 1.4 bcm per year (1 mtpa or 16 cargoes receiving terminal plans has dwindled after per year) for import through the 3.4 bcm its proliferation to nearly twenty in early per year (2.5 mtpa) Hazira terminal, also 2005, due to high global gas prices causing on India’s west coast, which is owned by a return to coal for power generation. Total Shell (74%) and Total (26%) and operated import capacity could be 15 - 20 bcm per solely with spot cargoes. Petronet intends year in 2010. to pay tolling charges to bring cargoes in through Hazira, and to sell them to the India devising ways Dabhol power plant as well. to increase LNG supply The two Indian terminals received 8.4 bcm Petronet, India’s fi rst and largest LNG (6.2 million tonnes) of LNG in total in 2006. importer, buys 6.8 bcm per year (5 mtpa) under a long-term contract from Qatar’s Singapore, Thailand, Chile, and Brazil RasGas for its Dahej terminal in the western may advance LNG receiving initiatives state of Gujarat, which started importing LNG in 2004. The quantity will increase Singapore decided to go ahead with its to 10.2 bcm per year (7.5 mtpa) in 2009. plan of 4.1 bcm per year (3 mtpa) LNG Petronet plans another terminal in Kochi in terminal plan in early August 2006, citing Natural Gas Market Review 2007 • Developments in LNG markets 108

“security of gas supply” as the main driver. Possible shipping constraints: crewing Thailand’s state-owned PTT confi rmed a plan to construct a receiving terminal on The LNG shipping industry is experiencing the east coast of the country by 2011, an unprecedented fl eet expansion. A record signing up Iranian supply. 35 ships are scheduled to be delivered in 2007, adding to the current 220 carriers. Chile has multiple plans to import LNG Another 47 ships are expected in 2008. into its central and northern regions to The global fl eet will be over 350 vessels by reduce dependence on piped imports from 2010 and is widely expected to approach Argentina. 400 by 2015. Another thing to be noted is expansion of capacity of newly built ships. Brazil’s state-owned Petrobras is developing The average capacity of a new ship delivered two dockside regasifi cation import ter- from yards will grow from 140 000 m3 in minals in the north and south of the country 2005 to 180 000 m3 in 2008. with urgent priority, endorsed by the country’s national energy policy council. The Naturally, crewing requirements have been company is initially seeking up to 2 bcm per increasing and have reached levels never year (1.5 mtpa) at Pecem in the north and seen in the LNG industry. A typical LNG 4.8 bcm per year (3.5 mtpa) for Guanabara vessel needs a complement of 27 seafarers Bay in the south near Rio de Janeiro by as comprising fi ve deck offi cers, fi ve engineer early as July 2008. Supply for these terminals offi cers and 17 crew members. Taking into will not be easy to procure. The company is account vacations, illness and turnover, also considering building a third terminal. the total requirement is 64 to 70 seafarers for each vessel. This means the additional Tight engineering market may cause 130 ships need 9 000 seafarers in 2010, delays and project cost increases including nearly 3 000 qualifi ed offi cers.

Global shortages of skilled labour forces and New trends of contractors with expertise, especially in the onboard regasifi cation LNG sector which requires special technology and engineering, have caused delays and cost LNG onboard regasifi cation technology increases in the sector. The increasing cost has recently become popular around the of new materials has also meant delays to world, due to its quicker implementation projects. The impact is greater as projects schedule than conventional land-based are planned on mega scales these days, even LNG receiving terminals, especially after though unit costs can be lowered with larger successful examples have been shown facilities. Modular construction practices by Excelerate Energy in summer 2005 may become more popular to alleviate with its fi rst offshore buoy and turret constraints in project development. While system in the United States’ Gulf of these problems are found throughout the Mexico, and in February 2007 with its energy sector, they are especially acute for fi rst dockside regasifi cation project in LNG production and import facilities. This is northeast England. discussed further in the Investment section. Natural Gas Market Review 2007 • Developments in LNG markets 109

There could be at least a few more planned projects. To date, there are three terminals with onboard regasifi cation operating LNG regasifi cation vessels technology in coming years out of twenty (LNGRVs) and six more of these specially-

Figure 25 An unprecedented fleet expansion

Capacity of total fleet (million m3 ) 50

40

300 30

20 200

10 100 Number of ships

0 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

Source: Company announcements.

Figure 26 Import terminals using onboard regasification technology

STL Buoy terminal (operation) Dockside regas terminal (operation) STL Buoy terminal (planned) Dockside regas terminal (planned)

Floating Storage and Regasification Unit (FSRU) (planned) Other onboard regasification application

Note: STL = submerged turret buoy. Source: Company announcements, media reports. Natural Gas Market Review 2007 • Developments in LNG markets 110

equipped ships are on order and more recently, even Indian LNG importers paid are on the way. Excelerate Energy and its expensive spot prices in the face of even shipping partner Exmar dominate orders. higher prices of naphtha in the country. Golar LNG is adding onboard regasifi cation on two of its vessels to convert them into In terms of LNG pricing in Japan, and in fl oating storage and regasifi cation units most of Asia, both buyers and sellers have (FSRUs). Several purpose-built FSRUs are agreed, and still continue to agree, to also planned. base the price of LNG on oil. In traditional contracts concluded before 2002, the rates of gas price increase and decrease Marketing, contracts and with oil are slowed by half outside of a spot trade evolution certain oil price range so that buyers and sellers are protected from exceptional oil price environments both at high and Stable and relatively lower low forces. This arrangement is called long-term LNG prices, the “S curve” from the shape of the oil/ consistently lower than oil LNG price graph. Over time the ‘slopes’ or rate of change of parts of this curve have Japanese average LNG import prices changed, but the basic pattern remained have been lower per unit of energy than until recently. those of crude oil for more than three years. The gap looks to be increasing From 2002 to 2004 the basic slopes were for the moment. Historically LNG prices lowered to ease linkages to oil and make were more expensive than oil, so many LNG more competitive. Flat pricing, or industrial customers have not seen the fl oors and ceilings for higher and lower price incentive to change fuel. However, oil price ranges were also introduced into due to the LNG’s linkage to oil of around some contracts during those years. 85% or less, the current expensive oil prices do not make LNG prices increase in However, after the surge in oil prices the same manner. since 2005, pricing in this unprecedented oil price range has become the main issue, This current trend creates several notable as such high oil prices was not originally changes both internally and externally: taken into account in the traditional an accelerated shift to natural gas in pricing formulas. Sellers are generally on industrial energy use (e.g. a 13% year-on- steeper slopes to fi ll the gap. year growth in industrial sector gas sales in 2006 in Japan); exceptionally expensive More tenders for spot LNG purchases to cope with the long-term volumes increased demand, which is managed by those LNG buyers with purchase portfolios During the fi rst half of this decade, tenders large enough to absorb the high price; were successfully used by buyers in China, and sellers’ arguments for price increases, Korea, and Chinese Taipei for their long- especially in higher oil price ranges. More term LNG purchases, resulting in generally Natural Gas Market Review 2007 • Developments in LNG markets 111

Figure 27 LNG and oil prices in Japan since 1969

LNG's traditional premium against oil seems to have disappeared LNG imports grew 7% in 2006 10 Industrial sector gas demand grew 13% in 2006

USD/MBtu

8

6

4

2

0

1969 1971 1973 1975 1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005 Japan LNG JCC

Note: Japan’s fiscal year: April to March. For 2006, the figure is for April to December Source: Japan’s import statistics.

Figure 28 Changing focus on price negotiations

6 14 Pre 2004 pricing example Post 2005 deal examples

USD/MBtu 12 JCC Parity JCC Parity 5 At USD60 Oil, USD10/Mbtu 10

Traditional 4 or example 8 USD8/MBtu

2002-04 example 3 6 “Out of range”

2 4 10 15 20 25 30 30 35 40 45 50 55 60 65 70 JCC USD/Bbl JCC USD/Bbl

Source: Media reports. Natural Gas Market Review 2007 • Developments in LNG markets 112

favorable pricing arrangements for those Hub, depending on specifi c contracts. buyers. More recently, a similar approach Some of the deals are structured so that is being adopted by sellers. different percentages apply above and below certain trigger points. In 2006, the North West Shelf (NWS) LNG venture in Australia, at its renewal These followed earlier marketing activities contract negotiations for volumes from in the decade targeting the United States’ 2009 with some of its long-term buyers in markets by NLNG Plus (Trains 4, 5 and 6) and Japan, invited them to submit requests for Yemen LNG, which were settled at 84% - volumes of LNG. The process apparently 85% of Henry Hub in 2003 - 2005. An even resulted in increased prices, shorter dur- earlier deal negotiated by Equatorial Guinea ation and reduced volumes. Arguably the LNG in 2003 has a percentage which varies shorter contracts can be seen as favorable according to gas prices and is below 84%. to buyers, too, because they do not want to be bound in the longer term by conditions New, more fl exible that do not refl ect market realities. marketing arrangements

Nigeria LNG (NLNG) allocated the expected Traditional LNG projects were underpinned output from its planned 7th train (“SevenPlus” by long-term sale and purchase contracts project) between the fi ve selected bidders, with consuming markets. However, more reportedly based on a sliding scale with recent projects have been sanctioned the highest bidding companies getting with upstream stakeholders purchasing proportionately more volume. The venture’s planned output, and in turn marketing aggressive asking pricing was a straight-line by themselves, either through capacity 90% of Henry Hub. The supplier can redirect and/or equity acquisition at regasifi cation cargoes into alternative destinations if the terminals in consuming countries, or Henry Hub gas prices fall below a certain even direct sales to willing buyers. Those trigger point, by paying some compensation companies with regasifi cation capacities to the buyer. in multiple consuming regions are also making f.o.b. offtake commitments to fi ll Nigerian National Petroleum Corporation those capacities or to sell to higher paying (NNPC) is conducting a tender process markets in a more fl exible approach than for its equity volume of 4.9 bcm per year previously seen. (3.6 mtpa) in OKLNG project in the fi rst quarter of 2007. There is some evidence Those projects where offtake arrangements that potential buyers had to bid at least are made in such a manner include the 90% of Henry Hub on an ex-ship basis. Four above-mentioned African projects, as well as or fi ve buyers are expected to be chosen projects in Trinidad and Tobago and Egypt. later this year. The strategy of directing output to more favorable markets is pursued in different Prices for the grassroots Brass LNG that ways also in the Pacifi c region. were negotiated in 2005 and 2006 also came in between 88.5% and 90% of Henry Natural Gas Market Review 2007 • Developments in LNG markets 113

Big drop in price expectations: Figure 29 NBP (National Balancing Point) in the United Kingdom 20

18 April 3 futures prices USD/MBtu 16 Drop in expectation 14 (USD8/MBtu!!) 12

10 8

6

4 November 27 futures prices Cash prices 2

0

May 06 Jun. Jul. Aug. Sep. Oct. Nov. Dec. Jan. 07 Feb. Mar. Apr.

Source: IEA data.

Partners in the Australia’s Gorgon projects 4.8 bcm or 3.5 million tonnes, was diverted are marketing their equity volumes into the Asian market in 2006. This trend does separately, rather than collectively as not seem to be a temporary phenomenon. one project. The North West Shelf (NWS) Some medium-term and long-term deals venture has avoided fully allocating volumes have been signed to sell LNG into Asian from Trains 1 - 3 after the existing contract markets, which were originally assigned to expires in 2009, leaving some fl exibility Atlantic markets on a long-term basis. volumes in its own hands (2 - 2.7 bcm per year (1.5 - 2 mtpa)). The venture’s operator, Pricing outlook Woodside Petroleum, is also reserving one- third of its planned Pluto output for its own As demand continues to rise and new fl exible marketing. liquefaction plants are more expensive to build, and often run over budget and These fl exible deals at loading points schedule, the LNG market looks set to remain will lead to more “spot” LNG at receiving tight in coming years. However, long-term terminals, and more “globalisation” of the pricing may not continue rising trends if industry. more supply emerges around the turn of the decade. To the extent they can, buyers Diversion of cargoes from are likely to resist long-term commitments one region to another at higher prices. As geographically fl exible and uncommitted LNG exporting capacity For the fi rst time in the history, as much as expands and unprecedented number of 6% of the Atlantic region’s LNG production, ships are delivered, short-term cargoes will Natural Gas Market Review 2007 • Developments in LNG markets 114

increase, with pricing increasingly decoupled gas source without large underground from that of long-term transactions and gas storage capacity, seasonal demand increasingly on a global basis. fl uctuations are absorbed by redundancy in LNG terminal capacities. In Europe, where “Future” prices sometimes large quantities of gas can be held in the create interesting developments system including more underground gas storage facilities, LNG terminals can enjoy Besides long-term pricing, spot and future higher utilisation rates. In the United prices have a strong infl uence on actual States, where LNG still plays a marginal cargo movements. One example is so-called role and LNG deliveries vary depending “fl oating storage”. While this method was on price differences with other markets, once used as an emergency back-up measure, utilisation of regasifi cation is rather low, for example by Spain in winter 2005/06, and the need for LNG terminal storage it was also used by some companies who capacity is not high thanks to huge have spare shipping capacity to capitalize networks of pipelines and underground on much higher winter price expectation in gas storage facilities. the summer of 2006, fresh from memories of tighter gas markets in the previous winter. Some cargoes were kept fl oating Coping with as long as fi ve months. In the end, the price Indonesian shortfalls expectations did not materialize by the start of winter 2006/07 (Figure 29). Indonesia, which enjoyed its status as the world largest LNG exporter for 22 years Peak demand, LNG terminal lost the status to Qatar in 2006. It has in recent years been cutting its contractual utilisation and seasonal LNG deliveries because of a slower-than- storage issues expected rate of gas reserves replacement as well as dwindling feed gas production. LNG terminal usage patterns differ by The reserve decline is most prevalent in region, refl ecting the structure of LNG the East Kalimantan fi elds that supply the demand in various regions. In the Pacifi c Bontang liquefaction plant. Asia, where LNG is generally used as a base

Table 21 LNG terminal regasification/storage capacity utilisation (2005) Imports/Regasification capacity Storage capacity/Imports (days) Pacific Asia 35% 36 Europe 61% 14 Atlantic America 36% 19 Worldwide 40% 29 Source: IEA data. Natural Gas Market Review 2007 • Developments in LNG markets 115

Total is the only gas producer in East Steel. Their combined contractual volumes Kalimatan that has been able to compensate of 16.3 bcm per year (12 mtpa) account to for other producers’ declines by pumping about 20% of Japan’s annual LNG imports. (27 bcm per year). Because of declining The two sides started full-fl edged dis- production from Vico and Chevron, the cussions on contract renewals in June Bontang plant in recent years has been 2004 and agreed to key commercial terms reducing LNG exports. for partial extension in September 2005, yet no fi nal agreement has been reached. In early 2005, Pertamina negotiated At least 4.1 bcm per year (3 mtpa), and the rescheduling of some 51 cargoes of potentially as much as 8.2 bcm per year its total 450 cargoes under long-term (6 mtpa) is expected to be renewed. contracts with Japan, Korea and Chinese Taipei for 2005. In December 2005, BP Since 2005 Indonesia has been giving Migas, the country’s upstream regulator, strong signals that it will in the future give and Pertamina advised that a total of 61 priority to its domestic market, as it wants cargoes would be cut from Indonesia’s to reduce its dependence on expensive 2006 shipments; 52 cargoes from Bontang imported oil. International companies are and 9 from Arun. wary about this as domestic gas prices are at least a third less than international In 2007, the Bontang plant is expected prices. Foreign companies are hesitating to to deliver 41 fewer cargoes than its develop reserves, fearing the government contractual commitment of 359. Arun will force them to sell cheaply into the expects 12 fewer cargoes this year than domestic market. its contractual commitment of 78. In total, the reduction is 12% of the original contractual volumes in 2007. The cargo The 2001 Oil and Gas Law states that all reduction equates to about 1.6-1.8% of the new contracts should refl ect the “domestic global total LNG trade, which comprised market obligation” to sell 25% of gas an estimated 3 300 cargoes in 2006. production in the domestic market. The practical enforcement of this law is not Indonesia’s LNG is supplied on mostly particularly clear, nor is future policy. This long-term contracts, with about 61% lack of clarity in the gas laws is hampering going to Japan, 26% to Korea, and the the effort to boost gas production. In early remaining 13% to Chinese Taipei. Some 2007, Indonesia revised its domestic gas Arun contracts are due for completion in policy, with new contracts expected to 2007 while Bontang contracts are due to deliver at least 42% of their production fi nish between 2011 and 2018. to local markets, instead of the 25% mentioned earlier, which could alienate Japanese buyers hope to renew contracts foreign investors even more. for half of the 16.3 bcm per year (12 mtpa) of Indonesian supply contracts set to Indonesia’s Energy Minister is apparently expire in 2010-2011. Those buyers are seeking better production sharing terms Kansai Electric, Chubu Electric, Kyushu at the offshore Mahakam Block when Electric, , Toho Gas and Nippon its contract with operator Total expires Natural Gas Market Review 2007 • Developments in LNG markets 116

Figure 30 Indonesia’s LNG sales commitments

40 Assuming 8.2 bcm out of 16.3 bcm per year up to expiry in 2010-11 is renewed Other contract renewals are not counted

bcm per year 30

20

10

0 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Japan 2010 renewal volumes Other Bontang volumes Arun Tangguh

Source: Company announcements. in 2017, including a greater share for production sharing contractors, and plans production split for the government, to complete its work by the end of the although the minister also said recently fi rst quarter of 2007. that the government is considering a new production split of 51% for the Another Japanese buyer, Tohoku Electric, government and 49% for producers, who buys 1.1 bcm per year (0.83 mtpa) from compared to the common 70-30 split. Indonesia’s Arun through 2009, signed a The minister’s idea was revealed after heads of agreement to buy 0.16 bcm per Total said it would invest USD 6 billion in year (0.12 mtpa) from Indonesia’s Tangguh Indonesia on exploration and development LNG venture in December 2006. The deal over the next fi ve years. The company runs for a period of 15 years from 2010. wants an extension of existing conditions The BP-led Tangguh venture has a contract before the USD 6 billion commitment. with the promoters of China’s Fujian terminal for 3.5 bcm per year (2.6 mtpa), The Ministry of Energy and Mineral starting in 2008. Other term deals from the Resources of the country set up a task venture include two Korean sales which force to evaluate the country’s gas balance have already started before actual start and determine how much volume will be of production from the plant: one with available for export after its domestic Posco for 0.75 bcm per year (0.55 mtpa) needs are satisfi ed. The group also includes and another 0.82 bcm per year (0.6 mtpa) representatives from upstream regulator contract with K-Power. A further 5 bcm per BPMigas, Pertamina and Indonesia’s main year (3.7 mtpa) has been sold to Sempra at Natural Gas Market Review 2007 • Developments in LNG markets 117

its Energia Costa Azul terminal in Mexico’s from Pertamina’s wholly owned Matindok Baja California from 2008. The two-train block and the Senoro area, which is jointly Tangguh project is 55% complete as of the held by Pertamina and Medco. The blocks end of 2006. Start up is expected in late are estimated to have 2.4 tcf (68 bcm) of 2008. gas.

Pertamina announced in December 2006 Tangguh expansion that it would not extend beyond its end-2009 expiry date a 2 bcm per year The Tangguh project is considering a (1.5 mtpa) contract with Chinese Taipei’s third train to supplement two 5.2 bcm CPC Corporation, citing that Japan is being per year (3.8 mtpa) trains already under given preference as it was Indonesia’s construction to be completed in 2008 earliest buyer in 1973. CPC has another - 2009. Buyers in Japan are interested in contract of 2.5 bcm per year (1.84 mtpa) expansion volumes from the venture. Gas that expires in 2017. Subsequently Chinese reserves are suffi cient to support another Taipei has cut its 2010 demand forecast for train. Tangguh’s partners say that they LNG by almost 20%, from 17.7 bcm per year might be willing to reserve as much as (13 mtpa) announced in 2005 to 14.3 bcm 2.7 bcm per year (2 mtpa) for the domestic per year (10.5 mtpa), moving away from its sector, possibly to an import terminal policy of favouring gas to generate electric proposed by state-owned power generator power in issuing licences to independent PLN on Java. power producers after 2007. Natuna Meanwhile, a controversial pipeline project linking East Kalimantan to Java appears to In 2006, Malaysia’s state Petronas was have collapsed due to shaky economics. said to be in discussions with Pertamina Gas-fi red power plants on Java are now and ExxonMobil for pipeline gas from expected to be supplied from ExxonMobil’s Indonesia’s Natuna D-Alpha fi eld. Gas from nearby Cepu block. This could ease some the fi eld could be piped to Sarawak Island pressure for domestic use from Bontang. to provide extra feed gas for expansion trains at Malaysia LNG’s Bintulu complex. Other possible LNG export After cancelling a production-sharing plans in Indonesia agreement (PSA) with ExxonMobil for the block, Pertamina plans to renegotiate the Central Sulawesi renewal of the PSA. The block contains an estimated 222 Tcf of gas reserves with Pertamina and private upstream player high carbon dioxide content of about 70%. Medco Energi selected Japan’s Mitsubishi About 46 Tcf (1,300 bcm) of gas is believed Corporation late 2006 to be their partner to be recoverable, but the separation of in the proposed 2.7 - 3.4 bcm per year CO2 is a big challenge. (2 - 2.5 mtpa) Central Sulawesi LNG project, due to come on stream by 2009 - 2010. This plant would be supplied Natural Gas Market Review 2007 • Developments in LNG markets 118

Masela Block in the Timor Sea said the reserves might be used to feed a liquefaction plant in Indonesia, an idea that Masela Block in the Indonesian portion of Jakarta apparently still favors. However, the Timor Sea is held by Japan’s Inpex. The Inpex now says it plans to pipe Masela company claims that it has found enough gas to an LNG plant in Darwin, northern gas in the block’s Abadi fi elds to support Australian, which already hosts another a 4.1 bcm per year (3 mtpa) liquefaction 4.5 bcm per year (3.3 mtpa) LNG plant. plant starting around 2014. Inpex earlier Natural Gas Market Review 2007 • Gas for Power 119

GAS FOR POWER

Power has been the major factor driving renewables such as wind may increase gas demand growth in OECD countries the role of gas-fi red power in grids. and will be the “fuel of choice” for the vast majority of new power plants to Gas and power markets are becoming 2012. much more strongly interlinked, affecting decision making in regulation, energy Gas fi red power provides fl exibility in security, the need for gas storage, and electricity systems. The relatively low the role of renewables. capital cost of adding new capacity makes it ideal as a spare generation Power use drives reserve in electricity systems, improving reliability. gas demand growth

Gas often provides supply to meet Power generation accounted for around peak demand and often sets the price half of growth in gas use from 1990 to of power in a number of IEA markets 2004; over the most recent fi ve years, this – high gas prices can therefore mean proportion rose to nearly 80%. As OECD gas saturation is being reached, gas-fi red high power prices, but lower business power is driving growth in gas demand. risks for plant operators. Even in 2006, with gas prices high, gas- fi red power production grew in a number A new investment cycle in power of markets, most notably the United generation is approaching; planning States by 6.5%, to meet high summer now includes more coal fi red units as power demand. gas prices have risen and concerns on gas security of supply have grown. Demand for gas in power generation in the OECD increased from 213 bcm in 1990 A key challenge is to ensure that planned to 447 bcm in 2004; an annual average coal plants enter the generating mix growth of 5.4%. Growth does appear to be quickly, but climate-change policy slowing down; during 1990-1995 average uncertainty, in particular, is affecting annual growth was 7%; during 1996-2000 these investment plans. it was 5% and the last four years to 2004 it was 4%. From 1990 to 2005, the share of In the absence of sustained new coal gas-fi red power in the mix almost doubled, construction, gas will continue to from around 10% to nearly 19%. be the default option for new power generating capacity in OECD countries, Forecasts by IEA member countries indi- as nuclear will not arrive in any scale at cate a continued strong contribution the earliest until after 2015. from gas in many IEA countries, as shown in the table of the IEA’s largest electricity Renewables cannot fi ll the gap in this users excluding Japan and Spain (similar time frame if other construction plans forecasts not available to 2020). In the do not proceed. In fact, intermittent majority of cases, gas meets a high Natural Gas Market Review 2007 • Gas for Power 120

Table 22 Increase in electricity generation from gas in selected IEA member countries Increase in gross gas-fired Increase in gross total Gas as a percentage of power demand forecast power demand forecast incremental power demand Notes between 2004-2020 (Twh) between 2004-2020 growth between 2004-2020 Canada 150 185 81% Gas to replace Germany 87 -10 n/a Nuclear and coal France 57 96 59%

Italy 142 138 103%

Turkey 105 330 32% Gas to replace United 102 40 255% Kingdom Nuclear and coal

United States 447 1294 35%

Source: IEA statistics and forecasts submitted by IEA member countries. proportion of incremental demand, or United States: use of gas in substitutes for energy sources having a power generation driven by lower share (e.g. Germany). summer peak demand This growth in CCGT capacity levelled off Gas as the fuel of choice for somewhat in 2004 and 2005, mainly due new power plants, 2000-2004 to a general slow down in investment in new generation capacity after the United States investment boom. However, the Total OECD generation capacity increased lion’s share of new capacity in 2005 in by 35% from 1990 to 2004; of this more OECD was still CCGT. Some 5.5 GW of than two thirds was gas-fi red. Of the gas- CCGT capacity was added in Italy in 2005 fi red capacity built, 64% was high effi ciency (7% increase of total installed capacity), combined-cycle gas turbines (CCGTs). The 4.5 GW CCGT was added in Spain (6% vast majority of the CCGTs were added in the increase of total installed capacity), and United States although CCGTs accounted 14 GW in the United States. Over two for 22% of total OECD capacity increase thirds (70%) of new plants that came into in 1990 - 2004. So much gas-fi red capacity operation in IEA Europe in 2005 were gas- was built that it oustripped demand for fi red. In IEA North America the share was power, and many CCGTs are now operating 78% and in IEA Asia and Pacifi c it was 22%. at less than 35% load factor. Because of this there is substantial latent demand for With the additional generating capacity, gas in the power sector without any new gas was able to fuel a signifi cant share investment in capital stock. This dynamic is of the increase in IEA power generation a very important legacy of the 2000 - 2004 between 2000 and 2004 (Figure 32). investment period. However, coal and nuclear capacity has Natural Gas Market Review 2007 • Gas for Power 121

also been up-rated or returned to the mix. The United Kingdom is a good example of In 2005, gas-fi red generation contributed the increasing importance of gas in power a lower share of the increasing power generation, but also its close interaction needs, because high gas prices provided with coal-fi red generation, particularly strong incentives for an increase in coal- in competitive markets. Figure 33 shows fi red generation from existing plant. power generation by fuel as shares of

Figure 31 Electricity consumption in selected months since 2001

25 United States: use of gas in power generation driven by summer peak demand

bcm

20

15

10

5

0 2001 2002 2003 2004 2005 2006 January July August December

Figure 32 OECD power generation growth

Gas provided 3/5 of OECD power sector growth 2000-04

TWh 500 534.1

400

300 322.1

200

100 135.7 101.1 74.1 0 -43.7 -55.2 Gas Coal Others Nuclear Hydro Oil Total -100

Source: Electricity Information 2006, IEA. Natural Gas Market Review 2007 • Gas for Power 122

Shares of coal-fired generation in the United Kingdom Figure 33 were at their highest level in a decade in 2006

100%

80%

60%

40%

20%

0% 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006p Coal Gas Nuclear Oil Hydro Other

Note: 2006 data are provisional. Source: DTI. total generation in the United Kingdom. Enormous scope still exists for increased Total power generation increased by 25% demand for gas for power generation, from 1990 to 2005. The importance of gas because gas-fi red plant tends not to be has increased considerably since 1995, used as base load plant, as illustrated in starting from more or less zero in 1990. Figure 34. Hence, the share of gas-fi red This increase was at the expense of coal capacity is considerably higher than the and nuclear power. The share of coal-fi red share of gas-fi red generation output. generation decreased from some 65% in If gas prices stay competitive, or other 1990, to 50% in 1995 and to below 40% energy sources are not available, because since 1997. But the share of coal and gas of delays in new plant construction or has varied considerably around the same reductions in output from existing plant, levels since then. The share of electricity existing gas-fi red capacity can be utilized generated from coal increased sharply more extensively, of course driving gas from 34% to 39% in 2006 displacing gas demand upward. and nuclear. This was caused by higher gas prices, especially at the start of the year. There has been signifi cant investment in But by the end of 2006, as gas prices fell, wind power in countries such as Spain and the process had reversed and gas was once Germany, on the back of sustained high again the fuel of choice. subsidies, including fi xed feed in tariffs. In Germany, some 17GW of wind power Natural Gas Market Review 2007 • Gas for Power 123

Gas-fired generation capacity and gas-fired electricity Figure 34 production in OECD countries, as a share of total

30%

25%

Shares of total 20%

15%

10%

5%

0% 1999 2000 2001 2002 2003 2004 2005 Gas-fired generation output Gas-fired capacity

Source: IEA statistics.

(about 17% of capacity), generates close Energy Information Administration (EIA) is to 5% of electricity production. Apart projecting a 2:1 ratio for gas-fi red versus from this considerable investment in coal-fi red capacity additions in the 2006- wind power capacity, there was an almost 2010 period, a 1 to 1 ratio for the 2011- exclusive focus on CCGTs in most of the 2015 period and an approximately 2:3 split IEA in the past decade. And forecasts from for the 2016 - 2020 period. In Germany a many IEA countries show a prominent role high level of new investment activity is for gas. proposed and a high share of the planned plants is coal-fi red. The German Electricity However, high gas prices and security Association estimates that 31.5 GW of new concerns are driving a rethink of this generation capacity will be commissioned approach. Looking forward, this almost by 2012, of which roughly one-half is coal- complete dominance of CCGTs is showing fi red, one-quarter is gas-fi red and the rest signs of change in several countries. is renewables, mainly wind. Another 13 GW The United States’ generation sector is is proposed in Germany by 2016 of which turning its interest towards building more about 5 GW are renewables, 4 GW are gas- effi cient new coal-fi red power plants and fi red and 3.5 GW are coal-fi red. In Australia, considering building new nuclear reactors. close to 4.5 GW is either under construction In its latest Annual Energy Outlook pub- or in advanced planning, with most of the lished early in 2007, the United States’ expected capacity additions to be gas- Natural Gas Market Review 2007 • Gas for Power 124

fi red and renewable (gas will go from 14 the projected increase in gas demand for to 20% of power by 2020). In Japan, the power generation. Gas-fi red generation government is considering plans to build is projected to contribute to about one around 12 additional nuclear reactors over third of the projected increase in power the next decade. It has also set a target of generation to 2015, corresponding to 3 GW installed capacity from renewable 661 TWh. (around 160 bcm of new gas power by 2010. In Korea, more than 19 GW demand at current effi ciencies). To 2030, of new capacity is expected to be on line WEO 2006 anticipates that gas-fi red power by 2017, which will include 9.6 GW of will more than double, despite a higher price nuclear, 6.1 GW of coal-fi red capacity; the outlook than a year earlier. remainder is composed of renewable, oil, hydro and gas-fi red. Economics of gas-fi red According to the most recent Platts generation database (Platts, 2006) 62% of plants under construction in IEA Europe are gas-fi red, and 53% of planned plants are gas-fi red. For IEA The economics of gas-fi red generation, North America the corresponding shares and its competitiveness relative to other are 49% under construction and 32% of generation technologies, depend on a planned plants. In IEA Asia & Pacifi c 27% number of key variables, including capital of plants under construction and 30% of costs, fuel costs, planning and construction planned plants are gas-fi red. This represents time, operating and maintenance, capacity an increase in planned coal fi red plants, but factors, cost of capital, plant life and planned plants do not generate electricity. discount rates. The competitiveness of The challenge is to take these plants various technologies can be assessed on from planned to construction through to the basis of the levelised lifetime costs, completion speedily. Uncertainty on future essentially a measure of the real average climate change policy is a primary factor generation costs of a technology over the in Europe, (and to a lesser extent North economic life of a power plant. America) slowing these plans. Coal fi red plant investments cost more than double Fuel costs as a share of total generation gas investments, using signifi cantly more costs vary signifi cantly among technologies. risk capital while coal fi red power, even at Wind has no fuel costs. For nuclear power, best practice has double the greenhouse fuel costs represent a small component of signature of gas-fi red CCGT. nuclear power generation, between 8 and 11%. For CCGTs, fuel costs account for The IEA World Energy Outlook 2006 projects about 75% of total costs. A 50 % increase that 681 GW of new generation capacity in uranium, gas and coal prices would will have to be built by 2015 in the OECD increase nuclear generation costs by about to replace retired plants (215 GW) and to 3%, coal costs by about 20% and CCGT meet increasing demand (466 GW). About costs by about 38% (IEA, 2006). Considering 30% of these new builds are projected to that the price of natural gas tends to be be gas-fi red. These plants are also driving volatile in some markets, this seems an Natural Gas Market Review 2007 • Gas for Power 125

Gas prices in the USD 4-6 /MBtu range over Figure 35 the long term are pivotal for the economics of CCGTs

Gas price (USD/MBtu) 45678 80

70

USD/MWh

60

50

40 40 45 50 55 60 65 70 Coal price (USD/tonne) Pulverised coal Wind Nuclear CCGT

Source: IEA.

important drawback for CCGTs. However, Pulverised coal-fi red plants remain more it must be remembered that where gas competitive than nuclear power plants sets the marginal price of electricity, until coal prices rise above USD 70 /tonne. (increasingly the case in a number of IEA These results were obtained using a generic countries) this volatility can be recovered utilisation factor of 85% for nuclear, coal from the market. In that case, of course, and CCGT. high gas prices directly translate into high electricity prices, which may be a severe The combination of high fuel cost problem for electricity intensive industry dependence and low investment cost in particular, and all consumers in general. dependence improves the actual market situation for CCGTs. Investment costs in a Figure 35 shows the sensitivity of gas- and power generation plant can be considered coal-fi red plants to changes in gas and coal “sunk costs” from the moment they are prices, at a discount rate of 6.7% (i.e., the incurred. Once a plant is commissioned, the low discount rate case in WEO 2006). The marginal cost of producing an additional cross-over point between nuclear and CCGT unit of electricity should determine its generating costs occurs when gas price operation (dispatch). Marginal costs more reaches USD 5.70/MBtu. In other words, or less correspond to fuel costs; thus, CCGTs CCGTs have lower levelised costs than often have the highest marginal costs, even nuclear at gas prices below USD 5.8 /MBtu. at relatively low gas prices. CCGTs are often Natural Gas Market Review 2007 • Gas for Power 126

the marginal plants that determine the price tariffs. Only if there is a pool of potential in competitive markets. Hence, increases technologies to choose from can a price in gas prices are passed on to increases in on CO2 emissions fundamentally change wholesale electricity prices; as noted above investment decisions. Excluding nuclear this can have severe consequences for power as an option (as is happening in a some if not all consumers. High gas prices few IEA countries) reduces real generation make other alternative technologies more options considerably. If local conditions are competitive, but as long as the costs are not favourable for nuclear, the only option covered, CCGTs may still be perceived as the to reduce CO2 emissions may be to shift least risky way to earn a profi t, particularly from coal to gas and renewables. given lower up front investment costs.

In markets where there is a CO2 price, the Gas-fi red generation economics of gas-fi red generation, wind capacity adds fl exibility and nuclear would improve relative to coal-fi red generation. Hydro power, CHP, biomass and distributed generation also The relatively low investment costs of have clear advantages over coal and gas- CCGTs have a profound impact on the way

fi red plants in terms of CO2 emissions. These power generation portfolios are developing, technologies may have competitively low and on the way gas-fi red power generators levelised costs when benefi cial conditions behave as gas customers. The principles support their use (access to hydro reservoirs, and incentives that drive CCGTs as gas heat demand or cheap biomass) or when customers are illustrated in Figure 36. underwritten by guaranteed high feed-in

Coal and gas-fired generation often sets the price in competitive electricity Figure 36 markets and the merit order is highly dependent on coal and gas prices Demand Supply

Price/MWh Oil & old plants

Depending on gas & coal price Gas

Coal Nuclear

Must run (for example wind) MW

Source: IEA data. Natural Gas Market Review 2007 • Gas for Power 127

Ranking of generation plants according to generation as a share of total generation, and a merit order of marginal costs is the corner the difference between monthly averages of stone of achieving optimal dispatch. The gas and electricity prices. marginal MWh of demand should always be met with the MWh of supply that has The share of gas-fi red generation in Texas the lowest marginal cost. In a competitive is seasonal with high shares during the market the cost at which the marginal high loads of summer, and lower shares MWh is bid into the market also determines during the winter. The difference between the market price. Figure 36 shows a merit electricity and gas prices is an important order that is often seen with the current driver. Gas power shares are generally high high gas prices, but the ranking of coal and when the spark spread (electricity-prices- gas will change according to the relative minus-gas-prices) is high, and the shares are prices of those fuels. Gas has a particular low when the spark spread is low. advantage in meeting demand growth that is low, uncertain, and becoming As noted earlier, the price of fuel is a primary increasingly volatile. risk factor for gas- and also to a certain extent coal-fi red plants. One measure Market experience from Texas illustrates to manage these risks is to diversify and the interaction between electricity prices ensure fl exibility in the generation portfolio and gas prices well. Figure 37 shows gas-fi red to be able to switch between technologies

Gas-fired power generation as share of total generation in Texas, and Figure 37 difference between electricity price in Texas and gas price at Henry Hub

100% 100

90% 90

80% 80 USD/MWh

70% 70

60% 60

50% 50

40% 40

30% 30

20% 20

10% 10

0% 0 Jan-04 Apr-04 Jul-04 Oct-04 Jan-05 Apr-05 Jul-05 Oct-05 Jan-06 Apr-06 Jul-06 Oct-06 Generation from gas, % share of total Electricity less gas price, USD/MWh

Source: EIA, PUCT, NYMEX, ERCOT. Natural Gas Market Review 2007 • Gas for Power 128

to a certain extent. In the past, with The need for and value of fl exibility in nuclear, coal and oil fi red generation as the electricity systems is likely to increase. principal elements in the generation mix, Un-subsidised wind power on good wind such hedging through diversifi cation was sites is competitive with conventional expensive, due to the high investment costs. technologies when there is a price on CO2 Nevertheless, within the fully regulated emissions. Many countries have specifi c environments that existed it was possible to support mechanisms for renewables, and ensure diversifi cation and reserve capacity wind power is the largest benefi ciary of by passing the cost to the consumer. these subsidies, driving a global average annual capacity increase of almost 30% The low investment costs of CCGTs have during the past decade, although capacity changed this balance. In the past, older coal factors are low. Wind-power is intermittent and oil fi red plants were traditionally kept and diffi cult to predict precisely. It in operation to serve mid-merit and peak therefore requires alternative fl exible load. Today, new CCGTs end up fi lling that resources to be integrated into the grid. role. One of the consequences is illustrated At low shares of total installed capacity in Figure 34. CCGT capacity increased from this requirement is met with the fl exibility a share of 18% in 1999 to 28% in 2004. that already exists in electricity systems, Gas-fi red generation as a share of total including from hydro plant. When the generation only increased from 15% to share increases above a certain threshhold 18% in the same period. Installed gas-fi red (depending on the specifi c characteristics generation capacity in IEA countries only of the system) more fl exibility will had a utilisation rate – capacity factor – of have to be added to the system. With 31% in 2004. CCGTs seem to have added low investment costs and high running considerable fl exibility into electricity costs, gas-fi red generation is the least systems because they are responsive to cost option in most circumstances. Thus, demand. This volatility of power demand demand for the operational and fi nancial therefore feeds through to a very variable fl exibility that gas-fi red generation can gas demand, increasing the need for short- offer is likely to increase with the increase term fl exibility in the gas value chain – e.g. of the share of intermittent renewables, storage. such as wind-power. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 129

NON-OECD COUNTRY/REGION UPDATE

Russian Federation Russia is so important to the world because future trends in Russian gas exports to Russia holds the world’s largest gas reserves Europe are a key factor in determining the and produces and exports more gas than degree of tightness in global gas markets any other country, accounting for almost and pressures on alternative sources. If its a third of imports into IEA Europe in 2005 exports to Europe are lower than planned (26% of imports into the EU in 2005). – irrespective of contractual arrangements – Europe will tend to import more from the Worries about general upstream gas in- Atlantic LNG market, drawing LNG from vestment worldwide also apply to Russia, the Pacifi c (as mentioned in the separate but here the level of concern is amplifi ed section on regional supply and demand). because of the crucial importance of Russia If LNG fl ows to IEA North America in the as the largest player in the globalising gas medium term are substantially lower than market. projected, then the fundamentals of North American gas supply will be affected. The gas trade between Russia and Europe No single factor better illustrates the is critically important for ALL nations with globalisation of the gas market than the an existing or potential stake in the global consequences of too little, or too much, gas business. Russian gas exports to Europe.

Summary Recent commercial disputes with its neighbours that have cascaded into We note that Gazprom has ambitious Western markets have caused many ob- plans to expand production in the existing servers to question Russia’s ongoing producing region of Nadym-pur Tazov commitment to reliable supply. However, (N-P-T) to 2010 as well as produce fi rst Russia’s long and proud history as a reliable gas from Yamal in 2011. In meeting these supplier of gas to Europe suggests that it aggressive deadlines, there is a risk that is Russia’s intention to honour contractual Gazprom’s plans are subject to the same commitments to trade partners in IEA and slippage and cost overruns we are currently the EU. But, for good intentions to translate seeing across the world. Such delays and into results, there must be real investment cost overruns in the N-P-T region could – particularly, but not solely into future leave the global gas balance looking clearly production and transport of gas. stretched before 2010, while slippage on such a major project as Yamal would have In a fully competitive, transparent upstream the same effect after 2010. In short, the gas market, stakeholders can gauge level of investment that we see in Russia the suffi ciency of investment through, seems inadequate to deliver the planned amongst other indicators, price effects. production on time, yet the problem may Gazprom has a gas export monopoly in partly be due to inadequate transparency Russia, it owns the transportation system in communicating Gazprom’s investment and two thirds of the gas reserves. In the and delivery plans. case of such a dominant company, there is no need to respond to gas prices by Natural Gas Market Review 2007 • Non-OECD Country/Region Update 130

Figure 38 Russia/European pipeline trade affects global gas balance

Historical Projection Projection 700 Base case Low case Base case Low case 600

500

bcm per year 400

300

200

100

0 2004 2010 2015 OECD Europe production (consumed internally)* OECD Europe imports from Russia** OECD Europe call on other imports (inc global LNG)*

Source: IEA. * Information from Supply/Demand section. ** Base case: Russian Government Energy Strategy (2003) total projected exports to IEA Europe. ** Low case: IEA scenario based on restrained investment. Note: We have assumed total Russian exports per Russian Government Energy Strategy (2003) less 77 bcm of Russian gas flows to countries other than OECD Europe for all future periods (Russia supplied 77 bcm to these countries in 2005). We assume that Chinese export plans made in 2006 do not form part of this 2003 Energy Strategy. increasing investment, as competitors At 430 bcm in 2005, the Russian domestic can not erode its market position despite gas market is the world’s second largest after favourable economics. At the same time, that of the United States and recently has the risks to Russia and its trade partners been growing substantially – driven, as in of relying on one company for all exports IEA countries, by growth in power demand are considerably higher than the risks of and an ongoing programme of gasifi cation exposure to an industry. (increasing penetration of the domestic market). The reasons for growth of gas use in Exports to Europe are of high importance power generation are however different from to Russia. Such exports account for around those in IEA countries as Russia has old or 27% of volumes sold and roughly 60% of underused gas-fi red power stations now being Gazprom gas revenues. However, we are returned to service or used at higher capacity keenly aware that Russia not only provides factors. Despite the ineffi ciencies, these plants gas exports to world markets, but also has are cost effective because of the artifi cially commitments to a large domestic market low price of gas (see below discussion of which accounts for two thirds of gas “Domestic price reform”). Gazprom base-case produced. Russian per capita consumption demand projections are based on a 2 bcm/year of gas is similar to that in Canada, but growth in domestic demand while alternative consumption per USD GDP is roughly fi ve scenarios show as much as 6-8bcm/year times higher than IEA countries. growth in domestic demand. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 131

Russian gas use in the power sector (including Upstream investment heat) was estimated at 224.4 bcm in 2004, accounting for 420 TWh of electricity The IEA’s World Energy Outlook 2006 generation. Between 2001 and 2005 gas (WEO 2006) projects that an average of demand grew 29 bcm (about the total USD 17 billion per year would need to be consumption of Korea in 2005), half of which invested in the Russian gas sector to meet was from power demand. Gazprom reports projected supply growth, including projected that demand grew by 14 bcm in 2006. in-terregional trade. This is subdivided into approximatly USD 10 billion needed On the surface, the key issues of concern to for upstream exploration and production world gas markets are a consideration of the and USD 7 billion for transportation infra- rate of future Russian gas production and structure. One of the reasons that the of the rate of increase in Russian domestic investment requirements are so great demand; however, there are many other in the case of Russia is because some factors which complicate the picture. We major fi elds which provided the bulk of note with concern that reduced Russian Russian production are now declining. This gas fl ows to the domestic power sector investment fi gure also recognises that there and heavy industry have recently forced has been considerable cost infl ation in the these users to decrease the amount of petroleum sector in the past years and has gas consumed. Recent announcements by therefore been adjusted upwards from the various members of the government and annual investment of USD 15 billion cited industry leaders seem to point to a potential in the WEO 2005. domestic gas shortage. In August, the Russian economics minister was quoted14 As the owner of the Russian pipeline as saying that the Russian domestic gas system and developer of the Yamal region, market may face shortages of 5 - 6 bcm Gazprom is called upon to account for the over 2007/09, as domestic consumption vast majority of upstream and almost all is expected to grow by 26 - 27 bcm, while of pipeline investment. In early January output is forecast to rise by only 21 bcm. 2007, Gazprom announced its Investment Program for 2007 which earmarked about Deepening the analysis reveals many USD 14 billion as capital investments. It factors which affect gas fl ows to and from was stated that this total does not apply the Russian unifi ed gas supply system exclusively to investment in the upstream (UGSS). We analyse each of these factors gas sector, but also to other sectors. From in detail below, discussing the potential the projects listed in the investment upside and downside risks attributable to programme, we have identifi ed plans to each factor. spend USD 3.85 billion on new upstream production in 2007.

14. Interfax (17 August 2006). Natural Gas Market Review 2007 • Non-OECD Country/Region Update 132

Major upstream investments in 2007: a much higher rate of investment at the Kharvutinskaya of the Yamburgskoye moment. The scale of the project and its fi eld: USD 1 billion. unique environmental challenges raise concern about timely delivery. Bovanenkovskoye and Kharasaveyskoye fi elds: USD 1 billion. In short, given the substantial decline in Yuzhno-Russkoye fi eld: USD 0.8 billion. existing production, we would encourage Shtokman fi eld: USD 0.65 billion. Gazprom to provide greater assurance that it is investing in enough production Prirazlomnoye fi eld: USD 0.4 billion. to guarantee gas supplies to customers. Our analysis of investment plans suggests The details that Gazprom gives for its that there could be a substantial risk of investments are vague when compared underinvestment in the Russian upstream with the details that are given, for in general, particularly with respect to example, by Saudi Arabia with regards the Yamal development. We believe that to oil investments which are similarly this risk of underinvestment increases important with regard to that market. As in light of the additional likelihood of with Saudi investments, the market would delays and cost overruns in execution of take considerable comfort from knowing such a challenging project, noting that which Gazprom fi elds will be brought such delays are being seen worldwide (see online at what production levels and when, separate section on Investment). as well as exactly how much the company will invest in each fi eld in order to ensure Import dependence the plans are carried out. The Russian gas pipeline system was The planned production growth of N-P-T conceived in the Soviet era, built on the basis region is the only source of new gas of two sources of natural gas reserves – the output in the period to 2010 according to major fi elds of West Siberia and those of Gazprom information. Despite Gazprom’s Caspian states (, Uzbekistan ability to date to meet its production and ) which then made up part targets in this region, we are not confi dent of the Soviet Union. After the break up of that enough investment is being made to the Soviet Union, historical trade fl ows expand production. were formalized by long-term contracts which codifi ed the interdependencies. In-depth details of planned development Turkmen gas was, for instance traded schedules for the Yamal region would for cash and goods from under reassure consumers of Gazprom target long-term contract rather than under the to produce fi rst gas in 2011, as well as direction of the Soviet government. the expected 140 bcm per year by 2015. We are only aware of USD 1 - 2 billion While “Turkmen gas” still ostensibly of investment in this region. If fi rst gas fl ows to Ukraine, the key sections of the production from Yamal is to be delivered transportation system used are owned on time in 2011, we would expect to see by Gazprom (the UGSS). Gazprom holds Natural Gas Market Review 2007 • Non-OECD Country/Region Update 133

Figure 39 Gas infrastructure of Russia

Producing region Gas pipeline UK Prospective region NORWAY Gas pipeline planned or proposed Selected gas fields SWEDEN Shtokmanovskoye LNG export plant under const. NETH. DEN. FINLAND 0 Miles 500 Export to GER. Finland 0 Km 500 EST. Yamal Peninsular CZ. POL. REP.Export to St. Petersburg LAT. Komi Vankor East Europe LITH. S. Russkoye SLO. REP. Minsk Yamburg Siberia Northern Lights Ukhta Zapolyarnoye Yakutsk HUNG. BEL. Urengoy UKR. ROM. Moscow Urengoy MOL. Kiev Sakhalin Chisinàu RUSSIA Surgut Yurubcheno- Lena- Export to Komsomolsk Europe Odessa Petrovsk Tokhomo Tunguska Volga- West Urals Khabarovsk Tyumen Siberia Kovykta Orenburg Krasnoyarsk North Volgograd Omsk Tomsk Caucasus Kemerovo Daqing Novosibirsk GEORGIA Novokuznetsk Irkurtsk Harbin TURKEY Tbilisi Aqtaù Astana ARM. CHINA JAPAN AZER.Baku KAZAKHSTAN Ulan-Bator NORTH SYRIA KOREA Shah-deniz MONGOLIA TURKMENISTAN REP. OF IGAT Nabit-DagUZBEKISTAN KOREA (from Iran) Almaty Beijing Ashgabat CHINA KYRGYZSTAN

IRAN Dushanbe TAJIKISTAN The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source: IEA. an import and export monopoly in Russia use. New export routes from the with few (specifi c) exceptions. This export Caspian region could put pressure on monopoly means that volumes leaving Russia’s long-term import agreements/ Russia to Ukraine come from Gazprom, expectations over time. Both China and whether or not the contracts with Ukraine the EU would like to tap resources in and Central Asia net off in its portfolio. the Caspian region in the medium term, Similarly, existing gas fl ows from Turkmen as discussed in the separate section to Ukraine through Russia must be planned covering Central Asia. within the context of the capacity of the The existing pipeline from the region into UGSS. Whether or not they are destined for Gazprom’s “Unifi ed Gas Supply System” Ukraine, some projections show Turkmen – the Central Asia Centre (CAC) is capable gas fl ows to Russia increasing to 80 Bcm of operating at only 50 bcm throughput, in 2010, a substantial volume equal to the well below . It is in total imports of Germany. urgent need of refurbishment. Gazprom has delayed refurbishment of the pipeline There are several risks in Russia’s strategy until an international audit of Turkmen of relying on future imports from Central reserves has been performed. Asia: The last time there was an audit of the Caspian gas reserves should not be actual reserves in place in the region was regarded as exclusively for Russian

in Soviet times. This audit confi rmed that 7 © OECD/IEA, 200 Natural Gas Market Review 2007 • Non-OECD Country/Region Update 134

there were at least 3 tcm of reserves in before 2015. Not least, we are aware that the 1980’s but of course a portion of this in 2006, Turkmenistan signed a long-term has been produced since then. agreement with China for the export of 30 bcm per year starting in 2009 There could be considerably more than albeit from Turkmenistan’s under-developed enough reserves in the Caspian region, Eastern fi elds. Furthermore, we are aware but an offi cial audit is needed to confi rm of no large-scale investment into new this. production in Turkmenistan, the only Caspian state with reserves to support it. Duma deputies and energy policy makers appear to have recognized the risks of relying Eastern export strategy on Central Asian gas and have called for a co-ordinated approach to gas exports from Energy exports to China are important the region. In this way they hope to ensure to Russia in the longer term, given its Turkmen gas uses the Russian system rather interest to diversify its export markets. than competing against Russian export Developing the oil and gas resources of plans to Europe and China. Turkmenistan East Siberia meets Russian economic as Eastern reserves and the Chinese West-East well as social and political objectives. The gas pipeline systems are already a relatively reserves currently supplying European short geographical distance from each other markets in Western Siberia, however, (compared with the length of pipelines could not be economically targeted for already in place) as discussed in the separate Eastern Markets given the presence of section on Central Asia. other reserves much closer to the East. Russian references to West Siberian gas The increasing nominal price that Gazprom when discussing its “Eastern Ambitions” is prepared to pay to Turkmenistan for gas are confusing, but might be a negotiating underlines the importance of this gas to the stance with Europe. Russian balance. In 2004 and 2005 Gazprom transited 40 - 50 bcm per year of Turkmen gas to Ukraine and bought another 5 - 7 bcm Russia has a long standing declaration of per year for its own use at approximately intent to co-operate with China given the USD 1.16/MBtu (USD 44/1 000 m3). In East Siberian oil and gas resources and 2006, Gazprom agreed to import 50 bcm China’s interest in importing increasing at a much higher price of USD 2.64/MBtu volumes from its neighbour. This was (USD 100/1 000 m3) for 2007 to 2009. It is discussed at the highest levels in spring impossible to verify the cash proportion of 2006 when inter-governmental framework these trades given the history of barter in agreements were signed by President the trade. Putin of Russia and President Hu Jintao of China. President Putin stated that Russia We are concerned that Gazprom is could potentially supply an annual total banking on being able to secure increasing of 60-80 bcm of gas to China via two volumes of Turkmenistan gas when there routes. Gazprom stated that the planned are other potential suitors for the reserves USD 10 billion 3 000 km Altai pipeline in the region who could be producing system (the western route) would pump the Natural Gas Market Review 2007 • Non-OECD Country/Region Update 135

fi rst Russian gas to China as early as 2011 will increase to 20% (140-150 bcm) by though construction of the Russia-China 2020. A review of various projections section of the system has not started. from the key non-Gazprom gas producing company websites refl ects a much more The Kovykta fi eld in the Irkutsk region of bullish outlook, with potential production East Siberia could be a possible source of volumes of over 300 bcm per year possible production for export to the East, as could in the period 2015-2020 if the investment Sakhalin. Nevertheless, plans to supply climate is favourable. Independent gas pipeline gas from Russia to China by 2011 producers and major Russian oil companies are very ambitious indeed. Gazprom’s control about a third of Russian natural gas increasing assertion of control in these reserves – on the order of 11 tcm. regions has slowed the rate of investment that has been made by private investors. In order to build a sustainable gas business, Gazprom is becoming increasingly active independents will need considerable se- in Russia’s potential gas regions in the curity that the volumes contracted for East – East Siberia, the Far East and and delivered will actually be taken at Sakhalin island. Events surrounding the the price agreed. There is tremendous recent buy-in to the Sakhalin II project for potential for more gas to be produced USD 7.45 billion have affected project in Russia for several key reasons: oil development for environmental and regu- producers, including Gazpromneft, fl are latory reasons. To date, developments at associated gas which is a by-product of Kovykta, another potential source for gas oil production; much non-associated gas exports to China, are very slow, allowing stays un-produced because the access Gazprom to press for entry. conditions to the pipeline network are not There have been considerable diffi culties adequate; some gas is produced beyond an in negotiating gas prices with China. economically recoverable distance from Gazprom wants oil-based prices, while the pipeline system. China is seeking much lower coal-based prices. If pipeline prices were, for example The solution to ending gas fl aring might linked to LNG prices in Beijing or Shanghai appear to be simply by ruling it unlawful regions, such prices are likely to be closer – but this is not a workable solution to Japanese (JCC linked) or perhaps United as it is likely to result in a dramatic States prices. decline in accompanying oil production. Instead, improved economic incentives Independent gas producers to remunerate gas production will have the double benefi t of reduced fl aring and In 2006, non-Gazprom natural gas increasing non-associated gas production. production reached 106 bcm; accounting There are two areas which would seem to for 16% of total. The Russian Energy need attention: access to transportation Strategy assumes that the share of such capacity and price. “independent” production out of the total transported by the Gazprom system Natural Gas Market Review 2007 • Non-OECD Country/Region Update 136

Regarding access to transportation, econ- Gas transportation capacity omic conditions which may lead to increased independent production include improving The UGSS transported about 700 bcm of gas the general regulatory environment and in 2005 and is reaching the upper limit of its specifi cally, continuing to improve pipe- current capacity. According to plan, by 2020 line regulation to ensure that it is cost the UGSS will need to transport between refl ective. Progress has been made recently 580 and 590 bcm of Gazprom gas and up to in this effort following the formation of a 140-150 bcm of non-Gazprom gas. “Gas Market Coordinator” partnership in 2004 between producers and consumers The Russian part of the transmission to agree the main principles of gas market system was built mainly between 1975 reform. This partnership has recently and 1990, when the massive increase delivered substantial improvements in in gas production from West Siberia the terms of access to the Transportation occurred. Most of the export pipelines System including for longer periods than in were built in the 1980’s. Between 2002 and the past. More work remains to be done, but 2006, Gazprom refurbished the trunk gas this seems to be a positive development for pipeline system, compressor stations and independent gas production in the Russian gas storage facilities. Throughput volumes upstream. in 2004 were up 6% in comparison to 2001, which gives confi dence that investments Regarding pricing, wellhead prices for undertaken in this third phase were close independent gas production in Russia will to target levels. depend heavily on domestic market prices as the “premium” export market seems A fourth programme from 2007-2010 was likely to be controlled by Gazprom. Reform approved in September 2006 with a goal of domestic gas pricing will therefore to increase rated throughput capacity have a large effect on gas production from by 35 bcm per year and to decrease fuel independents. It is essential that prices rise input needs for the transmission system to levels where producers can earn revenues by 3.5 bcm per year. An earlier discussion in excess of cost after transportation of this fourth phase had a goal to increase and essential gas processing (see section capacity by 24 bcm per year at a cost of below, on Domestic Pricing). USD 3 billion per year.

However, even after issues of access to transportation capacity and price are addressed, there will remain myriad chal- lenges facing independent gas producers in Russia. The key seems to be in ensuring that the power of Gazprom as a monopoly buyer/transportation provider is balanced so that independents have confi dence that they can sell gas and that they will be paid a profi table, pre-agreed price. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 137

Major gas transmission projects in 2007: In 2005, Gazprom reported that it was able to inject 46.3 bcm of gas into its Northern Tyumen to Torzhok pipeline: storage facilities and withdraw 42.8 bcm. USD 0.7 billion. Three new underground gas storage (UGS) Expanding the Urengoy hub: facilities are currently under construction USD 0.6 billion. in Russia which will add some 1.9 bcm to Expanding the northwestern network the working volume reported in 2005, (including Nordstream): USD 1 billion. compared to annual gas demand in Russia which runs at some 425 bcm. Branch pipelines and distribution stations: USD 0.5 billion. Gazprom also stores gas abroad. Gazprom Upgrading gas transmission facilities: is responsible for developing the largest USD 1.8 billion. storage facility in Germany at Rehden, the largest in Austria at Haidach, which Focus on storage will also serve German customers, as well as 50% of the Humbly Grove UGS facility Storage works in tandem with trans- in southern Great Britain. Gazprom also portation capacity in most pipelines uses storage facilities in Ukraine (in co- systems worldwide. Storage facilities ordination with RosUkrEnergo), Latvia, help to smooth out seasonal fl uctuations Germany and Austria. A new storage of gas demand, allowing pipeline systems facility is also planned in Belgium. to run at higher average rates over longer periods. There is substantial room for Gazprom’s focus on storage in downstream improved transport capacity in Russia if markets is a sensible use of capital given storage investment near demand centres that many of the pipelines in the UGSS run is increased. This could be a signifi cant well below maximum capacity in summer contribution to the quality and cost of when demand is low. With increased supply if the investments are made in the storage at demand centres, Gazprom will be right areas. able to transport more gas in the summer Existing gas storage facilities are an and increase the effective capacity of the integral part of the UGSS and are situated UGSS without building new pipelines. in the main gas consumption regions. Gazprom uses storage to supply up to 20% Focus on “transit avoidance” of demand during the heating season and pipelines up to 30% of gas to Russian consumers during cold snaps. Storage is a stated Gazprom has stated that it wants to build “strategic objective” for Gazprom because several “transit avoidance” pipelines, in- it considers investment to be 5-7 times less cluding Bluestream II, Nordstream and a expensive than development of reserves new Southern corridor to take Bluestream and corresponding transmission facilities gas through Turkey to Western Europe. that would otherwise provide the swing output (see section on Gas Security for a discussion of the role of gas storage). Natural Gas Market Review 2007 • Non-OECD Country/Region Update 138

Table 23 Investments in transit-avoidance pipelines Name From To Avoiding Cost (USD billion) Nordstream Russia Germany Poland, Belarus 11.4 Bluestream II Russia Turkey Ukraine 6.0 Southern corridor Russia Austria, Hungary Ukraine 7.0 Total 24.4

Source: Gazprom company statements and IEA estimates.

The total estimated cost for these projects that regulated prices are below replacement is some USD 24 billion in the current cost levels and contract prices to Europe. environment of high cost infl ation. Even Despite low prices, Gazprom has ongoing if these projects succeed in their strategic problems in collecting payment from aim of reducing gas transit dependence, Russian customers – in 2005 it reported a they do not address the root causes of total of USD 2 billion in total unpaid bills. potential transit problems in the future. The proposed pipelines do not remove Price reform is not just a Gazprom issue dependence on transit states entirely or - low prices for the fi nal customer mean add to upstream gas investment which even lower prices at the wellhead. At these would result in higher gas production. prices, gas is regarded as a by-product of oil which must be disposed of in a cost The capital earmarked for these pipeline effective way. Independent oil producers systems would be better spent addressing are keen to get access to gas processing concerns about Russian upstream gas pro- facilities in order to remove liquids duction (or the effi ciency of downstream from the stream and to dispose of the gas use). Meanwhile Russia could consider associated gas. Nevertheless, at such low proceeding with multilateral political gas prices, fl aring is widely used to dispose efforts to put its relationships with transit of associated gas – offi cial fi gures suggest states on a more reliable footing. that 15 bcm per year is disposed of in this way. Together with the National Oceanic Domestic price reform and Atmospheric Administration of the United States (NOAA) the IEA has estimated Gazprom sells gas in the domestic market maximum fl aring by oil companies in West at wholesale prices regulated by the Siberia at 4 times the offi cial fi gure (see Federal Tariff Service. In 2005, Gazprom Optimising Russian Natural Gas, IEA 2006). sold 307 bcm on the domestic market for Even if the actual amount of economically about USD 13 billion, an average price of recoverable associated gas were some 20- USD 1.11/MBtu (USD 42/1,000 m3). Russian 25 bcm per year, capturing this volume per capita consumption of gas is similar to alone would allow Russia to supply the that in Canada, but consumption per unit entire annual gas use of a country such as of GDP is roughly fi ve times higher than IEA Belgium. countries. Gazprom has argued for years Natural Gas Market Review 2007 • Non-OECD Country/Region Update 139

We note that Russia accounts for some pace of these plans. The outlook is for 50 bcm per year of consumption as “own domestic gas prices to about double from use” in the gas sector itself. We consider current levels to just over USD 2.64/MBtu that perhaps 5-6% of total transported (USD 100/1 000 m3) in 2010, still only 40% volumes could reasonably be expected to of current European export prices (which be necessary for compression in such a may change in the interim). President large transportation system. This implies Putin has stated that he expects Russian that there is potential to save some domestic gas prices to level off at a rate 10-15 bcm per year of gas by installing more of 60-70% of European prices given the effi cient compressors and reducing leaks. transportation netback. Domestic prices A rise in domestic prices should provide still have a long way to go after 2010 the economic incentive for Gazprom to to match this intended ratio given the invest in equipment upgrades which could differential of nearly USD 5.28/MBtu start to meet its own target – a reduction (USD 200/1 000 m3) based on current prices. of 10 bcm per year by 2012 (see, Ibid). Despite the intention to raise prices to “European levels”, it is worth noting that From a consumer perspective, low gas most gas producing countries with which prices coupled with a lack of metering, Russia must compete in number of sectors, mean a lack of incentives to avoid have very low level of gas “feedstock” ineffi ciency and waste. According to CDU prices (see separate MENA section for TEK (the statistics arm of the Russian example). This factor may act to limit the Ministry of Industry and Energy) domestic scope for price rises in those sectors. gas demand growth has been above 3% per year in 2005 (3.82%) and 2006 (3.03%). The establishment of a gas exchange in This is high for such a large and relatively Russia, where up to 10 bcm is being sold mature industry. Throughout this book at unregulated prices, 50% by Gazprom we note that power remains the driver for and 50% by independent producers, is an gas demand and Russia is no exception. important step towards more market based However, because of the prices, the pricing in Russia’s domestic gas market. average effi ciency of gas use in the power Prices on the gas exchange have been as sector for example is low. An upper bound high15 as USD 2.48/MBtu (USD 94/1 000 m3) estimate of potential gas savings in Russia compared to regulated gas prices of about is in the order of 80 bcm per year of gas USD 1.06/MBtu (USD 40/1 000 m3). As if all end use equipment was upgraded to in IEA Europe, we believe that there are state of the art effi ciencies over a period of considerable benefi ts to gas exchanges time (see Energy Technology Perspectives, which allow price transparency according to IEA 2006). economic factors. Russia is making progress in improving gas sector regulation for Annual gas price increases in the order market participants and working on of 25% or more are planned – although installing a more effective balancing elections in early 2008 could slow the regime. Improvement of modifi ed entry/

15. Gas was traded at USD 2.48/MBtu (USD 94/1 000m3) on December 15, 2006. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 140

Figure 40 Gas price rises in selected Russian export markets

350 300 250 200 150

USD per 1100 000 cu.m 50 0

Latvia Russia Estonia Georgia Poland Ukraine Lithuaina Europe (Avg) 2006 2007

Source: Press statements, Gazprom website.

exit schemes and balancing regimes is an with a view to bringing them to European ongoing challenge in many IEA European market based levels as quickly as possible. gas markets (see separate section on As the price increases in these countries Investment and regulation). are more extreme than in the case of Russian domestic price reform, these We see domestic price rises as essential dramatic rises in prices are likely to result to stimulate more effi cient consumption in increased unpaid bills from customers. of gas in Russia, notably in the power These accumulating debts have been used sector. We therefore welcome Russian in the past by Gazprom to secure equity initiatives to raise the price of gas in the positions in customers’ gas infrastructure. regulated sector and to expand the gas exchange. However, we are mindful that Ukraine, for example is one of the most a focus on price rises alone may simply energy intensive countries in the world, result in increasing non-payment if they with demand of some 80 bcm per year of are implemented without other policy gas. In 2004, Ukraine paid amongst the remedies. lowest prices of any of the “near abroad” (see Figure 40) and so Gazprom was perhaps Foreign price reform overly keen to see demand reduction coupled with energy saving in this market. Shifting geopolitics have enabled Gazprom The recent price rises to USD 3.43/MBtu to take a proactive stance regarding price (USD 130/1 000 m3) appear to be having an reform in some of the Russian “near abroad” effect on consumption in the commercial as Russia’s former Soviet neighbours are sector, despite worries over non-payment. known. Gazprom has recently enacted a According to preliminary data, in 2006 policy of raising prices in the near abroad domestic gas consumption was 65.87 bcm, Natural Gas Market Review 2007 • Non-OECD Country/Region Update 141

a “saving” of 3.03 bcm on demand in 2005 Gas Security). However, systemic gas despite the considerably colder winter in substitution in the power sector has been 2006. If Gazprom can continue to “save a stated strategic aim of the Russian gas” abroad and increase its revenues at government for some time, especially the same time, it may be in a position to given that almost 45% of power generated cover some slippage in upstream project in Russia comes from gas. Despite the development. governments strategic aim, we note that gas demand in the power sector has risen Fuel switching year on year for the past ten years and that the share of gas in power generation Short-term fuel switching is a good way has remained static in that time, if not of managing gas demand tensions in increasing slightly. the short-term and is therefore used as a management tool by many IEA In IEA countries, market forces have governments (see separate section on traditionally been relied upon to ensure

Box 3 Fuel switching in Russia during extreme cold

In late January and early February 2006, extreme cold weather forced electricity utilities to switch their fuel source due to lower gas deliveries. Amid the record low temperatures in the European part of Russia and Europe itself, Gazprom cut its gas supplies by 12.5% effective 17 January 2006. At the same time, electricity consumption in the European part of Russia exceeded the target set by the Federal Tariff Service of Russia by 12.6%. Electricity generation from thermal power plants rose by 16.9% and heat output increased by 22.0%. Gas deliveries to power plants were restricted signifi cantly in some areas of Russia: 51%-83% in the North-West, 48%-72% in the Middle Volga area and 35%-80% in the Centre. In order to meet the increased electricity and heat demand, power plants switched to alternative fuels, fuel oil and coal. The daily average fuel oil consumption by the power plants located in the European part of Russia grew 12-fold in the second half of January 2006 compared to the targeted consumption level. Total fuel oil consumption in January 2006 increased by 1.1 million tonnes. Fuel oil inventories, which in some cases declined below the allowable levels, had to be replenished amid surging fuel oil prices. The coal consumption in the European part of Russia in the second half of January 2006 rose to 240% of the planned level, with the coal consumption in January 2006 exceeding the monthly target by 2.7 million tonnes.

Source: RAO UES, extract from Annual Report 2005. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 142

that countries have effi cient and well But if indeed Gazprom is worried that diversifi ed portfolios of electricity gen- domestic gas consumption is rising too eration. In Russia however, gas prices fast for projected production, it is possible are similar to coal prices for large users, that an increase in coal as a share of the despite the considerable technical and domestic energy mix might be seen. environmental advantages that gas enjoys Likewise pressure on the domestic gas as a fuel. From a producer perspective, the market could be reduced by switching to cost to produce and transport one unit oil in some plants, though we note that of energy as coal is far lower than the capacity is limited and oil is substantially cost to produce and transport the same more expensive than gas in Russia. In energy in the form of natural gas. The low either event, the changing Russian fuel regulated price of gas compared to oil has mix has the potential to affect global oil meant that gas has been the economic and coal markets, particularly Russian fuel of choice for power generators and trade with Europe. large users. As has been experienced by some IEA countries, it is diffi cult to ensure From the perspective of gas-importing that power generation companies make countries it is perhaps comforting to see balanced decisions between economics that measures have been taken to reduce and security of supply if prices for one fuel gas demand in Russia in the medium term, are so low. or even in the short-term if needed. From a global/regional perspective however, Gazprom has taken a pro-active view it worth observing that ironically, the of relative energy prices in Russia with European drive for cleaner, less carbon- its merger with Suek, the national coal polluting natural gas looks likely to have company, and its takeover of the former the consequence of increasing coal- or oil- oil company Rosneft. Regardless of the fi red generation in Russia. Of course, this external “market” situation in Russia, will be balanced by increased (premium Gazprom is now in a position to directly priced) gas exports to Europe. infl uence the energy balances across sectors. If it feels that gas production growth is not keeping up with demand Islamic Republic of Iran for gas in the power sector, then it is in a position to infl uence the mix of fuels Iran, which has the second largest gas such as coal, through Suek, or oil through reserves in the world after Russia, is Gazpromneft. uniquely positioned in the global gas market, representing one of the largest The evolution of the Russian energy potential new suppliers to both eastern balance is of great interest to all observers. and western markets, as Qatar does and The “solution” found by Gazprom to the Russia could potentially do with their huge market failures or lack of progress towards gas reserves. market pricing to date in Russia is to push the market itself aside by internalising However, political uncertainty and com- all the values and costs in one monopoly. mercial deadlocks have stopped attempts Natural Gas Market Review 2007 • Non-OECD Country/Region Update 143

Figure 41 Iran’s gas production, consumption, imports and exports

100

bcm 90

80

70

60 Production and consumption 50 are growing at 9 - 10%/year since 1990 Net imports 40

30 Imports from Exports to Turkmenistan started Turkey started 20

10

0 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 Production Consumption Imports Exports

Note: Consumption does not include re-injection into oil fields for enhanced oil recovery. Source: Natural Gas Information 2006, IEA.

by the Islamic republic to monetize the Despite possessing the world’s second giant gas reserves at its offshore South Pars largest reserves, Iran has been a net fi eld. The reserves are thought to belong to importer of natural gas since 1997. In 2005 the same geological structure as Qatar’s it imported 7 bcm from Turkmenistan and North Field, which has been a commercial exported 4 bcm to Turkey. Gas exports to source of LNG for the international market Armenia are expected to start in 2007. for more than ten years. Introduction Iran is currently the largest producer and consumer of gas in the Middle East, with While continuing to negotiate on domestic consumption similar to that in numerous ambitious gas export projects, the United Kingdom or Germany. Growth Iran’s petroleum ministry faces calls in consumption in the last two decades from within the ministry and also from has been dramatic, running at 9-10% per the Majlis, or parliament, to abandon year since 1990. The Iranian economy in such plans altogether and concentrate general and power generation sector in on using gas for oil fi eld re-injection to particular are highly dependent on gas boost oil production, especially under which accounts for more than 50% of the current high oil price conditions. The primary energy supply and around three Majlis also calls for gas to be used for the quarters of power generation. sector and other industrial, Natural Gas Market Review 2007 • Non-OECD Country/Region Update 144

power generation, transportation and In addition to economic and political residential use within the country. Majlis pressure, there are other factors at play: Energy Committee Chairman Kamal over-stretched capabilities of domestic Daneshyar said in September 2006 that construction fi rms, which are already full gas volumes allocated by the National with other projects in the oil, power and Iranian Oil Company (NIOC) for re-injection sectors; also diffi culties (30 bcm per year) into aging oilfi elds are in securing experienced international insuffi cient. Commercial issues such as engineering, procurement and construction pricing and project ownership of gas export contractors. Yet another factor is a dispute projects are also still complicated. over the country’s buy-back system.

The election of Mahmoud Ahmadinejad The buy-back system as President of Iran in June 2005 has signifi cant implications on the gas export The buy-back system was introduced in plans. While the petroleum ministry and order to reconcile the legal obstacles to NIOC subsidiary National Iranian Gas Export foreign investment in the oil and gas sector Company (NIGEC) say they are committed with the need for foreign investment. to LNG, the opposing lobby wants more Under the laws introduced after the 1979 focus on meeting domestic needs fi rst Islamic revolution, foreign companies and using gas to increase oil production are not allowed to own, control, or even through re-injection, as well as using gas directly to invest in Iranian oil and gas for petrochemicals and power generation. fi elds. The 1987 Petroleum Law introduced As oil exports account for up to 90% of short-term buy-back contracts between total export earnings and nearly 50% of the ministry of petroleum or state owned the government’s budget, boosting oil companies and “local and foreign national production continues to be a high priority. persons and legal entities.”

The petroleum ministry and NIGEC dispute Under the terms of the contracts, foreign this view, arguing that the country investors are required to undertake all has plenty of gas to meet domestic upstream development and to bear the requirements as well as for export. Based cost. They receive a fi xed proportion on analysis provided by NIOC, Iran will of production, with a pre-agreed rate still have a massive 12 000 - 14 000 bcm of return, but control of the fi elds in (425-500 Tcf) left over for export after question reverts to the National Iranian covering domestic needs and gas re-injection Oil Company (NIOC) upon completion of for 50 more years. The opposition lobby the development. counters that any extra gas should be used to expand petrochemical and steel production The system is less attractive for foreign for export, to diversify away from a heavily investors than traditional production crude-export dependent economy. sharing agreements or joint ventures. All buy-back contracts are as short as fi ve to seven years, giving investors relatively little time to recover investment, especially Natural Gas Market Review 2007 • Non-OECD Country/Region Update 145

when the foreign investors must fi nance An important milestone for NIOC should all of the development costs. The lack of have been the launch of South Pars Phases control over the pace of fi eld development 6-8. These phases involve production of discourages investment. 30 bcm per year of gas and 120 000 b/d of condensate. Most of the gas was to be In February 2007, NIOC indicated amended reinjected into the aged and ailing Aghajari terms for buy-back contracts, with greater oil fi eld. Statoil won the operating rights fl exibility and an attractive rate of return: of the development with a 40% interest an extension of the terms of the contracts in 2002 and was to operate the offshore to 25-30 years; capital costs to be portion. Production was expected to come determined after front-end engineering on stream in mid-2006 but it has been rather than in the development plan, to delayed by a disagreement over the terms enable more accurate project costing; of the buy-back contract. Perversely, the the formation of a joint NIOC/contractor disagreement has been caused by good committee to oversee all phases of the news – a production upgrade from 10 bcm contract, thereby allowing contractor per year to 13 bcm per year. The better- involvement after project handover to than-expected performance of the wells NIOC; and a penalty and reward scheme led to confl ict about the terms of the buy- to provide contractors with an incentive back deal. As the pipeline and platform to maximize production. The rate of return infrastructure has not been delivered has not been fi xed in the revised terms, as agreed, the three phases are now not but would be suggested by the contractor expected to all come on stream by 2008. as a fi rst step towards reaching agreement between the parties. Petrochemical sector: a huge gas user Although some foreign companies have tried to invest in Iranian gas projects The petrochemical industry in Iran and its because of their huge potential, delays feedstock requirement including natu- have been reported for both pipeline and ral gas are expected to grow quickly in LNG schemes that would be allocated gas the next decade, as the country tries to from specifi c phases of the South Pars diversify away from the crude dependent development. economy. The fi rst and also one of the biggest petrochemical plants in Iran Domestic supply projects (Shiraz) began operations in 1959, fol- lowed by the Kharg Island petrochemical NIOC is keener to award new phases of complex in 1966 and Razi and Bandar Imam South Pars that are geared toward supplying Petrochemical Complex and some others gas for domestic use. In 2006, a group of before the 1979 Islamic revolution. international companies, including Shell and Total, won qualifi cation for South Pars Both production and investments in the Phases 19-22, a USD 5 billion project that petrochemical industry in Iran have grown calls for production of 40 bcm per year of signifi cantly in recent years. In 1995, gas and 160 000 b/d of condensate. petrochemical production was 8.7 million Natural Gas Market Review 2007 • Non-OECD Country/Region Update 146

Figure 42 Iran’s gas system

ARMENIA AZERBAIJAN

TURKEY AZER. TURKMENISTAN Astara Tabriz

Rasht

Gorgan Qazvin Sari Neka Khangiran Mashhad

IRAQ 2 & 1 IGAT Arak Baghdad IRAN Isfahan

Yazd

AFGHANISTAN

Kerman KUWAIT Kuwait City Shiraz

Dalan Aghar

Pars Nar Pars Structure Kangan SAUDI South Pars Sarkhoun

Bandar Abbas PAKISTAN Gashu Manama Lavan Isl. Qeshm Isl. Larak Isl. Pars LNG BAHRAIN Persian LNG Sirri Isl. Iran LNG Doha OMAN Riyadh QATAR 0Miles 100 200 Abu Dhabi To India ARABIA 0Km 200 300 UNITED EMIRATES Gas pipeline planned or under const. LNG export plant planned OMAN

The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source:The Petroleum Economist Ltd. tonnes. Petrochemical production at which is approximately the combined National Iranian Petrochemical Company current ethylene capacity of Japan, Korea, (NIPC) increased at an average annual rate Chinese Taipei and China. of 6% during the period 1995-2005 and reached 23.6 million tonnes in 2006. The With the commencement of the South country is currently constructing massive Pars gas fi elds development in 2001, new petrochemical production capacity NIPC started planning for mega gas- Natural Gas Market Review 2007 • Non-OECD Country/Region Update 147

based petrochemical plants, many of country’s petrochemical industry from which came online from 2003 to 2006. As 2007 to 2010. The country is also actively such, this period saw an average annual attracting foreign investors to invest in growth rate of approximately 30% in the industry, further emphasizing the production capacity. In 2006, 78% of total signifi cance of using energy resources petrochemical production was exported, domestically. bringing in revenue of USD 3 billion (second only to USD 50 billion in crude export Pipeline exports revenue). The Ministry of Petroleum and NIPC have introduced measures to package Currently, Iran has only a 10 bcm per year long-term investments more attractively export contract with Turkey, which has for international companies. To encourage not delivered full contractual quantities both domestic and foreign investors in since inception. This has not prevented the the sector, Iran has provided tax holidays National Iranian Gas Exporting Company for the petrochemical zones. (NIGEC) from planning several more In 2005, the petrochemical industry export pipelines. While gas prices in the alone consumed around 8 bcm of fuel region remain signifi cantly lower than and feed gas, representing about 10% of international markets, NIGEC continues to the country’s total gas consumption. Due negotiate gas exports, although many face to massive investment in polyethylene considerable uncertainty. Iran’s possible production, there is signifi cant growth pipeline export projects are summarised in potential for gas demand within the Table 24.

Table 24 Iran’s pipeline export projects Direction Buyer Start Yearly volume South UAE Crescent 2007 5 bcm UAE DUSUP n.a. 7 bcm UAE Mubadala n.a. 10 bcm UAE Ras-Al-Khaimah n.a. 6 bcm Kuwait n.a. 3 bcm Oman n.a. 25 bcm East Pakistan-India 2012+ 40 - 80 bcm North Azerbaijan (Nakhjavan swap) 2005 0.35 bcm Armenia 2007 2.80 bcm Austria (Nabucco) 2012+ 12 bcm Switzerland (Nabucco) 2012+ 5 bcm Europe via Ukraine n.a. 30 bcm Turkey 2001 10 bcm n.a.: not available. Source: Company announcements. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 148

Many of these plans are discussed in other LNG projects sections of the Natural Gas Market Review 2007 and have therefore been briefl y There have been a number of LNG project summarised here. proposals in Iran since the 1980’s, none of which have progressed to fi nal investment Iran – Pakistan – India. The Iran-Pakistan- decision. There is considerable uncertainty India (IPI) pipeline (or “Peace Pipeline”) due to the internal divisions on how to is a planned export route for Iranian gas best monetize and utilize the huge gas eastwards. The USD 8 billion pipeline is resources in the country, as well as political expected to have capacity of 40 - 80 bcm uncertainty surrounding the country. This per year, with India buying about two- means that getting the various proposals thirds of the gas and Pakistan taking the to the construction stage will continue remaining third. The gas would originate to be tough. Among the various projects, from the Iranian port city of Assaluyeh, the Pars LNG looks most advanced. landfall point of gas produced in the giant South Pars fi eld. For more information see Pars LNG (South Pars 11) later section on India. NIOC (50%), French Total (30%) and Malaysian The National Iranian Gas Company (NIGC) Petronas (20%). In 2005 the project partners has a contract with Turkey’s BOTAS signed a framework agreement to produce Company to export 10 bcm per year via some 13.6 bcm per year (10 mtpa) of LNG. pipeline for 22 years (starting at 3 bcm per and JGC undertook front-end year in 2001, reaching the plateau level by engineering and design work on the two- 2007). After a cold winter 2006/7 in Iran, train plant. Although it has been revealed the exports faltered and Turkey (as well as that the project’s target start-up slipped many Iranian cities) saw their gas supply from 2010 to 2011, volumes from Pars interrupted. Iran has also been mentioned LNG have been aggressively marketed in as a potential source for the Nabucco China and Thailand, with a preliminary sales project. This project is intended to link agreement for 8.2 bcm per year (6 mtpa) Turkey with Austria via , signed in 2006. Gaz de France (GdF) and and Hungary. For more information see Germany’s E.On are also said to be interested later section on Turkey, in buying output from the project.

Various pipeline options are available Persian LNG (South Pars 13-14) to the south of Iran, in the Middle East and North Africa (MENA). These projects Talks were started in 2001 on Persian LNG, include United Arab Emirates (UAE), Kuwait another NIOC-led (50%) joint venture that and Oman. For more information see latter has (25%) and Repsol YPF section on “MENA”. (25%) as foreign partners for two 5.4 bcm per year (4 mtpa) trains. In January 2007, NIOC signed an upstream service agreement with Shell and Repsol for development of Phases 13 and 14 (formerly 13a), which is Natural Gas Market Review 2007 • Non-OECD Country/Region Update 149

subject to the fi nal investment decision of Khatam Anbia construction company were the LNG development. NIOC says the fi nal awarded a USD 500 million downstream investment decision is scheduled for 2007. contract for the project. Details of the deal are not clear. Iran is demanding an FOB Iran LNG (South Pars 12) LNG base price of USD 5.10/MBtu, nearly 60% more than the base agreed in 2005. A 25-year deal was signed in summer 2005 China’s Sinopec signed a memorandum for a group of Indian state companies of understanding to buy 13.6 bcm per (GAIL/IOC/ONGC) to buy 6.8 bcm per year year (10 mtpa) of LNG from this project in (5 mtpa) of Iranian LNG starting in 2009 at January 2005. a maximum price of USD 3.25/MBtu (a fi xed price component of USD 1.2/MBtu plus Chinese interest 6.5% of the current Brent oil price in USD per barrel, which was capped at USD 31) In addition to the above-mentioned on a free-on-board (FOB) basis. However, Chinese deals with Pars LNG and Iran LNG; Iran later called for the price to be raised NIOC and China National Offshore Oil because of the subsequent rise in crude oil Corp. (CNOOC) in November 2006 signed a prices as Iran’s Supreme Economic Council USD 16 billion deal to develop Iran’s North refused to approve the agreement. Pars gas fi eld and build LNG facilities. The project would be undertaken in four Iran’s oil ministry earmarked India to be the phases. Gas from three phases would be market for the 100% NIOC LNG (the current used to produce LNG for export, with Iran Iran LNG) project that aims to export up taking LNG from one phase and CNOOC to 12.2 bcm per year (9 mtpa) of LNG from taking LNG from two phases. Gas from Bandar Tombak on the Gulf, fed by Phase the fourth phase would be used for re- 12 of the South Pars fi eld development. In injection into oilfi elds and for delivery to February 2007, Korea’s Daelim and Iran’s the domestic gas grid.

Table 25 Iran’s LNG projects Project Sponsors Start Potential buyers Feedgas T1: Total/Petronas equity lifting NIOC (50%), Total (30%), Pars LNG 2011+ T2: Thailand (PTT), China (PetroChina), South Pars 11 Petronas (20%) possibly India (GdF-Petronet), possibly E.On NIOC (50%), Shell (25%), T1: Shell/Repsol equity lifting Persian LNG 2012+ South Pars 13-14 Repsol (25%) T2: Asia (Japan) National Iranian Oil Co. India (Gail, IOC, BPC) Iran LNG 2012+ South Pars 12 (NIOC) China Sinopec (Yadavaran package) Unnamed NIOC, CNPC 2014+ China (CNPC) LNG + domestic Former South Pars 14 Qeshm NIOC, LNG Ltd. (Australia) 2014+ tbd Selkh, Southern Gesho Unnamed NIOC, CNOOC n.a. China (CNOOC) North Pars Unnamed NIOC, SKS (Malaysia) n.a. tbd Golshan, Ferdos t.b.d: to be decided, n.a.: not available Source: Company announcements. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 150

China National Petroleum Corp. (CNPC) is pace with production in the longer-term, also reportedly fi nalising its memorandum as the rewards of world market prices of understanding with NIOC to jointly are balanced against the higher fi nancial develop a USD 3.6 billion upstream rewards of oilfi eld re-injection and the and LNG project based on gas reserves economic and social benefi ts of domestic formerly known as South Pars Phase 14. gas-fi red power generation and industry. The development would be expected to take seven years, with USD 1.8 billion Strongly competing demands on the being spent on developing 370 bcm of gas region’s natural gas are likely to help reserves and USD 1.8 billion on building foster market opening, providing some an LNG export plant with 6.1 bcm per opportunities for outside investors. year (4.5 mtpa) capacity. This phase was Equally, regional state companies are earlier allocated for a gas-to-liquids (GTL) expected to use access to gas and long- project. term supplies to leverage opportunities in consuming markets. None of the Chinese deals seems likely to yield gas deliveries before 2014. Summary

The MENA region is one of the fastest Middle East and expanding gas producing areas of the North Africa (MENA) world, with regional growth of 6.4% in the period 2000-2005, compared to total non- OECD growth of 4.4% and OECD growth The Middle East and North Africa region of less than 0.1% in the same period. That is seeing rapid gas production growth, has almost doubled the region’s share in with new investment and ample reserves world production to 15.5% in 2005, from providing a basis for continued annual 7.8% in 1990. growth in the 6-8% per year range. Export growth has also been rapid, At the forefront of this expansion have giving the region around a sixth of the been Egypt, Libya, Iran, Oman, Qatar and world market. Further growth will be Saudi Arabia, with all bar Saudi and Iran also led by Algeria and Qatar in the medium- contributing to the region’s expanding term, with Iran’s emergence tentatively net export profi le. This took the MENA previewed beyond that. share of world gas exports to 16% in 2005, equivalent to early 150 bcm of gas. However, rapidly rising domestic demand New developments in Qatar and Algeria is proving a competing draw on resources, are expected to drive expansion to 2011 such that diffi cult decisions will need to (see table), although Qatar’s moratorium be made in a number of Middle Eastern on new gas projects until 2009 will see at states about medium to long-term gas least a 3-year delay in large new supplies allocations, potentially resulting in the to the market. It is at this point that Iran’s cancellation of some export projects. This emergence as a net exporter might be means that exports are unlikely to keep felt, although the volume and timing of Natural Gas Market Review 2007 • Non-OECD Country/Region Update 151

Table 26 MENA natural gas export projects to 2015 Year Country Project Gas volume/year Target markets United Arab Emirates 2007 C Qatar Dolphin pipeline 20.7 bcm (UAE), Oman 2007-08 P Iran Salman-UAE Pipeline 2-5.2 bcm Sharjah/UAE Transmed (Enrico Mattei) 6.5 bcm on top of existing 2008 C Algeria Italy pipeline expansion 27 bcm 2008 P Egypt Egypt-Israel Gas Pipeline 2 - 7 bcm Israel Jordan, Syria, Arab Gas Pipeline Extension to Lebanon, Turkey. 2008 * Egypt 10 bcm Turkish Border Potential to link into Europe. 21.2 bcm / 2 X 7.8 million The United Kingdom 2008-9 C Qatar Qatargas II tonnes /Europe 21.2 bcm / 2 X 7.8 million The United States, 2008-9 C Qatar RasGas III tonnes Chinese Taipei 9.2 bcm / 2 x 3.4 million The United States, 2008-9 C Yemen Yemen LNG tonnes Mexico, Korea 2009 P Algeria Medgaz 8 Bcm Spain/Europe 10.6 bcm / 7.8 million LNG - the United 2009 C Qatar Qatargas III tonnes States 2009+ P Algeria El-Andalus LNG 5.4 bcm / 4 million tonnes LNG 10.6 bcm / 7.8 million LNG - the United 2010 C Qatar Qatargas IV tonnes States 2010+ P Algeria Skikda replacement LNG 6.1 bcm / 4.5 million tonnes LNG 2011 P Algeria Galsi pipeline 8 -10 bcm Italy/Europe 13.6 bcm / 2 x 5 million 2011+(p) Iran Pars LNG LNG - Thailand, China tonnes 21.8 bcm / 2 x 8 million 2012+ (p) Iran Persian LNG LNG - Asia, Europe tonnes 2012+ * Iran Iran- Pakistan- India pipeline 40 – 80 bcm Pakistan, India 12.2 bcm / 2 x 4.5 million 2012+ (p) Iran Iran LNG LNG – Asia tonnes 5.9 bcm / 3 x 1.45 million 2014+ * Iran Qeshm LNG LNG tonnes 2015 ** Iran Nabucco Link in 10-12 bcm Under Construction (C), Planned (P) and Proposed (*) Note: further details in separate LNG section. Sources: Company reports, statements, news reports. any tradable gas remains the subject of profi le of the region’s own domestic considerable speculation (as noted in the gas requirements, whether for power previous section on Iran). generation, gas-based industry or oilfi eld re-injection, all of which offer alternatives Consumption to overseas sales. Consumption in the Middle East and North Africa states as a One of the most signifi cant developments whole is expanding at some 7.4% a year, of the last year has been the increasing compared with world demand growth of Natural Gas Market Review 2007 • Non-OECD Country/Region Update 152

2.6%. This gave the region an 11% share limited experience of many regional state of global demand in 2005 from 6% in companies. Pricing remains a key issue here 1990. It is notable that the region’s largest which will have repercussions on the pace producers, Egypt, Iran, Qatar and Saudi and attractions of any such developments Arabia have charted some of the fastest for the domestic market, with the region demand growth. as a whole erring towards extensive under pricing for their own markets to sustain This refl ects in part the widespread growth, this policy inevitably distorts econ- adoption of gas-based industrialization omics over the longer term. strategies to reduce economic dependence on oil. It is also the consequence of a With competing calls on fi nite resources, region-wide “switch” to natural gas in greater efforts are expected on the part of the energy mix, most notably for power consuming states in order to tie up available generation and water desalination, where MENA supplies for long-term needs. This demand for gas is expanding in excess of may also conversely create investment 10% a year, over twice the OECD and non- openings for producer state companies to OECD averages. Even further growth will enter the mid and downstream value chain be charted as a result of the increasing in a more signifi cant way as part of tie-ins role of gas in the energy mix, such that with gas (and oil) supplies. MENA suppliers 59% of the region’s installed capacity will are likely to gain further benefi t from be derived from gas in 2020, from around their increasing importance as a strategic 52% in 2003. Gas demand for power counterweight to Russian gas in European generation accounts for more than 40% markets. This has already meant EU political of total gas consumption. backing for a number of pipeline initiatives from the MENA region, with Algeria the Exports principal focus of this to date.

Although existing investments and planned The full policy implications of the rapid projects point to continued growth in growth in consumption rates in MENA regional gas production at an annual range states (especially the Gulf) are still very of 7-8%, availability for exports is unlikely much in the process of being assessed. to hold this pace. That the region will This means that it will take time before become an increasingly important source of the precise impact on the regional project new gas supplies to world markets is not in outlook becomes clear. However, the initial doubt. However, domestic demand growth signs are that some changes in energy and is such that local users likely to become an wider economic planning will be required increasing priority in the allocation of new to manage usage in the mid-term, with gas feedstock in the 2008-15 period. This may the potential for feedstock substitution have the effect of reining in contributions where possible and the scaling down to world exports, but also brings with it the or cancellation of projects plans where prospect of new investment opportunities not. Initial signs are that these cutbacks in the region, many of which are likely to will be focused on industrial projects for be open to foreign partners, given the the domestic market. This in turn has Natural Gas Market Review 2007 • Non-OECD Country/Region Update 153

implications for alternative energy sources to the gas-based industrialization at the like oil products, in the event that feedstock core of its ambitious Vision 2020 economic substitution strategies are pursued. programme, with the aim of compensating for the shortfall in near and mid-term gas. Oman United Arab Emirates (UAE) Among states where shortfalls have been felt or are anticipated, Oman has been In the UAE, power/desalination demand and one of the most candid. In February 2007, oilfi eld re-injection are the two principal Undersecretary of Oil and Gas Nasir al- drivers of demand growth. Some near-term Jashmi, acknowledged that “we have a lot relief is promised by the arrival of Qatari of demand and there are projects in the gas through the Dolphin pipeline in mid- pipeline that we cannot meet” in comments 2007, but this is still expected to fall short to the Middle East Economic Survey. Oman of demand. Meanwhile existing domestic estimates that gas demand will reach developments are largely geared towards 39 bcm per year in 2010, compared with oilfi eld reinjection, as part of plans to boost production of 28 bcm per year. The lack of production capacity to 3.7 - 4 mb/d from near-term availability has already meant current levels of 2.8 mb/d. Development delays to full capacity production at the of more inaccessible domestic reserves Qalhat LNG project, which is now envisaged and further imports from neighbours like for 2009 after start-up at the end of 2005. Iran and Qatar, are all under consideration It also rules out any further Omani export in this light. However, the decision by the initiatives without the benefi t of new region’s largest exporter, Qatar, to extend supplies, either from domestic discoveries the assessment of its North Field reservoirs or imports. Nevertheless, the Omanis have until at least 2009 means that new gas from indicated that the brunt of any shortfalls this source to the UAE and other would-be will be felt by new domestic projects, regional importers, remains unlikely until whether for power generation or for at least 2012. This will contribute to the petrochemicals. In this light, the country’s pressure on the UAE and others to seek lead developer, Petroleum Development of out alternatives for the medium-term, Oman, is considering coal for a new 500 MW particularly for gas-intensive projects generation facility, rather than natural gas, such as the two aluminium smelters while the Duqum petrochemical and refi ning under consideration and petrochemicals project is being reviewed on the basis of oil expansion at Borouge. feedstock, rather than natural gas. The Sohar petrochemicals project is also under review Iran and has been set back from its initial start-up date of 2009. Although the situation will be As mentioned in the previous section eased somewhat by imports from Qatar in focusing on Iran, the country is also facing 2008, (and the end of Omani commitments a similar scenario despite holding the to Dolphin) these supplies will be focused world’s second largest conventional gas on oilfi eld re-injection at Mukhaizna. This reserves. Its domestic demand growth is leaves Oman to make further amendments estimated at just under 10% a year, only Natural Gas Market Review 2007 • Non-OECD Country/Region Update 154

held back from higher growth rates by whereby only one third of reserves is the lack of distribution infrastructure and available to the export markets, there upstream availability. are signs that it too is struggling with contending demands on its gas. In the Elsewhere in the Middle East home market this is led by domestic petrochemicals, power generation and Both Saudi Arabia and Kuwait are also facing efforts to extend residential usage through gas shortages, as a result of allocations a national gas grid. In the export market, for power generation projects and in the this includes commitments to the 10 bcm former, petrochemicals. There has always Arab gas pipeline running through Jordan, been considerable interest in Saudi Arabia Syria and eventually Turkey; the pipeline as a potential net gas exporter from the to Israel; and two LNG plants at Damietta region given the size of its reserve base. and Idku, which are also in need of new gas However, unconfi rmed reports suggest for expansion. Egypt is already importing that near and mid-term gas availability fuel oil for domestic power generation, at even for domestic uses is tight. This has some cost, and in this atmosphere, further had the impact of delaying supplies of commitments of gas to export markets feedstock for planned petrochemical will be politically and economically diffi cult projects and may cause future project plans without substantial production increases. to be revised. Saudi Arabia has also reverted to the use of oil products for some new Algeria power generation, rather than natural gas, Algeria accounts for almost half MENA in contrast to previous policies favouring gas exports. Algeria has seen its export natural gas as a means of displacing oil initiatives given enhanced status in EU use. In this light, the planned independent energy planning, which is set to result in a water and power project at Ras al-Zour, is memorandum of understanding on energy now expected to run on more expensive cooperation in 2007, along the lines of oil feedstock. Similarly in Kuwait, plans to similar agreements with Kazakhstan, construct a fourth refi nery at al-Zour have Azerbaijan and Ukraine. For its part, largely been driven by domestic power Algeria has agreed to expedite work on generation needs, after diffi culties in two further EU-bound export projects, locating domestic or imported gas supplies including the Medgaz link to Spain, due for planned gas-fi red power projects at al- in 2009 and the Galsi link to Italy, which is Zour, Shuaiba and Subiya. due in 2011, along with the expansion of the existing Trans-Mediterranean link to Egypt Italy. This will offer a further 22.5 bcm of Algerian gas to Europe by 2011, up from Egypt has witnessed the most rapid nearly 70 bcm total exports in 2005. domestic demand growth of all MENA countries, some 10.8% a year over However, there have been some signs of the period 2000-05. Despite its more tension in this emerging energy inter- conservative approach to gas exports, dependence, particularly after Algeria’s Natural Gas Market Review 2007 • Non-OECD Country/Region Update 155

state-owned Sonatrach signed an MoU with from Algeria which would otherwise be Russia’s Gazprom in mid-2006 on future benefi cial for security and competition energy cooperation. The link-up between in the wider European market. Indeed, if leading suppliers was particularly sensitive there were a fully integrated European gas for Italy, which depends on Russia and market, total dependence on Algeria would Algeria for 69% of its imports in 2005 be less than one quarter of imports. This is and was therefore sensitive to any hint of a good example of where both Spain and collaboration between the two. For its part, Algeria could achieve greater diversifi cation Algeria has stated that the Gazprom MoU and security through greater integration is similar in scope to those signed with of the EU gas market. Shell, BP and Norway’s mostly state-owned Statoil. However, strong reservations have Libya also been expressed in Spain. Libya too has continued efforts to increase Algeria and other suppliers also concerned exploration through its open tender about over-reliance on one single market and licensing process, with a number of gas are eager to increase investments through prone blocks including Mediterranean the supply chain in order to mitigate risk offshore acreage made available in the and reap some of the rewards of integrated third international licensing round in supply chain management. For Algeria, 2006-07. It has plans for a further licensing this has taken the form of the pursuit of round focusing on gas in 2007. However, access to mid and downstream investment as yet, there is no additional availability opportunities in EU markets. In this light, it to increase capacity at the 8 bcm per has plans to establish marketing companies in year Green Stream pipeline to Italy or Italy and France, as well as establish minority indeed feed into new export projects. stakes in regasifi cation facilities. To date, Shell is however working on the project Sonatrach has interests in regasifi cation in to upgrade the al-Brega LNG plant, which the United Kingdom, France and Spain and is could include an expansion to 4.3 bcm also pursuing regasifi cation and marketing per year (3.2 mtpa) from 1 bcm per year opportunities in Italy. This trend is likely to (0.8 mtpa), although this remains de- continue as both sides of the supply picture pendent on exploration success. A number seek to mitigate concerns about market of other companies, including BP, are also security and producer National Oil Companies discussing integrated gas ventures. have the capital available from high energy prices to pursue such investments. Investment

Spain’s stated policy is to limit supplies from There are, however, some positive signs any one country to 60% of imports. In the emerging from the region that the de- context of its own national market, Spain mand for gas, whether from domestic or was close to this limit in 2005, although overseas sources, will help create a more dependence was reduced to 43% in 2006. vibrant project climate, both because This limit makes it diffi cult for Spain to of the strength of demand and the encourage an expansion of gas imports requirement for external expertise to meet Natural Gas Market Review 2007 • Non-OECD Country/Region Update 156

the pace and complexity of requirements. process to develop reserves that were In some cases, this is taking place through previously deemed as uncommercial due the redesignation or reconfi guration of to their high sulphur content and relative projects, such as the Palm GTL project in inaccessibility. Prequalifi cation for the de- Qatar, where the GTL aspects have now velopment of a small part of the country’s been abandoned in favour of a domestic- 5 663 bcm (200 Tcf) plus of sour gas reserves focused development project, known as was started in 2006, drawing in a number Barzan, in which Exxon Mobil, will take a of major international players. An award on 10% stake. Perhaps more signifi cantly, there this is expected in 2007, allowing project are signs that gas demand is generating completion by around 2011-12. Foreign rare openings for upstream investment players will be given a 40% stake in the and engineering support, a trend which is projects under 30-year contracts with the likely to continue while international prices Abu Dhabi National Oil Company. for gas remain at current high levels. This impulse is supported by the relative lack of Further such opportunities are also gas experience held by the region’s mainly expected in other regional states, including oil-focused state-owned companies, as Kuwait, where a non-associated gas fi nd well as the need for investment funds and in 2006 was estimated to hold some technological input in cases where reserves 35 Tcf (991 bcm) of reserves. The KPC has are hard to access and where a sense of moved quickly to draw up a fast-track urgency is at play. commercialization plan for the fi eld, which is due to be published in 2007. Expectations Oman has again been the most pro-active are for initial production of 4.5-5 mcm per Gulf player to date, awarding its fi rst two day (1.7 - 1.9 bcm per year) from the North onshore gas production sharing agreements Field fi nd, with a further 17 mcm per day in 2006. The awards have ushered new players (6.2 bcm per year) also planned from the into the country’s upstream arena, with BG Durra gas fi eld in the offshore Gulf. The marking its fi rst entry with the Abu Mutabul latter development awaits the resolution Block 60 award, while BP was awarded of a maritime border dispute with Iran. It development rights to tight gas reserves is also worth noting that it was the allure at Khazzan-Makarem. Oman estimates of natural gas production that broke the it has between 20 to 60 Tcf of gas locked mould on foreign participation in the Saudi up in tight geological formations, which upstream industry in 2003-04 when its were previously deemed as uncommercial. initial Empty Quarter tender was concluded. However, rising prices, strong demand, As yet, exploration for gas outside these not to mention technical advances, have four PSAs is being led by Saudi Aramco. changed assessments on this, with some Seismic work in the Red Sea area, which hope that tight gas supplies will provide was initially offered to investors under the the country with a longer-lifespan than abandoned Strategic Gas Initiative has also conventional reserves. been undertaken in the last year. This, along with growing interest in Gulf offshore So too in the United Arab Emirates (UAE), reserves, may provide the basis for future where Abu Dhabi has started an award licensing rounds in the country. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 157

Elsewhere in the region, progress in demand signals, it is clear that gas pricing bringing new gas investments to the for domestic projects in the region remains market has been mixed. In Iran, political dislocated from international pricing and changes and subsequent policy reviews the global demand picture. This refl ects have upset the momentum of project the widespread provision of cheaply priced awards at South Pars, with the effect gas to encourage usage and foster gas- that new awards have dried up in the last based industry, as well as an unwritten 18 months. A restart is envisaged in the political contract between governments project process, although the country’s and populations in oil and gas rich states international position, combined with an for cheap and abundant energy. increasing preference for domestic players means that opportunities for investments In some cases, external upstream investors will be more limited. Algeria too has are shielded from these lower prices by “cost stepped away from the international fray in plus” approaches to payment or condensate 2005-06, in order to reconsider changes in export rights which moderate exposure to its hydrocarbon legislation. The resolution the low domestic market rates. This leaves of this debate in early 2007 is likely to pave regional governments to bear the brunt the way for a return to the market this of the burden between development or year, albeit on less favourable terms than purchase costs and the domestic price base. originally envisaged. In all of this, Egypt However, the costs of this approach are has remained a relatively steady presence rising in terms of lost revenues, decreased in the regional project climate, offering at effi ciency and an increasing subsidy burden, least one tender of gas exploration acreage which has prompted domestic debate on a year, with a positive investor response up the issue in a number of states. The most until the latest round (see below). notable dialogue has been in Saudi Arabia and Iran where prices of USD 0.75/MBtu Pricing and USD 0.35/MBtu have been used as an incentive for downstream industry growth. However, while investment opportunities Here, full market prices for domestic users may have started emerging in response to remain unlikely given the developmental

Table 27 Reported domestic gas feedstock prices in selected MENA countries Country Domestic prices Egypt USD 1.19/MBtu Iran USD 0.35/MBtu Oman USD 0.80/MBtu Saudi Arabia USD 0.75/MBtu UAE USD 1/MBtu16

16. Reported for gas sale from Adnoc to Dubai Jebel Ali , APS Market Review, 15 January 2007. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 158

and political objectives of subsidized gas, Exports to near neighbours previously although incremental price increases used pricing formulas that were relatively represent a more probable outcome in favourable to buyers in the interests of order to help distinguish the merits of bolstering regional relations and gaining contending calls in the domestic market. market access. However, the signs are now that those with net gas to export Until recently, Egypt was one of the few will be unwilling to strike deals on the countries to pass on some of the burden same terms, given the widening disparity of low domestic prices to investors, which with international prices. Qatar has now proved acceptable in a lower price era, with intimated to Oman and the UAE that it will some recompense available through access be looking at a minimum of USD 4/MBtu to export markets through LNG and pipeline for any second phase of supplies through gas. However, signs have increased over the the Dolphin pipeline, compared to prices of last year that this policy was beginning to around USD 1.30/MBtu in the initial phase. pose a disincentive to investment, such that A short-term bridging supply deal to Dubai interest in the 2006 EGAS licensing round in 2007, is estimated at three to four times fell far short of expectations. Investors such the original price. Iran has gone one step as BG and Apache also spoke publicly of the further in attempting to renegotiate its need for higher prices. This has persuaded 2001 supply deal with Sharjah based on a gas the Egyptian government to make a deal price of USD 0.46/MBtu (USD 17.5/1 000 m3), with its largest oil and gas investor, BP, in which would have risen to a maximum 2007 which will see it pay a higher price for of USD 1.06/MBtu (USD 40/1,000 m3) in a gas from the North Alexandria and West second phase of development. Iran has also Mediterranean Deep Water concessions. started initial discussions with Oman and The maximum price to BP is quoted at Dubai (UAE) over future exports, where USD 4.7/MBtu, as opposed to a usual price of signifi cantly higher prices are envisaged. USD 2.65/MBtu, in recognition of the costs of development in deepwater offshore At the international level, MENA states areas. This is likely to act as a benchmark have tended to fi x prices at the prevailing for future such arrangements, helping to world market levels under long-term con- foster investment in the country’s more tracts, except in a few exceptional cases resource-intensive development acreage where political or strategic considerations and unlock gas for domestic and potentially, have resulted in more buyer-favourable export markets, where reserves are suf- arrangements. Qatar in particular has had fi cient. However, it is not yet clear if the suffi cient new developments in the last Egyptian state will shoulder the burden year to take full benefi t of the higher price of higher prices, or pass on part of the climate. Iran is reported to be looking at increase to domestic users who pay around a new maximum price of USD 5.10/MBtu USD 1.19/MBtu for gas, thereby contributing for LNG sales to India, after pulling out of to an estimated USD 7 billion energy subsidy a 2005 agreement which capped prices at burden in 2006-07. USD 3.25/MBtu based on a Brent crude cap of USD 31/bbl. It is also reportedly looking at a price of USD 4.93/MBtu for pipeline Natural Gas Market Review 2007 • Non-OECD Country/Region Update 159

gas supplies to India and Pakistan based on support. China is an alternative potential 6.3% of the Japanese crude cocktail (JCC) market for these producers, offering less (at USD 60/bbl) and a fi xed component of of this type of risk. More transparency USD 1.15/MBtu. on infrastructure investment and what commercially exploit-able gas reserves will become available over time, accompanied Central Asia by dialogue on the long-term export policies of Caspian gas producers, in both To complement established economic West and East-bound market perspectives, relations, Central Asian and Caucasian is urgently needed. states as well as Russia are understandably seeking to diversify their energy sector Central Asian and Caucasian States have investment and oil and gas export routes. strong links with the Russian Federation, With new independent oil export in- including historic, economic and cultural frastructure from the region starting up ties, between what was until just 15 years successfully in 2006, (Baku-Tbilisi-Ceyhan ago part and parcel of a monolithic Soviet pipeline), attention has shifted to possible Union, preceded by the tsarist empire. gas export routes from the region to Hence, engagement between Russia and central, southern and western Europe. Central Asian and Caucasian States has a long tradition, but is now evolving. In addition to the completed , a number of alter- The newly independent Caspian and Central native export routes are under active Asian states, that include the Russian consideration. West-bound options in- Federation, are now seeking to diversify clude the Nabucco project, the Greece their energy export markets and transit Turkey Italy inter-connector and the Trans routes and hence are fostering trade links Adriatic Pipeline as well as Trans Caspian with new demand centres not just in the options (see also Turkey section). East– west, but to the east and south. bound options include routes to China and through Afghanistan and Pakistan Russia would like to retain newly indepen- to India. dent Central Asian and South Caucasian states in its sphere of infl uence. It is driven However, gas availability is a central by the desire to restore some degree of the issue. In the time-frame to 2012, gas status quo ante, recognising the fi nality of the from Azerbaijan could provide up to 15 demise of the Soviet Union. In the oil and gas bcm to a west-bound pipeline; supplies in sector the ability of Transneft and Gazprom excess of that would need to be sourced to block Central Asian and South Caucasian from new investment in Azeri prospects access to European oil and gas markets and in Turkmenistan and Kazakhstan. In through their control of the only available addition, pipelines crossing up to eight transit pipelines has been a key instrument. international borders face major risks South Caucasian and Central Asia’s policy and will not proceed in the time frame to towards Russia has been balanced by the fact 2015 in the absence of signifi cant political that Russia provides a secure route to maket Natural Gas Market Review 2007 • Non-OECD Country/Region Update 160

Figure 43 Pipelines in Central Asia

Minsk BELARUS Ishim-Astana- RUSSIA RUSSIA Orenburg Atasu, 935km Rydnyi-Astana- Astana Kiev Orsk Atacy, 895km Karachaganak UKRAINE Krasny Oktyabr Atasu-Druzhba Shalkar-Atasu Atasu 905km 895km MOLDOVA Horgos- Severny Ustyurt KAZAKHSTAN Atyrau Urumchi Shalkar-Balskash Odessa Beiney-Bozoi 660km 1500km Almaty-Horgos RUSSIA 450km Shalkar- ROMANIA Novorossiisk Samsonovka- 360km Samsonovka Lunnan Almaty, 676km Constanta 1200km Zapadny Shymkent Almaty Aktau Ustyurt BULGARIA GEORGIA Burgas UZBEKISTAN Bishkek Supsa Tbilisi Tekesu Samsun Batumi KYRGYZSTAN Istanbul AZERBAIJAN Shagyr Yerevan Tashkent Ankara Baku Erzerum Turkmenbashi ARMENIA Chardzhou Kirikale AZER. TURKMENISTAN TAJIKISTAN TURKEY Izmir Tabriz Dushanbe Ashgabat Mary CHINA Dauletabad Ceyhan Neka Donmez Tehran CYPRUS SYRIA Kaboul Islamabad LEB. IRAN Bagdad AFGHANISTAN IRAQ Esfahan ISRAEL JORDAN Quetta KUWAIT EGYPT New-Delhi NEPAL PAKISTAN Katmandu 0Miles 200 BAH. 0Km 300 SAUDI OMAN Existing gas pipelines ARABIA QATAR INDIA Planned gas pipelines UAE OMAN The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source: IEA. for their oil and gas production even if at a offshore Azeri Chirag Guneshli fi eld. The discounted price, which was substantially subsequent agreement between Kazakhstan increased in 2006, but still remains below and Azerbaijan to commit additional Kazakh market worth, (as defi ned by European net oil volumes for export through BTC via the back prices), although higher than Russian Kazakh Caspian Transportation System internal gas prices. could ultimately be in the range of 1 mb/d. These are pivotal events in tapping Central The evolution in oil sector relations Asian hydrocarbon resources. Other export between Russian and Central Asian states options have recently become available and the south Caucasus shows that the near to Central Asian and Caspian oil producers monopoly position of Transneft in Russia such as the Atasu-Alashankou export link to is increasingly offset by the opening of China, rail transport or exports by barge to alternative routes to markets. The fungible Caspian ports such as Neka in Iran, Baku in nature of oil as a global commodity opens Azerbaijan and Machakala in Russia. up more export modes when compared to gas. The Baku Tbilisi Ceyhan (BTC) pipeline The gas sector is up against more diffi cult entered into operation in summer 2006, obstacles – many a result of its costlier exporting up to 1 mb/d of oil from the and more rigid infrastructure. Russian Natural Gas Market Review 2007 • Non-OECD Country/Region Update 161

resistance to allowing Central Asian Union (for example Belarus). Gazprom’s and South Caucasian states to diversify focus on “reacquisition” of these transit investment and export routes is driven by pipelines is detracting from investments the Russian state’s interests in preserving in the Russian upstream and expanding Gazprom’s monopoly over exports. Gazprom inherited the major The relationship between Russia and part of the centralised Soviet Union’s gas Central Asian gas producers, of which export system and is using this to assert Turkmenistan is believed to have the as much control as possible upstream into largest gas potential, will shape the future producing countries of Central Asia. This of Caspian gas. Russia, given its past approach is also being applied to parts relationship with the region, may seek of the gas transit system now in other to delay any Trans Caspian gas export countries formerly part of the Soviet options that could link Central Asian

Box 4 Central Asia’s eastern ambitions

Turkmenistan wants to develop alternative export routes independent of transit routes in Russia. Current lack of progress on Trans Caspian options has lead to a pipeline plan to China. China has aggressively pursued this possibility, especially given uncertainty regarding the availability of resources from Russia and Western China to fi ll the proposed second West-East pipeline. In April 2006, then-President of Turkmenistan, Saparmurat Niyazov, signed an agreement in Beijing with Chinese President Hu Jintao under which China pledged to purchase 30 bcm per year of gas at the Turkmenistan border for 30 years, «starting from the date the Turkmenistan-China gas pipeline is commissioned in 2009.» The two governments agreed to build a gas pipeline between the two countries and jointly develop natural gas resources in the eastern area on the Amu Darya River. CNPC is preparing for as much as 30 bcm per year supply starting in 2009 (or later), through a 3,000-km pipeline traversing Uzbekistan and Kazakhstan to connect to the West-East Pipeline in the Xinjiang Uygur Autonomous Region. As much as USD 13 billion would be invested to carry the gas at USD 1.2 - 1.5/MBtu. Kazakhstan is conducting a feasibility study for a gas pipeline to China. According to state Kazmunaigaz, two routes are being evaluated: the southern line to go through consumption centers in the southern part of the country and the central line parallel to the existing crude pipeline. Kazmunaigaz said in Beijing in 2006 that Phase 1 construction of a 10 bcm per year pipeline to China would be undertaken jointly with CNPC for completion by 2009. Expansion to 30 bcm per year is targeted for completion by 2012. From the Chinese border, a spur would link the pipe to the West-East gas pipeline. The Turkmenistan – China and Kazakhstan – China pipelines could be combined into one. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 162

production capacity through Southern through Turkey (as discussed in the section Corridors directly to European demand on Turkey). However, in the past, neither centres, for example by supplying these Turkmenistan nor Uzbekistan has been a markets directly from its own network, or particularly hospitable environment for contracting all available gas for export. In Western companies. 2003, Gazprom contracted nearly all of the gas export potential of Turkmenistan and It is possible that the death of former concluded similar strategic agreements Turkmen President Niyazov will provide with Kazakhstan and Uzbekistan. Including an opportunity to re-open the possibility re-export to Ukraine (Turkmenistan’s tra- of westbound trans-Caspian gas. For the ditional export market) currently about moment, only China and Iran offer direct 50 bcm of Central Asian gas is exported export opportunities; there is considered to Russia – equivalent to 8% of Russian to be enough reserves for more than indigenous production. these two markets would require, although transparency on these reserves Russia recently agreed to raise gas prices is especially poor. East-bound options for to USD 2.64/MBtu (USD 100/1 000 m3) for gas export are attractive for Central Asian Central Asian gas whereas Russia is paid states to consider, even at a discounted nearly USD 7.91/MBtu (USD 300/1 000 m3) price, because of the potentially large at Russian export points (including transit market size. Moreover, such options tend costs). For now, Belarus and Armenia pur- to improve the negotiating position of chase gas at a substantially lower prices. Central Asian gas producers with Russia. Though the price differential between Another constraint which may be felt the purchase price of Central Asian gas by companies of IEA member states is and European border prices thus remains concern for their competitive position in the same for Gazprom, it has decreased Russia and whether Russian reaction to imports from Turkmenistan from the their Central Asian activities might impair originally 60-70 bcm agreed in 2003 to their (admittedly limited) access to much 50 bcm for 2007. It is not quite clear what larger upstream oil and gas assets in Russia, led to this change in volume. On one including offshore. Russia itself may be hand this may have been a response to pondering the implications of opening increasing gas prices; on the other hand east-bound opportunities for Caspian gas it may refl ect the current production for its long term, privileged relationship and export limits in Turkmenistan due to with Central Asia and South Caucasian investment constraints. states. Despite precedents created by massive investment in subsea gas-links With gas prices in European markets rising in the (existing) and Baltic Sea recently (according to oil indexation) and (under construction) by Gazprom, Russia given the potential for Central Asian gas continues to raise delimitation reserves to service those markets, there is and environmental concerns about sub- growing European interest in buying and sea gas pipelines as arguments against shipping Central Asian gas by pipelines any Trans Caspian gas options. that do not cross Russia, but instead transit Natural Gas Market Review 2007 • Non-OECD Country/Region Update 163

In the meantime, Gazprom has continued People’s Republic of China the gas price rises seen in 2006 into 2007 for most FSU and former Soviet bloc countries, Gas use in China is still small, currently towards west European levels. Gas prices only 3% of demand and likely to grow to Georgia have increased in the order of slowly to 4% by 2015. This corresponds to 400% in two years from an unsustainably gas use growing from 47 bcm in 2004 to low USD 1.32/MBtu (USD 50/1 000 m3) 69 bcm in 2010 and 96 bcm in 2015 (WEO to USD 6.07/MBtu (USD 230/ 1 000 m3). 2006). By contrast, statements from the Ukrainian price increases were at the heart Chinese government and analysts indicate of the interruption of supplies witnessed signifi cantly higher hopes, ranging up to at the beginning of 2006, while prices to 190 bcm of consumption by 2015, based Belarus have been left in a transitional on estimates of domestic production of up arrangement towards European levels to 120 bcm and optimistic assessments of (Figure 40). LNG and pipeline imports. Up to now, most gas has been produced locally, but import The outcome of gas price negotiations infrastructure is being established rapidly between the State Oil and Gas Company as demand increases beyond domestic of Azerbaijan and Gazprom of Russia in supply – echoing similar trends amongst January 2007, may show the limits of IEA countries, though not necessarily for Gazprom’s negotiating strength. Here the same reasons. Azerbaijan chose not to accept the USD 6.07/MBtu (USD 230/1 000 m3) price China accepted its fi rst LNG shipments offered by Gazprom for the gas it proposed in 2006 and a second terminal is well to sell Azerbaijan in 2007. The Azeris underway, while a third, in the Shanghai chose to rely on indigenous production area, started construction recently. comprising associated gas from Azeri Although Chinese energy demand is Chirag Guneshli (at the expense of re- growing rapidly with GDP, the presence injection, slowing down oil output) and of plentiful domestic coal supplies Shah Deniz volumes that would ramp up could indicate that gas use countrywide over the year, next to traditional onshore seems set to remain relatively small. production. Azerbaijan has also switched Nevertheless, Shanghai in particular could to fuel oil power generation and delayed be a substantial gas importer by 2015. exports of gas to the Turkish market via the South Caucasus Pipeline. On the other Shanghai and LNG hand this might be seen by Russia as a desirable outcome: locking up Azeri gas for One important development in 2006 domestic use and hence limiting its ability concerns a new LNG project into the to compete with Russian gas in Europe. Shanghai market. This area may have a signifi cant infl uence on total Chinese gas demand, as well as the natural gas market in East Asia as a whole, largely because of its ability to compete for globally priced LNG supplies which may be too expensive Natural Gas Market Review 2007 • Non-OECD Country/Region Update 164

Figure 44 Gas infrastructure of China RUSSIA RUSSIA KAZAKHSTAN

MONGOLIA

West to East pipeline Beijing N. KOREA TAJIKISTAN JAPAN KOREA CHINA

Shanghai

NEPAL BHUT. 0Miles 400 0Km 600 BANG. Gas pipeline INDIA Gas pipeline planned LNG terminal MYANMAR LAOS LNG terminal planned The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source:The Petroleum Economist Ltd. for other Chinese regions. It is also worth noting that the planned LNG receiving faster. A 5 bcm per year expansion of the terminal in Shanghai is most likely to be line itself is now underway. the last one in China built before the end of this decade. According to a recently released energy white paper, Shanghai plans to more than The Yangtze River Delta area surrounding double the ratio of natural gas in its energy Shanghai has a prodigious appetite for consumption by 2010, with imported LNG gas. Shanghai fi rst started using natural playing a key role in achieving the goal gas from the offshore Pinghu fi eld in 1999. (the municipality based the white paper In 2003, when the fi rst eastern section on policies in China’s 11th Five-Year Plan, of the 4 000 km West-East Pipeline was 2006 - 2010). By 2010, Shanghai plans to commissioned connecting the gas-rich have gas accounting for 7% of its primary Xinjiang Uygur Autonomous Region in energy mix, up from 3 % in 2005. The city northwest China to demand centres also hopes to cut its coal dependence to around Shanghai. At the time, the pipeline 46% by 2010, from 53% in 2005. operator PetroChina was worried that the 12 bcm per year line would not be In August 2006, Shanghai LNG Co., Ltd., a fully utilized for several years. After the joint venture between Shanghai municipal pipeline was completed in 2004, however, utility Shenergy (51%) and CNOOC (49%), the pipeline fi lled quickly but demand in awarded the terminal’s main cons-truction the Shanghai area could have grown even contract to a consortium led by Ishikawajima- Natural Gas Market Review 2007 • Non-OECD Country/Region Update 165

Harima Heavy Industries (IHI) of Japan. The is well above the prices to be paid for the contract of about USD 260 million consists contracts signed by CNOOC with Australian of several components, with the Japanese and Indonesia suppliers for delivery to company responsible for the facility’s three earlier terminals in Guangdong and Fujian 165 000 cubic meter storage tanks and a (said to be capped at USD 3.10/MBtu and venture comprising Chinese Taipei’s CTCI USD 3.80/MBtu, respectively). But the Corporation and local Chinese fi rm Wuhan delivered USD 6 - 7/MBtu price is well below Engineering Co., Ltd. (WEC) handling the those discussed in other deals in the region site preparation, the marine facilities, the (including buyers in Japan and Korea). regasifi cation equipment and other related infrastructure. The Petronas deal is for 25 years, starting in 2009. Petronas said it would initially CNOOC continues to consolidate its position deliver 1.4 bcm per year (1 mtpa), rising as China’s No. 1 LNG importer, while trailing to 4.5 bcm per year (3.3 mtpa) after 2012 the other two national giants PetroChina from Malaysia LNG Tiga (III). Malaysia’s and Sinopec in domestic gas production. three plants will have a combined pro- It forged ahead with the third facility at duction capacity of 32.7 bcm per year Shanghai, after starting operations in the (24 mtpa) after the MLNG Dua (II) plant is country’s fi rst terminal in Guangdong in debottlenecked by October 2009. the summer of 2006. Its second terminal in Fujian is under construction and is The additional supply may come from a due to start receiving LNG in 2008. The third train at MLNG Tiga. It is not yet clear Shanghai terminal, strongly supported by whether there are enough reserves to cover the local government who wants to cut air contract extensions at MLNG Satu and pollution, will have an import capacity of Dua as well as expansion capacity at Tiga, some 4 bcm per year. Construction started although a string of exploration successes at the beginning of 2007 for completion in in the waters off Sarawak may have eased summer 2009. The regasifi ed LNG would these concerns recently. It is possible that be primarily supplied to power generation Natuna D Alpha in Indonesia could feed the plants planned by Shanghai City (3.6 GW in expansion. Meanwhile, CNOOC appears to total). have agreed with Indonesia’s upstream regulator BP Migas to divert some of the LNG for the facility is to come from Malaysia’s Tangguh volumes contracted to supply to Petronas. The Shanghai LNG deal with the Fujian terminal to Shanghai instead. Petronas was the fi rst LNG supply agreement signed by China since 2002. Rising global CNOOC says that it aims to build a trans- LNG prices had made deals diffi cult for other coastal natural gas pipeline linking major Chinese markets in which the gas prices have coastal cities from the south to the north been fi xed. It is to pay USD 5.6 - 5.8/MBtu in 10 to 15 years. The trunkline would FOB at a USD 60/bbl oil price, according to a be fed by imported LNG in addition to senior offi cial at the National Development the company’s offshore gas from Bohai and Reform Commission (NDRC), China’s Bay, East China Sea and South China Sea. top economic planning agency. The price The strategy is to build individual gas Natural Gas Market Review 2007 • Non-OECD Country/Region Update 166

consumption centres fi rst, to expand into Expansion of the Pinghu pipeline surrounding areas and then to link each center with pipelines. The Pinghu gas fi eld in the East China Sea southwest off Shanghai, operated by Expansion of the West-East pipeline Shanghai Natural Gas Co., a joint venture between Shenergy (40%), CNOOC (30%) The entire 4 000-km West-East Pipeline, and Sinopec (30%), started to deliver which supplies gas from the western gas to the Pudong district of Shanghai Xinjiang region to the eastern consuming via a 389 km undersea pipeline in 1999. region including Shanghai, started The delivered volume is to be boosted to commercial operation at the end of 2004. 800 mcm per year by the end of 2007 The pipeline carries 12 bcm per year, of from the current 600 mcm per year. The which the Shanghai area consumes 1.3 bcm wholesale “city gate” price is reported to annualy. The pipeline operator, PetroChina, be around USD 5.1/MBtu in 2005. has a gas sale agreement with Shanghai Natural Gas Pipeline (which was signed in Sinopec’s Sichuan-East pipeline January 2004) under which the gas is sold at about USD 4.3/MBtu, delivered at the Sinopec (China Petroleum & Chemical Shanghai city gate. Corporation) plans to construct a pipeline to supply gas from the Puguang fi eld in PetroChina plans to boost the capacity northeastern Sichuan Province to growing of the West-East pipeline to 17 bcm markets of the eastern seaboard, including per year by the end of 2007 by adding Shanghai. The company claims that the compression to the existing facilities. The Puguang fi eld is one of fi ve gas fi elds with company also is considering construction reserves of more than 200 bcm discovered of second, parallel pipeline that would in China. In early 2006, Sinopec submitted carry gas from Xinjiang and, it is hoped, a proposal for Phase I development to Central Asia and/or Russia (see separate the National Development and Reform sections). This parallel line would branch Commission (NDRC. A pipeline was orig- south at Zhengzhou in Henan Province inally planned from the fi eld to Jinan and terminate in Guangdong Province. in Shandong Province. The State then Assuming these projects go ahead, the authorized the company to commence ultimate total transportation capacity preliminary work on the project. of the West-East pipeline system would be 26 bcm per year by 2020. Although In summer 2006, Chairman Chen Tonghai details of the route have not been of Sinopec stated that the proven disclosed, there might be two new lines reserves stood at 322 Bcm and anticipated to be installed between Zhengzhou and production of commercial gas of more Wuhan in the Hubei Province and between than 9 bcm per year by 2008 and 12 bcm Changsha Hunan Province and Guangzhou per year by 2010. in Guangdong Province, as a transmission pipeline is already in operation between Wuhan and Changsha. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 167

Table 28 China’s domestic pipeline plans

Promoters Anticipated yearly volume Current: 12 bcm West-East expansion PetroChina By 2007: 17 bcm By 2020: 26 bcm Shanghai Natural Gas Co. Current: 0.6 bcm Pinghu expansion Shenergy (40%), CNOOC (30%), By 2007: 0.8 bcm Sinopec (30%) By 2008: 9 bcm Sichuan-East Sinopec By 2010: 12 bcm

Source: Media reports.

The company apparently planned the In addition to the pipeline supply, the pipeline to Shandong for several reasons. company is reported to have a plan to The Sichuan gas market, the largest in China, install a USD 520 million (4.3 billion yuan) is well developed and mostly controlled by gas-to-liquid (GTL) project in Chongqing the bigger rival PetroChina leaving little City with initial production capacity room for Sinopec. In turn, Sinopec has of 2 million tonnes per year fed by the been developing the Shandong market Puguang fi eld. and converting coal-based gas to natural gas in the region; Sinopec is thus trying to establish an advantageous position in India Shandong against PetroChina. Moreover, Sinopec enjoys good relationship with India’s production and the Shandong provincial government, consumption as it operates the Shengli oilfi eld – China’s second largest – and associated Gas represents less than 10% of total downstream facilities in the province. primary energy demand in India. In fi scal year 2005/0617 India used 38.4 bcm of gas, In August 2006, the National Development compared to demand of 34 bcm in 2004/05. and Reform Commission (NDRC), however, Of the use in 2005/06, 31.3 bcm was sourced rejected the original plan and asked it domestically and 7.1 bcm was imported as to be revised to include gas supply to LNG. The public sector accounts for 78% the Shanghai’s Pudong district. Sinopec of production, while private producers for accepted the idea and submitted a revised 22% of production. plan. In the new plan, the main line would be a 1 674-km one from the fi eld to Shanghai, The medium- to long-term trend points with an 842-km branch from Yichang in towards a strong increase in private/JV Hubei Province to Henan Province. gas, while the gas from public fi elds, based

17. India’s fi scal year runs from 1 April to 31 March. Production for calendar year 2006 stood at 31.6 bcm. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 168

on the Administered Pricing Mechanism optimistically the “new North Sea”. (APM) declines. APM gas is currently sold Production and development of fi elds in at about USD 1.8/MBtu while private/JV the KG basin is costly due to the depth of gas is sold at around USD 4.5/MBtu. Indian the reserves and the diffi cult terrain. This domestic supply is not suffi cient to meet will impact on the price at which these current demand. Against offi cial demand new domestic gas fi nds can be marketed. of 118 mcm per day, actual supplies were only 62 mcm per day during the last fi scal Private sector joint venture (JV) Reliance- year. It is unclear how high suppressed (or Niko was the fi rst to strike gas in late 2002 latent) demand is. and its block has estimated reserves of 410 bcm (14.5 Tcf). Production is now The domestic production outlook is expected to commence in mid-2008 at tentative despite the undisputed existence an initial rate of 40 mcm per day to be of large gas reserves. Estimates over India’s doubled to 80 mcm per day by end 2009. future production vary. According to the Based on current indications Reliance- government, India could produce 42 bcm Niko expects a minimum selling price of in year 2010 (down from 44 bcm in the USD 4/MBtu. This price is widely believed GMR 2006). By 2015 this could increase to to be too low to remunerate development 59 bcm with the majority of gas supplies costs and associated investments in from the private sector. The uncertainty pipelines. over domestic gas production is due to investment and pricing uncertainties; at Gujarat State Petroleum Corporation what pace producers are willing to bring (GSPC) has estimated reserves of 566 bcm fi elds into production for a given price. (20 Tcf) in an adjacent block to Reliance- Niko. Production from this fi eld is expected Reserves additions for 2010/11 at a rate of 54 mcm per day. Finally in late 2006 ONGC announced that There have been several considerable re- it had found around 595 bcm (21 Tcf) in serve additions under the New Exploration a fi eld in the same region. The upstream Licensing Program (NELP). Moreover, sub- regulator has not yet certifi ed the fi nd. stantial parts of India’s territory remain Based on available documentation the unexplored leaving the promise of additional regulator will likely make a downward signifi cant reserves. India fi nalized NELP adjustment to a maximum of 396 bcm VI during 2006 under which it offered 55 (14 Tcf) pending further tests by an exploration blocks. Preparations for NELP VII independent third-party. are ongoing. In addition several smaller gas fi nds have Since launching its NELP process in 1999, been made under the NELP. By 2010-11 three major fi nds have been made, all in it is expected that at around 100 mcm the eastern offshore Krishna-Godavari (KG) per day will be available from the private basin. There is now talk that the KG basin sector/JV from the KG basin alone. India and an area slightly north could contain is also looking towards exploiting its up to 50 Tcf and the area has been dubbed Coal Bed Methane (CBM) potential as an Natural Gas Market Review 2007 • Non-OECD Country/Region Update 169

alternative source of gas. The third round After resisting for a long time, NTPC, India’s of CBM-II policy was launched during 2006 largest public power sector producer, and 10 CBM blocks have been awarded. had to resort to buying spot LNG in 2006 for up to USD 12/MBtu to overcome LNG imports supply constraints to its plants. This shift in customer attitude and the strong India’s import capacity currently stands economic growth over the last years has at 12.2 bcm per year (9 mtpa) through two resulted in a more positive assessment of terminals located on the Western coast. the future of LNG in India. Petronet LNG’s Dahej terminal is capable of handling 8.8 bcm per year (6.5 mtpa). By 2010 India’s LNG import capacity could Dahej is being supplied from Qatar under reach 31.3 bcm per year (23 mtpa). In a long-term contract, supplemented by addition to the Hazira plant, this would spot cargoes from other sources. The include; Dahej capacity expansion to Shell-Total promoted Hazira terminal 17 bcm per year (12.5 mtpa) by 2008; the imported only 0.24 bcm (175 000 tons) commissioning of the Dabhol-Ratnagiri through its 3.4 bcm per year (2.5 mtpa) terminal at 7.5 bcm per year (5.5 mtpa) facility during fi scal year 2005/06, the by 2009; and the initial 3.4 bcm per year fi rst year of operation. For the year (2.5 mtpa) phase of Kochi terminal which ending in March 2007, the Hazira terminal Petronet is promoting in the south operators expect a capacity utilisation of western state of Kerala. Utilisation of the around 30%. facilities is, however, subject to securing gas supplies and availability of pipeline This increase in utilisation of existing facilities downstream. infrastructure is primarily explained by Indian customers adjusting to paying India is working towards bringing the international spot prices for gas. Fertiliser, abandoned integrated Dhabol LNG re- power and petrochemical plants are the gasifi cation facility and power station major customers and they are switching into operation. The re-named Ratnagiri away from naphtha to gas. Mostly these facility is currently operating its power industrial producers are not eligible for plant at only 15% of the 2 184 MW APM gas and are also experiencing prob- capacity, using naphtha (as per the lems obtaining supplies of domestically initial Dhabol contracts). The tentative produced private/JV gas. However, some date for commissioning of the Ratnagiri public sector power producers and steel regasifi cation facility is September 2009. companies have remained loyal to naphtha Until the integrated regasifi cation facility and show higher consumption during is ready, the Ratnagiri plant is expected to fi scal year 2006/07 then in the previous run on LNG supplied from the Dahej and year. Whether this is due to lower naphtha Hazira terminals. Petronet LNG is charged prices as a result of a local supply glut, with procuring 2 bcm per year and is hoping or to lack of availability of natural gas is to source the LNG at a delivered price of diffi cult to determine. USD 10 - 10.5/MBtu. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 170

The construction contract for the Kochi Transmission system terminal is to be awarded by end 2007, targeting a 2010 start-up. Petronet is India’s transmission system will need to negotiating with ExxonMobil for a 3.4 bcm be substantially expanded to create an per year (2.5 mtpa) share of the Gorgon Indian gas grid. GAIL, the monopoly pipeline LNG supply from Australia. Originally, it operator, operates about 5 600 km of was planned that LNG to Kochi would be pipelines with a capacity of around 130 sourced from Qatar under a long-term mcm per day, of which only around 64% is supply contract commencing in 2009. currently used. GAIL has ambitious plans to However, Petronet is now considering further expand the system. Its two major diverting this gas to its expanded facility in priorities are to connect all LNG terminals Dahej. The Kochi terminal may eventually with its trunk-pipeline in the West-North be expanded to 6.8 bcm per year (5 mtpa). and to connect domestic gas on the Eastern coast to consumers in the North and South If all LNG terminals are made operational of the country. Private investment in as currently planned and if domestic transmission infrastructure has so far not production from new fi elds comes on- been permitted. However, as part of the new stream as scheduled, India could be sector regulatory framework, transmission supplied with 87 bcm gas by 2015, of which now falls under the regulatory authority. 30 bcm would be imported as LNG. Reliance is keen to engage in laying pipelines

Figure 45 Gas infrastructure of India and surrounding countries Amritsar CHINA IRAN New-Delhi Delhi PAKISTAN NEPAL Jaipur BHUTAN

Patna BANG. CHINA

Bhopal Jamnagar Dahej OMAN Hazira INDIA Calcutta MYANMAR Cuttack LAOS

Bombay Dabhol Hyderabad THAILAND

Madras 0Miles 500 Bangalore CAMB. 0Km 500 Kochi Gas pipeline Trivandrum SRI LANKA Gas pipeline planned or under const. LNG import terminal LNG import terminal under const. The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source:The Petroleum Economist Ltd.. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 171

to be able to market its gas from the KG the regulatory mandate. The Act provides basin and has prepared the necessary project for open access for transportation of proposal for approval. petroleum products and natural gas on a common carrier principal. Pipeline imports India’s “Policy for Development of Natural India’s plans to import gas via pipeline Gas Pipelines and City or Local Natural from its neighbouring countries have Gas Distribution Networks” was codifi ed not progressed physically during the last in December 2006. The policy seeks to year. However, contractual progress came promote competition and transparency in in the form of an agreement reached the transmission sector and is also charged between India, Pakistan and Iran on the with vertically unbundling interests in pricing formula for gas through the Iran- upstream and downstream sector where, Pakistan-India (IPI) pipeline. Iran offered for example, companies such as GAIL are to sell gas at a price based on 6.3% of the present. The policy requires mandatory Japanese crude cocktail (JCC, an average excess capacity of 33% for all pipelines of Japanese crude import prices) in USD which is likely to adversely affect the rate per barrel plus USD 1.15/MBtu with a ceiling of investment in such pipelines. of USD 70/bbl and a fl oor price of USD 30/bbl. Both India and Pakistan seem to have accepted this new pricing proposal. Latin America highlights

India would receive a maximum of 90 mcm Since the 1990s, the relationship between per day through the IPI pipeline. India’s gas-rich countries and gas-dependent import price at the Pakistan border would consumers has played a pivotal role in be about USD 5/MBtu (at USD 60/bbl JCC) defi ning Latin America’s energy landscape. – without transit and transport charges. Because of the capital costs required for Clearly, the higher prices being paid for its transport, the evolution of natural gas LNG imports and the potential pipeline trade has been particularly revealing of imports will result in private domestic the diverging rationale between energy producers requesting higher gas sales politics and energy economics in the prices within India. region. The recent rise in natural gas prices, stalled regional integration and Regulatory framework declining or delayed upstream investment as a result of nationalization moves have The Petroleum and Natural Gas Regulatory further exacerbated that relationship. Act, 2006 has been notifi ed in April 2006 and the Regulatory Board is in the process In 2005, natural gas represented 20.5% of being established. The Board will be of total primary energy supply in Central charged with regulating specifi c activities and South America. The region produced relating to petroleum, petroleum products 135 bcm of gas and consumed 120.5 bcm, and natural gas. However, upstream of which of which 32.5 bcm was used to activities and pricing are excluded from produce electricity. Gas consumption in Natural Gas Market Review 2007 • Non-OECD Country/Region Update 172

South America – i.e. excluding Trinidad than most natural gas pipeline projects. and Tobago – is highly concentrated. Despite the higher cost involved in Five countries: Argentina, Bolivia, Brazil, developing LNG capabilities, diversifying Colombia and Venezuela, account for 95% supply options and linking national mar- of gas production, while Argentina, Brazil, kets to the rest of the world is seen Chile, Colombia and Venezuela represent as more fl exible and more secure than 94% of primary gas consumption and 94% expanding or building new pipelines that of gas used for power generation. tie some countries to their neighbours. In several cases, previous plans to expand and Gas dynamics in South America are exhi- extend pipeline networks to link producing biting a growing paradox. Although the countries with major consumption centres region has more-than adequate gas reserves have given way to new calls for LNG terminals. to further develop the gas markets in general, Accordingly, in the last three years, four and the gas for power segment in particular, regasifi cation terminal projects for natural because of the recent surge in resource gas in South America have been announced, nationalism in the main gas-supplying two in Brazil and two in Chile. countries and the ensuing concerns over energy security, gas consuming countries The Southern Cone conspicuously illustrates are increasingly turning to liquefi ed natural the trend away from regional co-operation. gas (LNG) as a more reliable source of The uneven geographical distribution of supply. Many of South America’s natural gas gas reserves and gas demand centres had resources are located in countries that are led (in the 1990s) to a rise in cross-border increasingly antagonistic toward foreign gas trade, with Argentina and Bolivia as the and private investment and are considered main gas suppliers and Chile and Brazil as as unreliable partners in cross-border gas the largest gas importers. Yet today, while supply agreements, most notably Argentina, on a physical/technical level the availability Bolivia and Venezuela. of gas supplies remains unquestioned – Bolivia is endowed with the second largest Therefore, while there is a compelling natural gas reserves in South America economic rationale for intensifying re- – on a political level, the security of cross- gional energy trade and regional energy border gas supplies has become a growing integration, current political and economic concern. Argentina’s unilateral cuts of its trends are leading South American policy exports to Chile and the uncertainty linked makers to focus on their national interests to Bolivia’s future gas exports following and on energy security. This dichotomy the May 2006 nationalization of the sector is remarkably illustrated by the long have underlined these concerns. standing dispute between Bolivia and Chile, when both countries’ economies could Insuffi cient gas supply has plagued Argentina signifi cantly benefi t from cross-border since 2004 after years of sub-sidized gas gas trade. In this context, LNG represents prices and underinvestment. To avoid cuts a more stable source of supply with more to its domestic consumers, Argentina uni- transparent price and contracting terms laterally decided in mid-2004 to cut exports and available within a shorter timeframe to Chile, creating severe supply problems for Natural Gas Market Review 2007 • Non-OECD Country/Region Update 173

the latter. Chile, which has very limited gas the Pacifi c coast from Peru to Chile, as reserves, has seen its daily gas supply from well as the use of existing pipelines from Argentina occasionally reduced by up to Chile to Argentina and the construction, 50% in the past two years. expansion, or completion of pipelines in Argentina, Brazil and Paraguay. The Chile is therefore turning to LNG to com- whole project has been estimated to cost pensate for rapidly declining Argentinean between USD 2.5 and USD 3 billion. After pipeline gas, on which it depends for several high-level multilateral meetings, about 75% of its current 22 mcm per day discussions about the project have gas consumption. The Mejillones project is subsided somewhat since December 2005, slated to start up operations by end 2008 following diplomatic friction between with initial shipments of 5-6 mcm per day. Chile and Peru and the announcement of a This comes in addition to the Quintero competing regional pipeline project from LNG terminal already under way, which Venezuela. The current regional political is expected to start operations in late climate is not particularly favorable for 2008, with a capacity of 3.4 bcm per year such a project to move forward. (2.5 mtpa). By 2010 Chile plans to receive less than 50% of its gas supply from Bolivia has seen gas production capacity regional sources, down from 75% in 2005. reach a plateau despite large proven and probable reserves. The nation lacks the Peru could potentially export LNG to necessary capital and foreign investors have Chile in the medium term. In early 2007, put a hold on any new investments. This lack Peru LNG consortium, lead by Hunt Oil, of investment in exploration and production moved to construct an LNG pipeline and and in transportation has delayed the export terminal at Pampa Melchorita, sanction of any new export projects in the 135 km south of Lima. The Peru LNG facility short to medium term. Net foreign direct will have an operating capacity of 6 bcm per investment (FDI) in Bolivia averaged 10% year (4.4 mtpa), with most of the production of GDP between 1998 and 2002, collapsed destined for the West Coast of North to 2.4% of GDP in 2003 and 1.3% of GDP America. Peru LNG consortium has also in 2004. According to the United Nations’ held discussions with ENAP, Chile’s state- Economic Commission for Latin America and owned oil company, about the possibility the Caribbean (ECLAC), FDI turned into a net of exporting LNG to Chile. export of USD 279.6 million, or -3.3% of GDP in 2005. Given the obvious complementarities among Southern Cone countries, an On October 31, 2006, the Bolivian govern- ambitious pipeline project that would ment concluded the renegotiation of up- bring gas from Peru’s giant Camisea fi eld stream operations contracts with all twelve to northern Chile and from there, connect E&P operators active in the country (BG, Total, into the Argentine and Southern Cone Repsol YPF and Petrobras, among others). gas network was proposed in mid-2005. However, this achievement was subsequently The proposed project would involve the undermined by the various postponements construction of a 1 500 km pipeline along of the signing of those contracts. Further Natural Gas Market Review 2007 • Non-OECD Country/Region Update 174

delays in approving these new gas contracts By 2010, Brazil hopes to reduce regional signed by Bolivia and Argentina could gas imports to one third or one quarter threaten YPFB’s (State oil and gas company from roughly 50% in 2005, thanks to a of Bolivia) investment programme resulting combination of a substantial increase in in possible shortages of gas destined for domestic production and LNG imports. Argentina. Some 44 contracts are still to be Combined investment in the LNG and approved by the Bolivian Senate; they include regasifi cation program is estimated to the construction of a new gas pipeline from cost USD 2.36 billion, including lease and Bolivia to Argentina, and the gradual increase operating costs of two fl oating storage in gas exports from 7.7 mcm per day, to up to and regasifi cation units (FSRUs). The fi rst 16 mcm per day in 2009 and then 27.7 mcm planned FSRU would process 14 mcm per per day in 2010 until 2025 and would cost an day and would be anchored in the bay estimated UDS 1.6 billion. located off the southeastern coast of Rio de Janeiro, close to the country’s largest Brazil is by far the country most affected natural gas market. The other FSRU would by the Bolivian hydrocarbon national- be located on the coast of Ceará State in isation as it depends on Bolivian gas for northeastern Brazil where there is large demand from thermal plants and would roughly 40% of its total gas supply. State- have a capacity of 6 mcm per day. By 2010- controlled Petrobras is the company most 2011, Brazil therefore plans to import affected by the new measures introduced 7 bcm per year of natural gas through by Bolivia’s nationalisation process. Gas these two regasifi cation terminals. The currently accounts for 9.1% of Brazil’s country has yet to tender contracts for primary energy supply, as the result of the LNG regasifi cation terminals as well an explicit government policy aiming to as for gas supplies. Thermal generation diversify energy sources in all sectors, is supplementary to hydro generation in including for thermal generation. The two Brazil. This fact leads to low load factors countries are linked by the 3 150 km Gasbol in thermal generation plants. Therefore, pipeline, the single largest private-sector LNG imports make sense as they avoid investment in South America to date with additional investments in pipeline ca- a total cost of USD 2.1 billion. The pipeline pacities, especially since the artifi cially has a maximum 29.7 mcm per day capacity low prices of gas for thermal-electrical and started operating in 1999. Brazil generation have started to signifi cantly currently imports an average 26-28 mcm increase in 2007. per day from Bolivia through the Gasbol pipeline. A concern in the wake of the In Venezuela, President Chávez announced Bolivian nationalisation in the medium- after his reelection in December 2006 that term is therefore the possible reduction of he would modify the gas law in line with gas imports, at a time when Brazil is short the oil re-nationalization process. This of alternatives and already faces gas supply is likely to have a more limited impact restrictions in the Northeast. than for the oil sector given that the private sector currently holds less than 10% of the country’s current gas output. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 175

Venezuela claims to have 4 300 bcm of 5% per year between 2000 and 2005. In of proven reserves of natural gas, yet the coming years natural gas is likely to insuffi cient gas supply in the west of the overtake oil as the second most prevalent country has affected petrochemical and fuel for electricity generation in the electricity production. This is the rationale region, while hydropower would remain for a 230 km underwater pipeline to the dominant source. The main structural import gas from neighbouring Colombia limitation to gas-based power generation whose construction began in July 2006, in South America is the abundance of with a total budget of USD 280 million. hydropower. This is especially true for The energy ministers of both countries Brazil and Colombia, where the share of recently declared that the transoceanic hydropower represented over 80% of pipeline would be fi nished by the end of gross electricity production in 2004. August 2007. Growing power demand across the The relationship between gas region, driven by relatively high economic and power generation growth rates as well as by improving electrifi cation rates indicates that ad- In Central and South America, natural ditional power generation capacity will gas is the fastest growing fuel source, be needed. However, the pace of gas with demand growing on average around for power demand growth could vary,

Figure 46 Major South American natural gas flows, 1975-2005

10

bcm

5

Imports 0

-5

-10

Exports

-15 1975 1977 1979 1981 1985 1987 1989 1991 1993 1995 1997 1999 2001 2003 2005e Argentina Bolivia Brazil Chile Trinidad Colombia Natural Gas Market Review 2007 • Non-OECD Country/Region Update 176

Figure 47 Gas infrastructure of South America and surrounding countries

BELIZE GUADELOUPE (FR.) GUA. HONDURAS BARBADOS EL SAL. NIC. Cartagena Caracas TRINIDAD & TOBAGO Port of Spain COS. RICA PAN. Atlantic LNG VENEZUELA Georgetown Medelin Santander Paramaribo Bogota GUYANA Cayenne Cali Apiay SURINAME FRENCH GUYANA COLOMBIA Quito Shushufindi ECUADOR Manaus Coari Fortaleza Natal Pucallpa BRAZIL Recife PERU Porto Velho Lima Mataripe Aracaju Peru LNG BOLIVIA Salvador Cuiaba La Paz Brasilia Ilo Corumba Sao Mateus Betim Potosi Vitoria Tocopilla Campos Mejillones PARAGUAY Rio Antofagasta Salta Sao Paulo Paposo Campos Basin Asuncion Sao Fransisco do Sul Catamarca Uruguaiana CHILE La Rioja Porto Alegre Cordoba Rio Grande Valparaiso San LorenzoURUGUAY Santiago Montevideo La Mora 0Miles 1 000 Conception/Talcahuano Buenos Aires Mar del Plata 0Km 1 000 Neuquen Bahia Blanca ARGENTINA Gas pipeline Viedma Gas pipeline Caleta Cordova planned or under const. Caleta Olivia Gas fields San Julian LNG export plant LNG export Punta Arenas plant planned Ushuaia LNG import terminal planned The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source:The Petroleum Economist Ltd..

refl ecting higher prices which are also into consideration, especially coal-fi red affecting the competitiveness of gas- power plants and greater use of domestic powered electricity. Because until recently renewable resources such as hydro and South America’s gas markets were isolated wind. from the rest of the world, gas prices were sheltered from price fl uctuations in other Therefore, on the one hand LNG could markets. Recent LNG developments have delay investment in E&P in some countries linked the region to the rest of the world and by opening new sources of supply to a producers such as Bolivia are accordingly formerly captive market. On the other raising prices to extract a greater share hand, the infl ux of LNG will likely impact of the natural gas production rents. regional prices by creating a common Consequently, the cost of incremental international reference parameter and natural gas production, combined with the could therefore provide incentives to political risk price premium, is forcing many invest in E&P in other countries to generate importer countries to take alternatives higher revenues. Natural Gas Market Review 2007 • Non-OECD Country/Region Update 177

Concluding remarks

The Bolivian nationalization and the re- nationalization drive in Venezuela have triggered a reversal of the gas integration trend of the 1990s. Concerns about the reliability of bilateral gas supply agreements and increasing gas prices in the region are signifi cantly refocusing national energy policies away from cross-border trade and joint pipeline projects toward global integration and the autonomous development of LNG. Regional energy integration has turned into a geopolitical project, disconnected from economic rationality and likely to remain at the level of grand political rhetoric.

In this context, the Great Pipeline of the South has become the fl agship project for Venezuela’s Latin America energy integration plans. The mega pipeline would cost an estimated USD 20 billion to link southern Venezuela to Argentina and continues to be promoted by the Venezuelan government despite its questionable economic rationale and highly challenging execution. To date, the other regional giant, Brazil, has opted for a conciliatory approach without signing into any fi nancial or binding commitments.

Natural Gas Market Review 2007 • OECD Country/Region Update 179

OECD COUNTRY/REGION UPDATE

North America However a large amount of natural gas was withdrawn from storage in February Together, the Canadian and United States following a particularly cold period. natural gas markets form the largest integrated gas market in the world, with Of special signifi cance in the United States Canada providing about a quarter of the was that the summer of 2006, during a combined gas production. In 2006, United period of exceptionally hot weather, saw States consumption was 618 bcm, met from two consecutive weeks of natural gas domestic sources (525 bcm) with almost all storage withdrawals in late July and early the balance coming from Canada. As the August, the fi rst-ever draws on inventory world’s second largest natural gas exporter, during the summer, threatening current Canada exports over half of its production patterns of seasonality. For the year 2006, to the United States, (104 bcm out of gas use in power was up 6.5 %. 190 bcm in 2006) accounting for about 15 % of United States’ gas consumption. Despite records for gas drilling production remains essentially fl at After a record 2005 hurricane season on the United States’ Gulf Coast, two relatively For 2006, the average natural gas rig mild winters left storage at high levels. count in the United States continued The gas storage surplus that started in the increases seen in the last four years, the winter of 2005-2006 grew to a record growing 16% to 1 372. Gas producers 18% surplus at the beginning of 2007. suffered in the fourth quarter of 2006 due

Figure 48 United States’ gas production: has it peaked?

570

bcm 560

550

540

530

520

510

500

490 2000 2001 2002 2003 2004 2005 2006

Source:IEA. Natural Gas Market Review 2007 • OECD Country/Region Update 180

to a 44% slump in gas prices to an average rate of about 10%. The Canadian dollar of USD 7.25/MBtu, while service costs for has appreciated 38% since 2002, further drilling continued to escalate. Competition eroding returns to producers. 370 Canadian for rigs has driven costs higher. Net income rigs were operating in January 2007, 200 of the independent United States’ oil and less than the record of 580 set in 2006. gas producers declined 62% between the Prices in Alberta fell by almost two-thirds fourth quarter 2005 and fourth quarter over the course of 2006. February 2007 2006. This group of producers develops saw some recovery, but prices were still 90% of the United States’ domestic oil 22% below those of early 2006. Companies and gas wells, produces 68% of domestic responded to all these factors by reducing oil and 82% of domestic natural gas. capital budgets 25 - 70% in the last half of 2006 as costs continued to climb. Major The same escalating costs and lower gas producers, including the country’s top prices have impacted Canadian companies three: EnCana Corp., Canadian Natural harder. Canada has a high proportion of Resources Ltd. and Talisman Energy Inc., shallow gas wells that deplete quickly and all of Calgary, signifi cantly reduced their are less profi table to drill when prices are gas exploration budgets for 2007. Some low. The strength of the Canadian dollar in USD 7 billion in capital was pulled out of recent years has meant producers have been the USD 33 billion conventional industry in realizing lower returns for their output than Western Canada. The Conference Board of their United States’ counterparts. Costs in Canada forecasts only a marginal increase Canada are climbing at an average annual in production – about 0.2% – for 2007.

Figure 49 United States’ coalbed methane and Gulf of Mexico gas production

200

bcm 180

160

140

120

100

80

60

40

20

0 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 Gulf of Mexico natural gas production U.S. coalbed methane production

Source:EIA DOE (2006 CBM Production Provisional). Natural Gas Market Review 2007 • OECD Country/Region Update 181

United States’ production is likely to struggle In summary, the cost of getting gas to the as the anticipated growth in unconventional end user has risen due to a combination of production (coal bed methane, shale and factors ranging from a tight service market tight sands gas) does not offset clear declines in terms of both rigs and skilled labour. in conventional gas output. When adjusted Because of these infl ationary pressures, for the impact of the hurricanes, United high gas storage levels at the end of the States’ production grew only modestly in winter heating season have been less of a 2006 despite the robust drilling and remains factor in determining the direction or level below the peak seen in 2001. In the short- of gas prices. term, continued expansion of unconventional production may be suffi cient to hold United Despite uncertainties about gas States’ production at constant levels or even supply, gas demand is expected to expand production modestly for several more grow, led by power generation years, as predicted by the United States’ Energy Information Administration (EIA). In the United States, total natural gas Figure 49 shows two of the most dynamic consumption is projected to increase by 2.9% sectors in United States production; coal in 2007 and 1.8% in 2008, after falling by 1.7% bed methane (growing) and Gulf of Mexico in 2006, on the back of lower residential and (declining). commercial demand (residential demand in January and December 2006 was 20% less At the beginning of 2006, the major than corresponding months a year earlier). Canadian production area, the Western Canadian Sedimentary Basin (WCSB) had The Annual Energy Outlook 2007 (AEO remaining gas reserves of about 1 613 bcm 2007) reference case, released in February and a reserves-to-production ratio of 2007 by the EIA, refl ects the evolution of approximately nine years. Since 2001, energy markets in an era of high prices by production from the maturing WCSB has projecting growth in nuclear generation, fl attened out, despite relatively high drilling more biofuels (both ethanol and biodiesel) activity; production in 2006 was about the consumption, growth in coal-to-liquids same as 2005. Marketable gas production (CTL) capacity and production, growing is expected to decline by about 10 % over demand for unconventional transportation the period to 2015. Production of coal bed technologies and accelerated improve- methane (CBM) is in its infancy. However, ments in energy effi ciency throughout the as conventional resources deplete, CBM economy. will play an increasingly important role due to the large resource potential. Projected In these forecasts, the amount of natural increases in CBM production over time gas needed to meet the United States may offset declines in conventional gas demand grows some 16% over the decade production. Infl ationary pressures in the to 2015. Most noteworthy is the rapid drilling sector have particularly affected growth in the amount of natural gas higher-cost CBM wells. required to generate electricity, which has increased 54% in the last decade, including more than 32 bcm in the past Natural Gas Market Review 2007 • Recent Events 182

three years. Gas use for power is forecast the 13% is permanent loss. Against these to grow by around 23% to 2015, although trends there are signs of increasing gas the average of private forecasts quoted demand in the refi ning sector and also in the Outlook shows a 40% increase (this associated with ethanol production. latter fi gure would imply gas demand increasing by around 80 to 90 bcm at Growing demand in Canada will affect current effi ciencies). After 2015-2020, exports to the United States. With a well growth is expected to slow, when new developed gas pipeline network linking coal and nuclear units appear. Enough gas- producing areas to markets, natural gas fi red capacity is in place today for electric is widely available from coast to coast in generation to increase sharply. Existing Canada. Total Canadian gas consumption gas capacity had a 35% utilisation rate in increased by 2.3 % in 2006 to just over 2006 compared to 71% for coal. However, 100 bcm. With approximately 50 % of higher prices may encourage conversion Canadians heating their homes with natural of the lower effi ciency boilers and turbines gas, residential gas demand experiences to higher effi ciency combined cycle plant, signifi cant seasonal fl uctuations and can reducing the gas supply needed to increase be volatile in winter depending on weather generation output. conditions. Commercial and industrial gas demand is generally responsive to Behind these power demand forecasts, macroeconomic activity and gas prices. several other trends can be discerned. Firstly, price sensitive industrial users have The power generation and oil-sands sectors been reducing demand. Industrial demand provide large potential for demand growth has fallen by nearly a quarter over the in the medium and long term. The last last decade, with sharp drops noticeable decade has seen noticeable additions in in 2001, when prices rose almost 20% gas-fi red capacity in several provinces, with and 2005, where hurricane induced price most increases concentrated in Ontario rises of 30% were especially damaging and Alberta. In Ontario, the government to industrial demand (as discussed in decision to phase out approximately the Natural Gas Market Review 2006). 6 000 MW of coal-fi red capacity by 2014 has Secondly, a fi rst quarter comparison of provided opportunities for new gas-fi red EIA’s estimated residential consumption power plants. Although there are several shows a 14% increase from 2006 to 2007, large hydro projects under development in refl ecting a return to more normal cold hydro rich provinces of Quebec, Manitoba weather compared to 2006. Taking the and Newfoundland and Labrador, as well year as a whole, residential consumption as signifi cant development expected for is expected to increase 10.8% in 2007. But other renewable power, gas-fi red gen- the American Gas Association (AGA) points eration is expected to remain an important out that on a weather normalized basis, technology for new capacity additions residential gas use declined 13% from during the coming decade. This will add 2000 to 2006, as residential consumers to the incremental demand for gas in this react to higher prices. AGA believes that sector, from the current level of around at least half and as much as two-thirds of 9 bcm annually. Offi cial forecasts show Natural Gas Market Review 2007 • OECD Country/Region Update 183

the gas share of electricity rising from 5% amounts to approximately 10 bcm. With in 2004 to 14% in 2010 and 23% in 2020. anticipated rising oil sands production, gas The latter fi gure implies around 180Twh demand from the oil sands sector is expected of gas fi red power output, around 40 bcm to double current consumption by 2015 and at current effi ciencies. In June 2006, the to continue rising after that date. Ontario Energy Minister directed the Ontario Power Authority to prepare a With rapid growth expected for the oil 20 year electricity supply mix plan. The sands, coupled with further gas-fi red power Government has accepted OPA advice that additions, natural gas demand is expected natural gas should only be used to meet to rise further to 2015. Canadian exports peak demand and ensure local reliability. to the United States fell a little over 2% in Ontario’s future electricity demand is 2006. By 2015, total Canadian gas demand likely to feature higher shares of renewable could be 25 to 30% higher than current energy demand, plus greater end use consumption levels. With increasing dom- effi ciency. estic demand and fl attening domestic production, gas exports to the United The Canadian oil sands industry concentrated States will probably trend downward over in the Fort McMurray area in Alberta the coming decade, resulting in a decline represents another large domestic market by about 5% over the period to 2015. for natural gas. Currently, the amount of natural gas used in the oil sands operations

Figure 50 Canadian gas exports

bcm 116

111

106

101

96

91 2000 2001 2002 2003 2004 2005 2006

Source:IEA. Natural Gas Market Review 2007 • OECD Country/Region Update 184

North America is setting itself to sales to North America, since the latter will be priced on a Henry Hub basis, import LNG in large quantities possibly with a slight discount. Although LNG imports declined in 2006, most forecasters are predicting a rapid While North American market structures increase in LNG imports. make it diffi cult to contract long-term for dedicated production capacity, increasing In 2007, pipeline imports from Canada are volumes of LNG are being produced outside expected to fall by about 5 bcm , with a the framework of long-term contracts similar rise in LNG imports to around 22 bcm, and these are being targeted primarily rising to 30 bcm in 2008. These increases at North American markets. Several new will be supplied from the signifi cant liquefaction projects are having price expansion in world LNG supplies from clauses written on a Henry Hub basis, as Nigeria, Trinidad and Tobago, Equatorial discussed in the LNG section. Guinea and from the Snøhvit project in Norway (Further details are provided in Infrastructure development the LNG section). Global LNG supplies is strong... are expected to be tight due to supply restraints, project delays and rapid growth In the United States, functioning markets in global demand. Nonetheless, importers and generally sound regulation are under- remain confi dent that North America will pinning infrastructure projects such as attract these volumes of LNG supplies, pipelines and storage in the lower 48 because: states.

Regasifi cation capacity will be more According to current Federal Energy than adequate as 12 terminals with Regulatory Commission (FERC) applica- 150 bcm of capacity will be in place by tions, gas pipeline projects to be started 2012. or completed in 2007 will extend over Strong development of infrastructure 2 000 miles and capitalize on the increased to move gas from LNG terminals to unconventional production in the Rocky markets has taken place (see below). Mountains. Large west to east natural gas pipelines continue to be planned, the North America has strong infrastructure largest (in 20 years) being the 1 323 mile to handle seasonal demand swings Rockies Express from Wyoming and (unlike some competing markets in Colorado to Ohio. The 20 bcm per year, Europe). USD 3 billion pipeline is expected to be Hence, the liquid North American mar- completed in 2009. The driver for this ket will be able to absorb large volumes pipeline has been the large persistent price at almost any time of the year. differential between Rocky Mountain and Mid West prices. The marginal cost of production is high in the United States and this is the The Kinder Morgan Midcontinent Express major factor setting Henry Hub prices Pipeline will carry 15 bcm per year 800 km and in turn the attractiveness of LNG Natural Gas Market Review 2007 • OECD Country/Region Update 185

from Oklahoma to Louisiana to interconnect In Canada, development of upstream gas to northeastern markets. Although it has storage capacity has also been pursued, not been approved yet, startup is predicted mainly in Alberta. TransCanada, a key for early 2009. player in the North American gas business in its capacity as the principal natural gas Expected growth in LNG imports will be shipper in Canada, currently owns 3.9 bcm backed by an improved network to move of storage capacity, composed of 1.4 bcm at regasifi ed gas from terminals to market: Edson (Alberta), completed in 2006, 1.4 bcm Energia Costa Azul Sempra LNG 72 km, at CrossAlta (Alberta) and approximately spur line due end 2007. 1 bcm with third parties. The CrossAlta storage facility completed a major ex- Elba Express (El Paso Corp.) in 2010, pansion in the autumn of 2005. The USD 850 million, 307 km 12 bcm per year. additional gas storage capacity will help Kinder Morgan Louisiana Pipeline, balance seasonal and short term supply 35 bcm per year of capacity from and demand and provide fl exibility to the Cheniere’s Sabine Pass LNG terminal supply of natural gas. USD 500 million. ... but some big pipelines Brunswick Pipeline (9 bcm per year) from Canaport LNG terminal near St John in are slow to develop Canada, to connect with Maritimes and In addition to increased LNG imports and a Northeast Pipeline system in Maine late rapid growth in unconventional production, 2008. the completion of an Alaskan natural gas Cameron Interstate Pipeline from pipeline now projected to be in service by Cameron LNG terminal to 7 inter- and 2018 will be an important component in intra-state pipelines to Midwest and meeting future North American gas demand. Northeast (2008). Alaskan production could provide as much as 60 bcm per year. Jordan Cove, 400 km, Jordan Cove LNG receiving terminal to Pacifi c Northwest system (currently in FERC pre-fi ling). Former Alaskan Governor Frank Murkowski in 2006 presented a 460-page draft contract At the beginning of 2007, there were 44 with Exxon Mobil, Conoco Phillips and BP to storage facilities operating in the Gulf the state legislature setting tax and other production area. According to FERC, 13 terms for a pipeline project they might storage projects (which will expand the build. That proposal failed after most state working gas capacity by a quarter) have lawmakers criticized it as providing too little been proposed or are under development revenue to the State. in the Gulf region. Six existing facilities are expanding current working gas capacity His successor, Governor Sarah Palin, has and deliverability. submitted natural gas pipeline legislation (Alaska Gasline Inducement Act) designed to address these concerns. If the legislature approves the bill, it would provide cash Natural Gas Market Review 2007 • OECD Country/Region Update 186

and other incentives to potential builders the start up date will be no “sooner than of a pipeline that would carry the North 2014”, about two years later than initially Slope’s vast reserves of natural gas to anticipated. Proponents of the project North American markets. Palin’s bill takes are Imperial, ConocoPhillips Canada, into account many of the criticisms that , Exxon Mobil Canada and arose during the debate on Murkowski’s the Aboriginal Group; the later formed proposal. Nonetheless, it seems unlikely in 2000 to enable ownership interest by the legislation will be passed in 2007 – the aboriginal peoples of the Northwest further delaying this project. Territories in the proposed pipeline.

A second large project is the Canadian Mexico struggles to meet demand Mackenzie Gas Project (MGP). To meet the projected increases in North American gas Facing stagnant gas production and a sharp demand, a consortium of large companies decline in its largest oil fi eld, Mexico’s new led by Imperial Oil proposed the MGP and President Calderon is struggling to fi nd a fi led applications for regulatory approvals way to open his country’s closed energy in October 2004. The MGP is a 1 200 km market to foreign investment. natural gas pipeline with an initial design capacity of 12 bcm per year, proposed Mexico is a major gas user (50 bcm in to be constructed from the Northwest 2005). Like the United States, Mexican gas Territories to the northern border of demand growth is driven by electricity Alberta, where it would connect to the generation, which accounts for around Alberta System. Throughout 2006, the 44% of gas use and now provides 36% of MGP proponents participated in public power needs. Electricity demand growth hearings convened by the National Energy is expected to remain strong. Since 1998 Board (NEB) and by a Joint Review Panel domestic gas production has been fl at. (JRP) constituted to assess socio-economic Accordingly, Mexico’s demand for natural and environmental aspects of the project. gas has outpaced the country’s production These latter hearings are expected to over the last decade and imports have conclude in the second quarter 2007, tripled between 2000 and 2005 to10 bcm. with the JRP’s report ultimately being submitted into the NEB review process. The state petroleum company PEMEX is constrained by a shortage of investment In March 2007, Imperial Oil fi led its funds, as well as institutional and ideo- updated cost and scheduled information logical concerns, that have led to laws to regulatory entities. Their submission and regulations that have blocked private shows a more than doubling in the total capital and participation. Lacking capital project cost to USD 13.9 billion including: and technology, PEMEX has been unable to USD 3.0 billion for the gas gathering expand reserves or exploit development system, USD 6.7 billion for the Mackenzie opportunities. The solutions appear to be Valley pipeline and USD 4.2 billion for increased imports from the United States the development of the anchor fi elds. and LNG. The regulatory fi lings also indicate that Natural Gas Market Review 2007 • OECD Country/Region Update 187

Newly elected President Calderon has Republic of Korea introduced partnerships that permit foreign investment but do not offer foreign Korea relies almost totally on LNG imports companies the right to own oil or gas for gas supplies. It consumed about resources. Pemex recently offered these 31 bcm of gas in 2005, up 8% from 2004. multiple service contracts (MSC), whereby LNG imports rose 10% in 2006. As can be the company can hire a private contractor seen from Figure 51, gas consumption has to conduct production activities in proven grown rapidly in recent years. The fi rst reserve areas, against cash payments. The LNG shipments arrived in 1986 and gas use success of the fi rst MSC bidding rounds has reached 5.6% of TPES by 1995, rising to been mixed, while the constitutionality of 12.5% of TPES in 2005. The largest use of this type of contracts has repeatedly come gas in Korea is for power generation (42% under attack. Yet they are one of the very in 2004) where it has now overtaken the few instruments that would allow the use of oil. The government has recently Mexican government to increase private stated its intent to increase the use of sector participation. nuclear generation in the power sector, which could, in future, lead to a decline in Opponents portray Calderon’s energy gas consumption. reform proposals as an excuse to privatize the energy sector, a strategy that plays on The average annual growth of gas use Mexicans’ fear of being sold out to foreign in the domestic sector was 30% in the interests. The former energy minister period 1990 to 2000 and gas has now will have a tough time convincing an virtually replaced coal in cooking and opposition-dominated Congress to enact heating, signifi cantly improving outdoor his much needed reforms. air quality in major urban areas, as well as indoors in all areas. Residential gas use In August 2006, the Altamira terminal on the now makes up the second-highest share country’s east coast (owned by Shell, Total of total gas consumption. With residential of France and Mitsui of Japan) accepted its gas use relatively mature, growth rates in fi rst delivery. The Costa Azul terminal on this sector are unlikely to be matched in Mexico’s west coast is under construction, the future. Indeed, growth has slowed in with a likely 2008 completion, intended to recent years, to 5.5% per year between supply some gas to Southern California, as 2000 and 2004. Owing to government well as meet local needs. Gas supplies are promotion and support, a relatively high likely to come from Indonesia and Russia. proportion of gas is used in the residential Chevron announced that it has given up a sector (31% in 2004) compared with other project to build an additional LNG facility IEA countries dependent on LNG), such as on the western coast of Mexico. The project Spain and Japan (both 12% in 2004). This would have involved an investment of places a strain on LNG supplies because USD 650 million. Chevron had earlier de- the majority of the gas is used for space cided to send natural gas from its Greater heating, which has a very seasonal usage Gorgon natural gas fi elds off northwest profi le. Australia to Japan. Natural Gas Market Review 2007 • OECD Country/Region Update 188

Figure 51 Korean gas consumption

bcm 31

29

27

25

23

21

19

17 2000 2001 2002 2003 2004 2005 2006

Source:IEA.

Table 29 Korea’s consumption of natural gas by sector, 1990 to 2004 Units: Mtoe 1990 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 Electricity generation 2 4.2 5.4 6.3 4.9 5.7 5.8 6.7 7.6 7.6 10.6 Share 75% 51% 50% 48% 40% 38% 35% 37% 37% 35% 42% Residential 0.5 2.7 3.6 4.4 4.5 5.8 6.2 6.4 7.9 8.5 7.7 consumption Share 17% 33% 34% 34% 37% 39% 37% 35% 38% 39% 31% Industrial 0.1 0.5 0.7 1.2 1.6 2.0 2.9 3.1 3.4 3.7 3.9 consumption Share 3% 7% 7% 9% 13% 14% 17% 17% 17% 17% 16% Other 0.1 0.8 1 1.1 1.1 1.4 1.8 2 1.8 1.8 2.8 Share 5% 10% 9% 9% 9% 10% 11% 11% 9% 8% 11% Total 2.7 8.2 10.7 13 12.2 14.9 16.7 18.2 20.7 21.6 25.1 Total (bcm)* 3 9.3 12.2 14.9 13.9 16.9 18.9 20.5 23.4 24.3 28.7 *Consumption values in bcm are calculated using a different methodology from values reported in Mtoe. .Sources: Energy Balances of OECD Countries, IEA/OECD Paris, 2006 and Energy Policies of Korea (IEA, 2007)

At 16%, total industrial demand for gas is recently decontrolled pricing in the oil low, while oil use in the sector is among sector. Price controls had in the past given the highest in the IEA. One of the reasons oil a competitive advantage over LNG, for this is that the government has only which is priced according to international Natural Gas Market Review 2007 • OECD Country/Region Update 189

Table 30 Korea’s LNG imports by source, 2001 to 2005 Units: 1 000 tonnes 2001 2002 2003 2004 2005 Qatar 4 942 31% 5 151 29% 5 838 30% 5 896 27% 6 228 28% Indonesia 4 028 25% 5 020 28% 5 137 26% 5 410 24% 5 565 25% Malaysia 2 253 14% 2 301 13% 2 808 14% 4 594 21% 4 708 21% Oman 3 928 24% 4 061 23% 4 810 25% 4 443 20% 4 335 19% Brunei 591 4% 769 4% 548 3% 899 4% 594 3% Others 422 3% 525 3% 293 2% 911 4% 874 4% Total 16 164 17 828 19 434 22 153 22 304 Source: Country submission. oil markets. Now that the reform of oil Most LNG imports into Korea are delivered pricing is almost complete, growth of according to long-term contracts, usually gas consumption in the industrial sector 20 to 25 years in duration. As has been between 2000 and 2004 has averaged standard until recently, long-term supply 7.4% per year and growth has continued of LNG to Korea is organised on a take- to be strong in 2005 and 2006. or-pay basis. All contracts are linked to international oil product prices, but Supply approximately one-third also apply an S-curve in the formula. These contracts Korea is the second-largest importer of were designed to insulate buyers from high LNG after Japan. In contrast to Japan, oil-driven gas prices but provide insurance almost all Korean LNG supply is imported to suppliers to cover the high investment by one company, Korea Gas Corporation costs of LNG infrastructure. Long-term (KOGAS), the state-owned monopoly, contracts have allowed Korea to ensure making it the largest commercial LNG security of supply through binding supply buyer in the world. agreements, but put the onus on Korea to secure downstream demand. In 1998, the Korea National Oil Corporation (KNOC) discovered the Donghae-1 gas fi eld Korea is more active in the spot LNG market in Korean waters which started production than its neighbour, Japan, largely because in July 2004. While signifi cant as the fi rst of Korea’s very seasonal demand for gas. source of domestic gas, the fi eld provides Korea buys spot gas in winter in addition less than 2% of annual gas consumption. to its take-or-pay commitments, which are suffi cient for gas demand in the summer. Because of its extremely high dependence on imported gas supply, Korea has Korea has been reviewing several major traditionally placed security of supply regions for upstream investment, including at the top of its policy agenda. KOGAS the Caspian and Russia. Recently these imports from Qatar, Indonesia, Malaysia, efforts have focused on major pipeline Oman, Brunei and others including supply sources in Russia – Kovykta gas in Australia, Egypt, the United Arab Emirates the Irkutsk region, Chavyanandgas in the (UAE) and Nigeria. Sakha Republic and the Sakhalin Islands gas Natural Gas Market Review 2007 • OECD Country/Region Update 190

Figure 52 Korea’s projected gas demand and contract cover, 2000 to 2015

45 40 35 30

Million tons LNG 25 20 15 10 5 0

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 IndonesiaMalaysia Qatar Oman Brunei Australia Yemen Russia Qatar (new contracts unconfirmed) Historical and Projected demand, 2004

Note: 2 contracts with Qatar were being finalised at the time of printing for a total volume of 42mtpa, starting in 2007 and 2009. Source:Country submission, industry information and KEEI demand forecasts

fi elds. Different options have been under demand compared to existing long-term review for over 20 years, but the Kovytka contracts indicates a growing supply gap, option seems to be forwarded. The pipeline as shown in Figure 52. Projections indicate route would transport gas via China, from that the shortfall may be as much as 10.9 where it would be transported across the bcm per year (8 mtpa) by 2010; in addition, Yellow Sea, supplying an expected 10 bcm 1.4 bcm per year (1 mtpa) of existing LNG per year to Korea. China National Petroleum contracts that will have to be renewed by Corporation (CNPC) and Russia’s Gazprom that time. signed a memorandum of understanding in March 2006 outlining the route, volumes In addition to reduced long-term and possible timetables for three possible contracting, events in Indonesia have also pipelines (West Siberia and Sakhalin could added to concerns about future security of be the other sources of gas). However, no supply. Recently, there have been problems fi rm plans have been made. In the meantime, with LNG exports from Indonesia, as LNG will continue to supply nearly all of discussed earlier. Indonesia accounts Korea’s gas needs. In recent years, KOGAS, for 25% of supply to Korea and a similar the state-owned gas company, has changed proportion of supply to Japan, leaving its policy of signing long-term take-or-pay the two largest LNG importers in the deals to a more fl exible policy that relies world looking to back up their Indonesian increasingly on shorter-term contracts and supply commitments with supply from spot purchases. As a result, projected gas other sources. This situation has also put Natural Gas Market Review 2007 • OECD Country/Region Update 191

pressure on the global LNG market at a Expanding infrastructure time when Korean demand is increasing and old LNG contracts will soon be coming Korea’s gas infrastructure is constantly up for renewal. Kogas is trying to secure expanding to accommodate the rapid two long-term supply deals from Qatar at increase in demand. Korea has four the end of 2006, totalling 5.7 bcm per year LNG import terminals, three owned by (4.2 mtpa). The fi rst one started delivery in KOGAS and one by POSCO, a large steel 2007 and the other is expected to start in manufacturer. Total import capacity is 2009. These would be the fi rst long-term 82 bcm. The gas trunk-line network deals after the company’s virtual monopoly provides gas to 75 cities and regions. The on LNG imports was re-instated in summer proportion of the population with access to 2006. a grid connection is 69%. Grid connection continues to expand, but slowly.

Figure 53 Korea’s gas transport network

Gas pipeline Gas pipeline planned or under const. NORTH KOREA LNG import terminal

Chunchon Ilsan Namyangju Seoul Heongsong Ildo Yoju Youngjong Island

Inchon Yongin Siwha Pyeong Taek Chonan Asan Sosan Chongju

Yusong REPUBLIC OF KOREA Jungchon Pohang Boryong Taechon Kimchon

Yunsan Kwanum

Kunsan Ulsan Chongju

Kimhae Masan Gwangju Sunchon Pusan

Hanam Tong Yeong Yosu

Mokpo Gwangyang 0Miles 100 0Km 100 The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source: Energy Policies of Korea (IEA, 2007). Natural Gas Market Review 2007 • OECD Country/Region Update 192

Figure 54 Korea’s natural gas industry structure

Ministry of Commerce, Policy Governors of cities Industry & Energy co-operation & provinces (MOCIE) - Wholesale rate approval - Retail rate approval - Administrative guidance - Administrative guidance & supervision & supervision Wholesale Retail Gas supply KOGAS City gas companies

Gas supply Gas supply

For power Large-scale customers generation etc. General customers

Source: Country submission.

Industry organisation and policy provinces. Each of the 33 city gas companies has an exclusive supplier’s licence for its Korea’s domestic gas sector came into region and is therefore a geographically being in 1983 as a result of government defi ned monopoly. There are seven city efforts to promote diversifi cation away gas companies operating in the Seoul from coal and oil in the domestic sectors. metropolitan area with approximately Korea’s natural gas business was classifi ed seven million customers between them. into a wholesale sector and a retail sector through the Korea Gas Corporation Act KOGAS and the various ministries have and the City Gas Business Act. At this time, overseen the successful development of the government set up KOGAS as a state- the gas industry in Korea from 1983 to owned company to control all aspects of 1999. The gas industry was developed with the wholesale natural gas industry. a strong focus on security of supply. The annual gas consumption growth rate from Under the terms of the Korea Gas 1990 to 2000 was 20%, refl ecting strong Corporation Act, the Ministry of Commerce, policy measures in support of diversifi cation Industry and Energy (MOCIE) provides away from oil. This was achieved at a cost, administrative guidance and supervision as Korean gas prices are among the highest for KOGAS. In turn, the company is granted in the IEA, in large part because the country a monopoly to import, store and distribute relies almost entirely on imported LNG. gas through main trunk lines in Korea. Towards the end of the 1990s, government Both the city gas companies and power policy regarding natural gas shifted from companies buy gas directly from KOGAS. its overwhelming focus on energy security The city gas companies are overseen on the towards encouraging better economic municipal level by governors of cities and effi ciency. Natural Gas Market Review 2007 • OECD Country/Region Update 193

Restructuring and liberalisation a new plan is currently being prepared, no plan has been released nor is there a date The Basic Plan for Restructuring the Gas for when the new plan is to be released. Industry was announced in November 1999 At the end of 2004, the government had with the aim of enhancing competition in a 26% equity stake in KOGAS. The other the gas sector. The plan was submitted to major owners were KEPCO (24.5%) local the national assembly at the end of 2001 governments (9.9%) and private investors and foresaw the splitting of KOGAS into (38.8%). KOGAS is listed on the Seoul and three subsidiaries, two of which were then New York stock exchanges. to be sold. The law recognised KOGAS as a monopoly that should be exposed Despite the lack of an industry-wide to competition. As a means to reduce restructuring plan, there have been its market share to spur gas market changes to the industry that open it competition, KOGAS was prohibited from up to players other than KOGAS. Some signing more long-term contracts so that companies are able to negotiate in order other companies could enter the market. to import gas directly if it is for the In addition, the plan stipulated that open company’s “own use”. In 2005, the Korean access would be implemented on LNG steel company Posco completed an LNG receiving terminals and pipelines. The retail receiving terminal at Gwangyang in the sector currently comprises many regional southern part of the country. Together or local monopolies that are not able to with K Power, a joint venture between SK operate outside their geographic area and and BP, Posco has contracted to import compete with each other; competition 1.6 bcm per year of LNG. In the fi rst deal of was also to have been introduced in stages its kind, Posco has negotiated third-party to the retail market after the wholesale access rights to the KOGAS high-pressure sector had been liberalised. The partial system from Gwangyang to Pohang. privatisation of KOGAS before separating A further large industrial group, GS, is it into different private entities led to an currently expanding its gas-fi red power initial public offering of 43% of its equity generation facilities and has also secured that was completed in November 1999. a licence to import LNG. The original liberalisation plan included the establishment of a regulatory commission Demand outlook specifi cally for the gas industry. Currently, the Fair Trade Commission (FTC) handles Gas use is expected to grow by more than general business oversight, but there is no 60% between 2006 and 2020. The city gas gas industry regulator. sector (including industrial, commercial and residential sectors) is expected to Since 1999, the original reform plan provide the bulk of the signifi cant growth has been postponed indefi nitely. The in gas demand over the period to 2010 and decision not to proceed with reform beyond. The government forecasts that partly stems from California’s experience with the planned growth of nuclear power, with liberalisation of its energy sector the share of gas used in power generation and the subsequent blackouts. Although will decline. Within the city gas sector, Natural Gas Market Review 2007 • OECD Country/Region Update 194

Table 31 Korea’s annual natural gas demand outlook, 2006 to 2020 Average annual growth rate 2006 2007 2011 2015 2020 2006-2020 2006-2011 2006-2015 Power 14.4 16.6 18.8 13.9 14.4 0.01% 5.50% -0.40% Share 42% 44% 42% 30% 26% City gas 19.4 20.8 26 31.7 40.5 5.40% 6.00% 5.60% Share 58% 56% 58% 70% 74% Total 33.8 37.4 44.8 45.6 54.9 3.50% 5.80% 3.40% Source: MOCIE Eighth Long-Term Natural Gas Supply/Demand Plan.

industrial consumption is expected to Where this information is available, e.g. grow faster than the sector as a whole. from Norway, we can see that – despite As industrial demand volumes are much high prices – only around half of Germany’s more stable throughout the year than current import capacity from Norway residential demand, this will help temper appears to be actually used (IEA, 2006). seasonality. Nevertheless, the forecast reduction in market share of gas used for Nord Stream, a direct pipeline under the power generation is likely to, on balance, Baltic Sea between Russia and Germany, increase the seasonality of the country’s is slated to come on line in 2011 with an gas usage. additional 27.5 bcm of capacity. According to the partners, this USD 11 billion project is intended to enhance the security of Germany German gas supply by bypassing transit states. Supply Most imports to Germany are made as part Germany provides approximately 18% of of long-term gas supply contracts that supply from domestic production, almost are pegged to the price of oil products. 20 bcm per year. Domestic production Information on the physical fl ows is sketchy has declined from a peak of 22.3 bcm as there are many physical swaps between in 2003. Russia accounts for 42% of locations so that the gas does not always imports with the balance divided between fl ow physically along the contractual path. Norway (29%), the Netherlands (24%) with Denmark and the United Kingdom Demand supplying small volumes. Germany is the largest gas market in Unlike the other large gas-importing continental Europe. Indicative 2006 data countries in Europe, such as Italy, Spain, suggest that it has surpassed the United France, the United Kingdom and Turkey, Kingdom as the largest in the European extremely limited information is publicly Union. Size and a fair level of diversity in its available concerning daily gas fl ows and supply should act to strengthen Germany’s import capacity utilisation in Germany. energy security, but the presence of dif- Natural Gas Market Review 2007 • OECD Country/Region Update 195

ferent networks operating gas qualities the future gap between power supply and could be seen as dividing Germany into more power demand will be fi lled by the “default vulnerable zones. option” – an increase in natural gas. Gas- fi red generation is expected to increase Natural gas accounted for about 23% of from 65 TWh to 150 TWh between 2005 total primary energy supply (TPES) in 2005. and 2020. Consumption totalled 90.0 bcm in 2003 and about 91.7 bcm a year in 2004 and As in other IEA countries, power grid 2005. The largest share of consumption is load is likely to grow more volatile as in the residential sector, which comprises demand patterns change and intermittent 47% of the market while the industrial generation increases. This will require sector accounts for 18%. the presence of a large idle capacity of variable, reliable backup generation – in Because of the high residential use, the absence of hydroelectric generation, German gas consumption is highly this role will be fi lled by natural gas. dependent on the weather – demand in January 2006 was 2.7 times that of August Market structure 2005. Seasonality is managed through gas storage as well as supply fl exibility (see The structure of the German gas industry is “Security” section for a discussion of gas relatively complicated because the system fl exibility). Currently, Germany has gas was conceived as a marketing network storage capacity equivalent to about 80 to aggregate demand in Germany for the days of Germany’s average demand. development of large import projects. The marketing operation was historically Demand outlook organised as a series of regional monopolies with pyramidal demand structure – many Residential gas demand per capita is small consumers served by fewer larger expected to fall starting in 2010 for the next ones. two decades as the energy effi ciency of buildings improves. Some 22% of total gas At the top of the pyramid are the three key consumption is used to generate electricity players, who own and operate the regional and new gas-fi red power stations are trunk pipelines essential for import/export planned in a number of locations. Germany competition in the German gas market. must legally shut down its remaining The pipelines are owned by E.ON (which nuclear power stations. The government controls 55% of the German market by priorities for a low-carbon future also volume) Verbundnetz Gas (VNG, 10%) and signal a shift away from coal- and the few Wingas (11%). The other major player in remaining oil-fi red power generation. the German gas industry is RWE (10%). Only E.ON and Wingas are able to compete Nuclear will be phased out in Germany across the country although even then not through legal action and coal investment necessarily in all geographic regions. may be challenged by either policy action or policy inaction. In such an environment, Natural Gas Market Review 2007 • OECD Country/Region Update 196

Table 32 German domestic trunk pipelines Capacity Name (bcm per From To Start Owner Share year) MEGAL 22 Czech Republic France 1980 E.ON Ruhrgas 50% Gaz de France 43% OMV 5% Stichting Megal 2.0% TENP 7 Netherlands Italy 1974 E.ON Ruhrgas 51% Snam Rete International 49% North Sea Ludwigshaven MIDAL 12.8 1993 Wingas 100% (Emden) (near Switzerland) STEGAL 9.8 Czech Republic Germany (MIDAL, JAGAL) 1992 Wingas 100% 16.6 total Connection to Connection to MIDAL 2006 Wingas 100% (loop) JAGAL North Sea NETRA 21.4 Wilhelmshaven 1995 E.ON Ruhrgas 41.7% (Dornum) BEB 29.6% Statoil 21.5% Hydro 7.2% JAGAL I 23.7 Poland (Oder) Brandenburg 1996/7 Wingas 100.0% JAGAL II 23.7 JAGAL I STEGAL 1999 Wingas 100.0% RGH 3.0 MIDAL Hamburg 1994 Wingas 40% E.ON 60%

Sources: Company websites, country submission.

The price of third party access to these Gas hubs and transparency pipelines in the future may determine the success of the competitive gas market The government issued two pieces of in Germany (see Table 32). The degree of legislation in the summer of 2005 based price regulation of these pipelines is not on the new Energy Industry Act with the yet established, pending a decision by the primary focus on network regulation regulator concerning the degree to which and unbundling of operations into some pipelines might compete with each separate legal entities. One, the GasNZV, other, therefore perhaps not constituting is intended to ensure transparent and a monopoly (perhaps a duopoly). Until this non-discriminatory access to the pipeline decision is taken, trunk pipelines are not network (where applicable). The second, subject to regulated third party access GasNEV, lays down a binding computation tariffs. method (where applicable) for the transit fees for which approval must be obtained. Natural Gas Market Review 2007 • OECD Country/Region Update 197

The BEB hub in the North West of the Important developments country is the only hub in Germany with towards competition any signifi cant liquidity. Co-incidentally, BEB is the only pipeline network not The development of a secondary market has majority owned by only one holding been stifl ed due to the types of contracts company with a gas trading subsidiary. being signed between suppliers and consumers. However, the regulator ruled Several hubs have been founded in the in April 2006 that contracts which locked past with limited success. For example, companies into buying all their gas from the Eurohub in Bunde operated for several one supplier for long periods of time were years with minimal trading volumes and anti-competitive. Further to the ruling, then failed due to a lack of liquidity. Too suppliers cannot sign two-year contracts if few players were able to get access to the they cover more than 80% of total annual pipeline system so there was insuffi cient volume and four-year contracts if they demand for hub services. cover more than 50%. This was probably the most important ruling in the past Recently, E.ON has launched a “choice ten years of gas market “liberalisation” in market” in northern Germany and also Germany. seems to be taking measures to increase the liquidity on its other transportation Germany is one of the few countries network subsidiary by combining the reviewed in this section on IEA country many balancing zones into a few. gas markets where the ownership and operation of regional pipeline systems by Liquid trading hubs can rarely develop if the major gas marketers is allowed. Gas all counterparties have to trade with the companies currently own and operate the incumbent (as in the case of the choice pipeline systems needed to transport gas market). As expected, few new players from the point of purchase to the point of have so far proved willing to trade on this sale to fulfi l the contracts. Experience from market when compared with the BEB hub. other IEA countries suggests that this is Commercially, it makes little sense to buy likely to be a major factor in preventing from the E.ON holding company in order liquid markets from developing. It is clear to use its own grid to compete for market that if a trading company and the network share to serve its customers. manager are owned by the same fi nancial entity this will create fi nancial incentives At the same time as appearing to make for favourable access conditions for the considerable concessions to the cause of group company. promoting a liquid gas market in Germany, E.ON also introduced a “price promise” In compliance with the new Energy Industry whereby the company will undercut all Act, which requires legal and management competitors in Germany. unbundling, the major gas utilities have each established separate legal entities to operate the transmission systems. The regional and local distribution networks are run by Natural Gas Market Review 2007 • OECD Country/Region Update 198

spin-offs of regional and local distributors, point in Germany to the burner tip. Under except where these networks supply fewer this model, there is little incentive or than 100 000 customers. The competition need to share information outside of authority, the Bundeskartellamt and the the value chain. This is to be compared Bundesnetzagentur (BNetzA) are responsible with a competitive market in which the for ensuring that these companies operate independent network operator has a clear independently from their parent supply incentive to advertise its services. companies. Both entities can investigate and force action on their own or when another Regulation company fi les suit. Regulation is carried out at the federal After fi ghting what some observers have level by the BNetzA, the former Regulatory called a “legal rearguard action” the Authority of Telecommunications and German incumbent companies use of the Post (RegTP), an agency subordinate to “single contract” model was ruled illegal by the BMWi. Regulation of entities entirely the regulator in late 2006. Trading within operating within a single Land (or province) entry-exit zones (or balancing zones) is is done by regulatory agencies in that now the only legally accepted method of Land, except where it has conferred these gas trade. Supplier switching under the powers on the BNetzA. new two-contract model will be facilitated by an arrangement under which capacity The BNetzA has powers to ensure non- reserved with one supplier is automatically discriminatory grid access ex post and to transferred to another with the gas supply approve ex ante transit fees. Under the contract – this will emulate the “rucksack EnWG, it has power to monitor abuses, i.e. principle” trialled in Austria. to forbid grid operators from engaging in practices that constitute an abuse of Customer switching their market position. Recent rulings by the regulator have seen transportation The rate of customer switching is low in charges reduced by up to 18% in some Germany – 302 customers switched supplier networks which should be one factor in 2005. The regulator is currently working which could improve competition. on standardising the process to a uniform automated process across Germany. Lower Regulatory coverage is still patchy, with switching levels are synonymous with lower all-important trunk-lines excluded from transparency and competitive pressure than the price regulation system pending a in markets such as the United Kingdom which decision by the regulator, as noted earlier. enjoys the highest customer switching rates in Europe. The efforts to standardise Gas quality and automate customer switching should improve transparency. There are several separate networks in Germany which for historical reasons The German system is designed for each carry different gas qualities. This marketing gas vertically from the import effectively sub-divides the country into Natural Gas Market Review 2007 • OECD Country/Region Update 199

Figure 55 German gas transport network

Copenhagen Malmö Trelleborg Ystad DENMARK

EUROPIPE BGI DEUDAN

NORPIPE (40) Kiel NORD STREAM Wilhelmshaven Rostock (36) Lübeck Greifswald Dornum (12) Hamburg

(10)

Emden Szczecin RHG (24) (42 or 56) (32) NETRA Bremen NETRA Schwedt

(4 (16) 8) (44) Lingen (20) Berlin Amsterdam (24) (20) Frankfurt/Oder NETHERLANDS Hannover (2 M POLAND 4 ID ) (36) A (36) L JAGAL Werne WEDAL (36) Düsseldorf GERMANY Leipzig Görlitz R Köln (48) TR Erfurt EVG STEGAL Aachen Bonn (40) Sayda (36) (40) (32) (38) BELGIUM TENP (36) Schlüchtern

LUX. Würzburg Lux. City (40) MEGA L Waidhaus (20) (28) CZECH REPUBLIC (48) (44) TRANSGAS I & II Nürnburg Karlsruhe (20) (32)

SEL (36) FRANCE (24) (48) Stuttgart (36) Wildenranna WAG (1 2 ) (12) AUSTRIA Munich

Gas pipeline Gas pipeline planned or under const. Major gas processing plant Zürich Underground gas storage Underground gas storage planned Bern AUSTRIA (24) Pipeline diameter (inches) LIECH. 0 Miles 100 Gas import route SWITZERLAND 0Km 100 LNG terminal planned The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

Source:The Petroleum Economist Ltd.. Natural Gas Market Review 2007 • OECD Country/Region Update 200

regions, reducing Germany’s security of gas of 28 bcm per year, but it is foreseen that supply when compared with one national this will be doubled by looping the line. gas market. E.ON Ruhrgas has owned a site on For the same historical reasons that which it could build an LNG terminal at underpinned the development of the gas Wilhelmshaven since the late 1970’s when sector, regional gas systems are operated its negotiations to import North African with the quality of gas determined by the gas to Germany via LNG were dropped. source – Norwegian gas having a higher calorifi c value than Russian which is in The Yamal Europe pipeline has a capacity turn higher than Dutch low-quality gas. to bring approximately 30 bcm per year of The three gas qualities are distinct so Russian gas from western Siberia through individual gas networks only carry one of Belarus and Poland, but most Russian the three. gas arrives in Germany through the Brotherhood and Transgas systems, which Practical solutions exist; for instance it is link western Siberian gas production to generally accepted that the two higher western European nations via transit quality specifi cations of gas, Norwegian through Ukraine. and Russian, could be mixed and carried in the same networks. Furthermore, quality Information on physical fl ows is not conversion facilities could be installed available by pipeline, so policy makers have at points where different gas-quality to resort to studying contractual paths to networks intersect, thus creating a single determine source and destination of gas market for gas. fl ows. However, the presence of several large swap arrangements between buyers Import infrastructure means that the gas does not follow the original route of the contracts. This makes Each of the existing offshore import it very diffi cult to predict the likely fl ows pipeline systems is owned by a different of gas in a supply emergency (see separate consortium of private companies, usually section on Security). representing the initial producer and fi nal consumer companies. The pipelines have Storage a total combined capacity of 54 bcm per year, but only 25 bcm passed through them Germany has the world’s fourth-largest in 2004 despite historically high prices. gas storage capacity following the United States, Russia and Ukraine. There are 43 A new pipeline project, Nord Stream, natural gas storage facilities with a total is planned to carry gas from Vyborg in capacity of 32.58 bcm and a total working Russia to Greifswald on the German Baltic gas capacity of 20 bcm, or about 80 days of coast. Construction of the approximately Germany’s average demand. The majority 1 200 km under-sea pipeline is set to com- of storage facilities are operated by major mence in 2008. The fi rst phase of Nord gas utilities such as E.ON Ruhrgas, Wingas, Stream is planned to have an initial capacity VNG and RWE, as well as by independent Natural Gas Market Review 2007 • OECD Country/Region Update 201

Table 33 New German storage capacity (planned or under construction) Units: mcm Existing storage Expansions Total storage Salt cavern storage 6 703 3 648 10 351 Operational 6 703 620 7 323 Planned/under construction 0 3 028 3 028 Depleted field storage 12 365 800 13 165 Operational 12 365 670 13 035 Planned/under construction 0 130 130 Total 19 068 4 448 23 516 Operational 19 068 1 290 20 358 Planned/under construction 0 3 158 3 158 Source: Energy Policies of Germany (IEA, 2007). facility operators and regional and Trading municipal utilities. Most storage facility operators have signed an agreement Gas trading in Germany has not enjoyed to offer capacity on GGPSSO terms,18 the relative success seen in neighbouring although this is a voluntary agreement Belgium or the Netherlands – currently rather than a binding commitment. less than 1% of domestic consumption is actively traded on gas hubs, with the In the North of Germany, geological majority on only one virtual point, BEB. conditions are favourable for the addition The major reason for the lack of activity is of further subterranean storage facilities. that Germany opted for negotiated third- In the south, geological sites are much party access to its networks after the more scarce, so new storage for German fi rst European gas directive, which made consumers is being constructed in Austria it diffi cult to obtain fi rm transportation – tied only to the German grid. Fifteen rights over a signifi cant distance or salt cavern storage facilities are currently time, therefore stifl ing competition. The planned or under construction, with a new regulated third-party access being capacity of 3.02 bcm. Capacity at existing implemented should signifi cantly improve salt cavern facilities is to expand by trading and liquidity. 620 mcm. One new depleted fi eld storage facility is being developed, adding 130 mcm Short-term capacity from time to time of capacity, with capacity at existing fi elds becomes available and is offered to the set to expand by 670 mcm. market, often on an interruptible basis. Interruptible capacity is not suffi cient for a new entrant because new entrants require fi rm capacity to build a business

18. ERGEG, Guidelines for Good TPA Practice for Storage System Operators (GGPSSO), 23 March 2005. Natural Gas Market Review 2007 • OECD Country/Region Update 202

as a dependable supplier and because IEA countries. New large-scale investment balancing services are provided by the in Germany is driven by the large incum- main players at high rates compared with bent companies because new entrants liquid markets in the United Kingdom. cannot get guaranteed access to long- Suppliers who gain customers should term existing or future capacity. inherit capacity through the “rucksack” principle. It will be interesting to see how For example: The Stegal, Wedal, Megal well this principal works in practice. and TENP pipelines are currently being expanded by their respective owners; there The limited trading that has taken place was no “open season” for these projects, has to some extent been around asset as is standard practice in contestable ownership brought about by large-scale markets. The lack of open season was physical swaps between the major players certainly an opportunity missed by the and the annual release programmes German policy makers to introduce some conducted by E.ON as a condition for its competition on those routes. Open season takeover of Ruhrgas. A lack of guaranteed processes are required in contestable associated transport capacity, however, markets to allow third party ownership of meant that the fi rst release programmes individual routes. were under-subscribed and they were regarded by the market as unsuccessful. A regulated open season process requires an independent network company to Traders have generally found it much easier obtain fi nancial commitments from to transport gas from release programmes multiple independent parties on an open through the Netherlands to liquid hubs in access basis. Although important pre- the United Kingdom, Belgium and France qualifi cation conditions must be met, the than to get access to capacity inside pipeline company then determines the Germany. Nevertheless, some traders have need for pipeline expansion by allowing managed to purchase long-term capacity all qualifi ed parties to bid for future on the TENP system in the past in order ownership of capacity. After the level of to transit gas from the Belgian hub at interest is determined and contracts for Zeebrugge down through Germany and future capacity are signed, only then does Switzerland to Italy. design and construction commence to the specifi cations of the market. Investment Many pipelines in the United States have German gas companies have maintained been built according to the “open season” their commitment to the new versions principle, as was the “Interconnector” of the old gas model and enhance their between the United Kingdom and Belgium. pipeline system infrastructure when they In the case of the Interconnector, this has see fi t. There is no system of auctioning resulted in primary capacity ownership by unused capacity as in liquid gas markets in the following companies,19 many of whom

19. Source: www.interconnector.com Natural Gas Market Review 2007 • OECD Country/Region Update 203

were not previously present in the United example, in a small number of cases, the Kingdom or Belgian markets: BG (UK), BP price is linked to coal prices. (UK), Centrica (UK), ConocoPhillips (US), Distrigas (Belgium), EDF (France), E.On Domestic tariffs are linked to the price (Germany), Total (France), ENI (Italy), Essent of heating oil and re-set every quarter. (Netherlands), Gas de France (France), RWE This type of pricing ensures volume (Germany), Hydro (Norway), Gazprom off-take, helping achieve stable market (Russia), Statoil (Norway). share compared to oil. Though gas now has a substantial market share, this As mentioned earlier, the lack of open pricing methodology, which eliminates season on domestic and international any interaction between gas supply pipelines means that the only way that and demand and the price, has not been new entrants can obtain uninterruptible, changed by suppliers. This is perhaps the long-term capacity on a domestic German clearest signal that there is a lack of gas- network is to build their own network to-gas competition in Germany. – an approach pioneered by Wingas in the 1990’s. Clearly, for most new entrants, this Due to the “market value” principal, is clearly impracticable and represents a the consumer in Germany will pay the substantial barrier to entry. same price for gas as for oil products irrespective of the cost of producing and Pricing transporting gas. Therefore, reducing the transportation cost on high pressure grids In 2006, the un-weighted average whole- is likely to result in either the producer sale prices in major IEA gas markets were getting more netback revenue, or the USD 6.57/MBtu at Henry Hub in the United transportation provider increasing the States, USD 7.08/MBtu for LNG purchased costs somewhere else in the value chain. in Japan, USD 7.36/MBtu at NBP in the United Kingdom and USD 8.31/MBtu at A class-action lawsuit by a number of the German border. northern German consumers against the rising tariffs of a northern German sub- Gas pricing in Germany is based on the sidiary of gas major E.ON led the company “market value” principle that the customer to publish its gas price calculations in should pay no more or less than the cost November 2005. Germany’s second-largest of the competing fuel, which is either gas gas company, RWE and a number of municipal oil or fuel oil. Thus the prices for gas are suppliers have followed suit, publishing a directly linked to oil, though there is a detailed breakdown of their tariffs. time lag for gas prices to change following moves in oil prices. Natural gas prices to The IEA recently conducted an in depth industrial consumers in Germany are set on energy policy review of Germany and a quarterly basis relative to the average of made a number of observations. In particu- the previous six or nine months of prices lar, the IEA considers that Germany needs for fuel oil and gas oil. Other elements to press ahead with market reform and can be refl ected as well, instead of oil. For interconnection of the German gas Natural Gas Market Review 2007 • OECD Country/Region Update 204

markets with the rest of Europe. This will by 2020. Information on gas fl ows is enhance supply security and diversity for available by entry or exit point with a German regions and the rest of Europe, 12 minute delay; this is seen as very such as through broader access to existing important so that the market can make European LNG terminals. Germany will informed investment decisions. also need to monitor the increasing concentration of external gas suppliers From 1990 to 2000, production more than and encourage new gas sources to enter doubled, reaching its peak in 2000. Since the German market, e.g. by greater 2000 however, production has fallen by investment in new infrastructure including nearly 30% to 83 bcm in 2006. In 2004, LNG import terminals in Germany based on the United Kingdom became a net gas “open season” principles. On regulation, importer. The decrease in production the network regulator and competition from the United Kingdom’s Continental authority will need more resources to Shelf (UKCS) occurred more rapidly than ensure effective commercial third party expected. When compared with the access and to unbundle networks to the similarly fast decline seen in the United extent required. It also seems clear that States offshore Gulf of Mexico region, this the number of balancing zones should be perhaps identifi es an important new trend reduced, ultimately to one, with a single in offshore gas production. There have independent system operator. Greater been some substantial new discoveries transparency is required, for example, recently and exploration continues, but pipeline operators need to provide entry offshore production is expected to decline and exit information on a timely public steadily over time (the United Kingdom has basis. Further details are provided in the produced about 65% of its total possible gas upcoming publication of the In-Depth reserves), so that with forecast increased Review, planned for later in 2007. demand, imports will continue to grow, to more than 50% of demand by 2010.

United Kingdom Supply

In 2005, natural gas accounted for 37% of Government policy strives to maximise total primary energy supply, a rapid rise economic production from domestic from 22% in 1990. The government projects reserves. The addition of two new types that the gas share in total primary energy of licence has been central to maintaining will rise slightly, reaching 39% in 2020. In interest and investment. Reaction to these 2004, gas-fi red power plants generated changes has been positive: in 2005 the 41% of the United Kingdom’s electricity. highest number of licences was awarded in This fi gure has seen tremendous growth the United Kingdom’s North Sea history. in the past fi fteen years from virtually zero, with the introduction of increased The United Kingdom has imported gas North Sea gas production and CCGT plant from Norway via the Frigg system for technology. Gas to power is expected to over a decade, while LNG imports were grow further, to 60% of power generated fi rst received in the summer of 2005 at Natural Gas Market Review 2007 • OECD Country/Region Update 205

Figure 56 United Kingdom gas production and gross imports

120

bcm 115

110

105

100

95

90

85

80

75 2000 2001 2002 2003 2004 2005 2006 Production Imports

Source: IEA data.

Isle of Grain. LNG import capacity is being Demand expanded fast, with a new project at Teesside added only months ago as well The United Kingdom has a highly as others planned (see below). In keeping competitive downstream gas market. with increased net import demand, several Although Centrica (the downstream import infrastructure projects were business inherited from the former completed as planned, just before winter monopoly) is still the largest retail gas 2006/07. These are the Langeled pipelines company, it has recently lost market share from Norway to Easington (25 bcm per due to high levels of customer switching year, of which the southern leg from the (see section on Recent Events). Liberalisation Sleipner fi eld came on stream on 1 October and the introduction of competition have 2006), the upgrade of the Belgium Inter- shifted a great deal of gas supply activity connector (from 16.5 to 23.5 bcm per year, from the public sector to the private sector. completed on 1 October 2006) and the The liberalisation process is generally BBL pipeline linking the United Kingdom regarded as successful: there have been no market with the Netherlands (15 bcm per major energy disruptions, more services year, operational on 1 December 2006). This are being offered and prices went down. In new import capacity together will offer an 2004, retail ex tax gas prices for households additional import capacity of 131 mcm were 14% below the IEA average, while per day, almost half the United Kingdom’s retail ex tax prices for industry were 25% consumption, (see also LNG, below). below the average. Natural Gas Market Review 2007 • OECD Country/Region Update 206

In 2004 the falling United Kingdom gas price per month. Increasing fl exibility could trend reversed itself, partly because import be derived from ship-to-ship transfers of and storage did not appear to keep pace LNG. Scapa Flow, which is located within with the decline of domestic production. the Orkney Islands, off the northeast coast Gas prices paid by non-residential customers of , is seen as a good location for almost doubled in the period between the the operations. fi rst quarter of 2004 and the fourth quarter of 2005. For residential customers, the Several additional import-related invest- retail price of gas rose by 33% from the ments are either planned or taking place fi rst quarter of 2004 to the fi rst quarter which should be operational by 2010. In of 2006. This has since proven to be a brief Milford Haven two LNG terminals are under spike rather than a trend – prices for winter construction to be operational in 2007/08: 2006/07 gas in the United Kingdom have one of 6 bcm per year (the Dragon LNG been approximately half the level of prices project, by Petroplus/BG/Petronas) and in the oil indexed continental European one of 10.6 bcm per year (phase 1 South markets, largely due to completion of new Hook LNG, Qatar Petroleum/ExxonMobil/ import infrastructure. Total).

LNG Midstream and gas quality

The Isle of Grain terminal is fully contracted Substantial investment is being planned for 20 years between terminal operator to upgrade the high-pressure gas pipeline National Grid and BP/Sonatrach (as one network. Ofgem noted that gas networks shipper). National Grid is starting a phase face “huge challenges” over the next fi ve 2 expansion with an additional 9 bcm; years to respond to changes in the sources capacity is under 20-year contracts by of gas, primarily higher volumes from LNG Sonatrach, Centrica and Gaz de France. For imports and a further increase in gas use both phases an open season process was for power. employed. An additional phase 3 could be available ahead of winter 2010/11; a third While Norway is solely a gas exporter open season has been held, which closed to the United Kingdom, Belgium both on 18 January 2006. This third tranche is imports and exports gas via the sub-sea subject to appropriate market interest, Interconnector (IUK) depending on the obtaining the necessary permissions for relative market conditions in the United further site development and regulatory Kingdom and on the continent (discussed consents. in Recent Developments).

The Excelerate dockside LNG terminal for On 29 December 2005 the government regasifi cation vessels at Teesside (4 bcm published its proposal to retain the current per year) started operations in February United Kingdom gas quality specifi cations, 2007. It is particularly noteworthy for which are different from those being its very short lead time of only one year. recommended for continental Europe The facility can take up to four cargoes through the EASEE-gas proposals. The Natural Gas Market Review 2007 • OECD Country/Region Update 207

fi nancial costs of blending or processing by the regulations governing gas quality plus producers or other parties in the market redesigning and replacing gas appliances. to meet the existing United Kingdom Ofgem chaired a gas quality workshop on specifi cations are lower than changing 13 September 2006 to assess whether gas

Figure 57 United Kingdom gas transport network

Gas pipeline Gas pipeline planned or under const. Major gas processing plant R Underground gas storage Sullom Voe GNUS EO Underground gas storage planned MA Shetland Is. (24) Pipeline diameter (inches) LNG import terminal LNG import terminal planned (36) 2) 0Miles 100 200 FLAGS (3 G IG 0Km 200 300 FR (32)

(30) SAGE (30) St. Fergus (27) F ULMAR SCOTLAND (20) Aberdeen (36) ) 2 (4 UNITED Edinburgh KINGDOM (24) N. IRELAND Moffat SNIP (24) ) (36) (44) (30 (34) CATS Belfast 6) SEAL

(3 IC1 (24) (36) IC2 (30) (42) LANGELED Teesside Barrow

Manchester

IRELAND Dublin A (42) B PointofAyr Theddlethorpe Wrexham LOGGS WALES (36) Balgzand Birmingham (36) Bacton BB Milford Haven L ENGLAND (24) ector Amsterdam Dragon (M. Haven) Swansea (36) (20) South Hook (M. Haven) (40) Bristol Grain

terconn NETHS. In Exeter Zeebrugge Easington Calais A Plymouth Brussels B Immingham FRANCE BELGIUM The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source:The Petroleum Economist Ltd.. Natural Gas Market Review 2007 • OECD Country/Region Update 208

quality acts as a constraint to gas supplies Gas trading and further examine solutions to this potential problem. Ofgem introduced the screen-based, on- the-day commodity market (OCM) in 1999 Storage and fl exibility to allow shippers to balance their daily positions and National Grid to purchase The offshore “Rough” storage (owned by and sell gas to balance the transmission Centrica Storage Ltd) accounts for about system. 76% of the available gas storage capacity. The Hornsea facility (SSE), represents The National Balancing Point (NBP), 8.8% of storage capacity while Humbly a notional point at the centre of the Grove () accounts for 7%. transmission system, serves as a market The facilities which are used to balance place for gas. Once gas has entered the shifts in demand within a single 24-hour transmission system at an entry point, period offer relatively modest storage it can be traded at the NBP without volumes (1.5% of the national total) but quantitative restrictions relating to its can withdraw quickly and thus represent exit point. The physical gas is traded at the a large share of the combined withdrawal NBP for balancing purposes partly through rate for the country (28.5%). National the OCM and partly through bilateral Grid owns fi ve LNG peak shaving units, deals. The NBP is also the settlement point accounting for almost 10% of the total. for exchange traded futures contracts. The LNG peak shavers have the highest The NBP churn rate is around 10, meaning withdrawal rate: 36.5%. that each molecule of gas is traded ten times before it is delivered. Just over half The United Kingdom continental shelf still the gas delivered in the United Kingdom has considerable production fl exibility, is actually traded on the NBP with the rest though this is decreasing as overall delivered under long term contracts. production is reduced through depletion. Nevertheless, the peak swing capacity of the UKCS by 2011/12 (200 mcm per day) Netherlands added to the planned withdrawal capacity from storage in place by 2011/12 (400 mcm The Netherlands is a large established per day) should cover the maximum (1 in gas producer and exporter; 78 bcm and 20) peak winter demand (550 mcm per day) 55 bcm respectively in 2006. Net exports – assuming depletion rates are accurate. are considerably lower than this as the Netherlands is also a signifi cant importer (25 bcm in 2006). Its peak production capacity of nearly 11 bcm per month is important in balancing supply with demand throughout the winter peak in Northwest Europe. Physical gas fl ow information is published on all borders, but is not yet available by pipeline. Natural Gas Market Review 2007 • OECD Country/Region Update 209

Supply and Norway have recently changed. Particularly relevant are changes to the The Nederlandse Aardolie Maatschappij treatment of Norwegian and the United B.V. (NAM), owned by Shell and Exxon Kingdom’s continental shelf “fallow fi elds” Mobil, has been active in the Netherlands (those reserves which are economic, but since before the discovery of the large not yet produced). Changes in fallow fi eld Groningen fi eld, with original producible rules are expected to increase production gas reserves estimated at 2 700 bcm. The in the United Kingdom’s and Norwegian Groningen fi eld is operated by and for the sectors as larger companies are forced benefi t of a public-private partnership to give up acreage that they do not fi nd which stipulates that Groningen gas must attractive to develop in favour of smaller, be marketed via GasTerra, whose annual specialist gas companies. profi ts are capped. An extra dimension of this arrangement is that the state, Demand producers and GasTerra have agreed to prolong the life of the Groningen fi eld by The Netherlands has amongst the highest encouraging production of other, more level of gas penetration in the world. In expensive fi elds (“small-fi elds policy”, 2005 the natural gas share of total primary codifi ed in the Gas Act). energy in the Netherlands was 43% compared to the IEA Europe average of During the last decade many other 24%. Natural gas use for power generation producers entered the Dutch market, accounts for about 33% of total gas but the NAM remains by far the largest demand. Natural gas consumption totalled producer with its concession for the 49.5 bcm in 2005. In the same year Dutch Groningen fi eld and a total market share exports amounted to 52.4 bcm, of which of almost 75%. NAM produces 50 bcm of 31.9 bcm was to Germany and 20.5 bcm to natural gas a year, of which 27 bcm (54%) Belgium. comes from the Groningen fi eld. The development of many deposits is diffi cult The natural gas share in power generation because they are located underneath was 60.5% in 2004. In view of this large environmentally sensitive areas. NAM share and the high imports, electricity commenced production in the Wadden Sea prices are sensitive to changes in gas area in 2007, which contains a relatively prices. large amount of gas (approximately 20 bcm).There is no specifi c regulatory LNG regime for access to upstream pipelines, only general competition rules apply. In the Netherlands four LNG terminals are being planned. The projects are at The Netherlands has historically had a different stages. In September 2006 similar policy to the United Kingdom and Petroplus International N.V. received Norway regarding offshore licensing for its fi nal environmental permit for its production acreage. However, licensing subsidiary 4Gas, to build an LNG terminal in arrangements in both the United Kingdom Rotterdam. Its LionGas project is planned Natural Gas Market Review 2007 • OECD Country/Region Update 210

Figure 58 Netherlands gas consumption

52

bcm 51

50

49

48

47

46

45 2000 2001 2002 2003 2004 2005 2006

Source: IEA data. to be completed in 2010. The permit allows Midstream and gas quality for a capacity of 18 bcm per year; the terminal will initially be constructed for Gas – especially from small fi elds – may be 9 bcm per year. Essent and ConocoPhillips different in composition and, consequently, have completed a feasibility study for an may have a different calorifi c value. If LNG terminal at the Port of Eemshaven gas of a higher calorifi c value needs to be in the north of the Netherlands. In March converted to gas of a lower calorifi c value, 2006 they started applying for permits. the shipper will need to contract quality Gasunie and Koninklijke Vopak N.V. are conversion. There are four standard Gas partners in the Gate terminal LNG project qualities: H, L, G+ and G. These four types in the port of Rotterdam (fi rst phase 8 of gas are transported through separate – 12 bcm per year). A fi nal investment but interlinked transmission grids. Cross- decision is likely by mid 2007; the terminal subsidies between different consumer may be operational by 2010. In addition, groups are prohibited, but the costs Taqa – the national energy company of associated with quality conversion have Abu Dhabi, the United Arab Emirates been socialised by 50%, to create more – announced in February 2007 that it is of a level playing fi eld for parties without going to build an LNG installation off the direct access to L-gas. coast near Rotterdam, utilising onboard regasifi cation technology and offshore The throughput of the transmission sys- depleted gas fi elds for gas storage. tem is large and growing as a result of Natural Gas Market Review 2007 • OECD Country/Region Update 211

increasing international gas fl ows. In 2005, pipeline will be built with a transport 95.6 bcm was transported, of which two capacity of around 27.5 bcm per year. The thirds crossed at least one border, double second pipeline is planned to come on the level of domestic gas consumption. stream in 2012 to double the transport Increasing imports are expected from capacity to around 55 bcm a year. European Russia and Norway and via LNG, as TPA rules will not apply. European gas consumption increases while production declines. The expected increase Storage and fl exibility in transit, imports and exports has to be accommodated with investments in both The current balancing regime is based entry and exit capacity at the borders and on daily balancing on portfolio basis reinforcements of pipelines. In short, as with cumulative hourly tolerances. GTS with many IEA European countries, the (Gas Transmission System Company) Dutch pipeline network will probably need offers shippers a certain amount of to be reshaped substantially within the hourly tolerance as part of standard next decade. transportation contracts and refrains from imposing penalties on hourly imbalances, The BBL (Balgzand-Bacton Line) started if these stay within the tolerance. GTS uses transporting gas from the Netherlands to the prices listed on the gas exchange as a the United Kingdom on 1 December 2006. basis for the settlement of the imbalance The total transport capacity is 16 bcm volume. For 2007, the day-ahead APX per year, based on the total capacity indices for the Title Transfer Facility (TTF) sold during the open season in 2003. BBL price, the Zeebrugge Hub price and the NBP Company, owned by Gasunie (51%), E.ON index will be used. The price for shortages Ruhrgas (20%), Fluxys (20%) and OAO will be determined by the highest price in Gazprom (9%), will offer capacity on an the price basket; the price for surpluses by interruptible basis when shippers do not the lowest price in the price basket. This use their contracted capacity for a limited methodology is somewhat arbitrary as time. During the open season of 2003 no neither the NBP price nor the Zeebrugge structural interest was shown by shippers prices are determined by balancing to transport gas from the United Kingdom conditions in the Netherlands. to the Netherlands, but reverse fl ow could be made possible in the future if Shippers can buy tolerance from each technical modifi cations are made. The BBL other. However, this tolerance is not is exempted from TPA obligations. suffi cient given the typical consumer off-take profi les. Serving consumers, Another interconnection, the Nordstream particularly small ones, requires fl exibility pipeline, is planned for completion in 2010, services. These services can be purchased to transport gas from Russia directly to from storage owners and from GTS, which Germany. Nord Stream is a joint project has an obligation to tender the services. of four companies: OAO Gazprom (51%), GTS, Nuon and AKZO/Nobel have taken an Wintershall AG (20%), E.ON Ruhrgas AG initiative to build a commercial storage (20%) and Gasunie (9%). Initially one facility in a salt cavern in the Netherlands. Natural Gas Market Review 2007 • OECD Country/Region Update 212

Figure 59 Netherlands gas transport network

0Miles 100 0 Km 100

Groningen Emden

Balgzand

BBL ) 8 (4

Amsterdam NETHERLANDS GERMANY

Rotterdam Gate LionGas Vlissingen (36)

Zeebrugge Gas pipeline Gas pipeline planned or under const. Major gas processing plant BELGIUM Underground gas storage Underground gas storage planned Brussels (24) Pipeline diameter (inches) Gas import route LNG import terminal Bonn LNG import terminal planned The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source:The Petroleum Economist Ltd..

There are three underground storage regulation because only the existing ones facilities, namely Grijpskerk, Norg and are deemed to have a dominant market Alkmaar. In 2002, DTe issued “Guidelines position. for Gas Storage”, which stipulate that the companies, NAM and the Bergen Gas trading Concessionaries, owning the three exis- ting gas storage facilities must make a Approximately 50 shippers have con- considerable part of their storage capacity cluded a transport contract with GTS. available to third parties on a negotiated Groningen gas is marketed via GasTerra, access basis. They must base tariffs for which also must buy small fi elds their services on actual costs and relevant production if asked – it therefore has the substitutes. New storages owned by lion’s share of the Dutch shipper market. new operators will not be subjected to The exclusive right it has been granted Natural Gas Market Review 2007 • OECD Country/Region Update 213

regarding the Groningen fi eld hampers Kingdom’s NBP it is still moderate. Since effective competition in the market for February 2005, APX Gas NL has provided a low calorifi c gas. GasTerra does not deliver real time market place facility to buy and gas directly to end users in distribution sell within-day and day-ahead gas at the networks but focuses on its core business TTF. Endex European Energy Derivatives of delivery to large consumers connected Exchange launched clearing services for to the transmission grid, wholesaling and TTF gas contracts on 20 October 2006. shipping. Plans to split the company into two, one owned by ExxonMobil and one by Shell, have been discussed for several Norway years but not fi nally agreed. The economically effi cient development The majority of gas prices are set according of its large oil and gas resources has made to the “market value principle” established Norway the third-largest exporter and in the 1960’s, meaning that gas is priced sixth-largest producer of gas in the world according to the prices of alternative fuels. in 2005. Over 90% of the gas produced This means linking gas prices to the prices from the Norwegian continental shelf of the reference fuels for households (NCS) is exported to continental Europe (domestic fuel oil) and larger consumers and the United Kingdom; the oil and gas (fuel oil). Daily published gas wholesale industry itself accounts for most domestic prices are not yet available, as the market is gas use. In 2005 Norway supplied over a not suffi ciently liquid. Initiatives have been third of the total import demand of the taken to create a wholesale gas exchange, North-West European market (Belgium, starting with the TTF (Title Transfer the United Kingdom, the Netherlands Facility). GasTerra is experimenting with and Germany); 18% of the gas imported sales based on TTF and NBP prices. by IEA Europe was produced on the NCS. A network of undersea pipelines connects During 2005 the trading volume on the TTF Norway to Europe across the North Sea grew by an average 9% per month, adding (see fi gure 60). Pipeline exports will be up to a total of around 12.5 bcm. This supplemented by LNG from the Snøhvit equals more than a quarter of the volume project in 2007. of gas consumed by the Netherlands. A net amount of around 4 bcm was supplied Supply by shippers via the TTF (up from 1.3 and 2.5 bcm in 2003 and 2004). In 2005 Norway exported 83 bcm of its 90 bcm production; 32.6% of exports went The TTF helps to increase liquidity in the to Germany, 18.6% to France, 17.3% to market by facilitating a spot and forward the United Kingdom and some 8% each market and creating new ways to access to Belgium, the Netherlands and Italy. The gas. It serves as a virtual entry or exit rest was supplied to Spain whilst swap point in the shipper’s portfolio. Currently contracts exist with the Czech Republic 38 parties are active on the TTF. Liquidity and Poland. Most gas is processed onshore is increasing, but compared to the United before being exported. The gas sales price Natural Gas Market Review 2007 • OECD Country/Region Update 214

Figure 60 Norway gas transport network

Gas pipeline Gas pipeline planned or under const.

Major gas processing plant Snøhvit LNG )

Underground gas storage 6 Underground gas storage planned (16) (1 Asgard transport pipeline

(24) Pipeline diameter (inches) (ATP) PIPE

(42) N

TE

LNG import terminal L A

LNG import terminal planned H (2x30) LNG plant planned Tjeldbergodden Major gas field Nyhamma 0Miles 100 200 Northern Leg gas pipeline (20) 0Km 200 300

) 2 (4 Tampen link (32)

Sullom Voe 2x(36) NORWAY MAGNUS EORShetland Is. Kollsnes

S ) T 6 AT (3 ) S 0 P Oslo 4 IP AG ( E L (3 F (32) IIA ) E 0 0 IP ) P (4 FRIGG E E Kårstø Z IIB (32) E IP P (36) E ) E 8 Z E (2 ) PIP 0 TAT (3 S

(30) )

SAGE 0

St. Fergus (4 E

(27) (36)

IP F (42) ULMAR P

(2 II

0) O

R

U

E PIPE

STATPIPE EURO

) ) 6 4 ) N. IRELAND (3 4 S ( 4 3 D ( E CAT L L E A E ) Belfast G S 2 N

(4 LA (40) DENMARK

Teesside PIPE

N EU RO ZEEPIPE FRA N PIPE O RPIPE IRELAND Dublin (4 0) (3 Wilhelmshaven 6) UNITED Dornum KINGDOM Groningen

Balgzand BBL

Dragon (M. Haven) Amsterdam South Hook (M. Haven) London NETHERLANDS. Grain GERMANY Zeebrugge BELGIUM FRANCE Brussels

The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

Source:The Petroleum Economist Ltd.. Natural Gas Market Review 2007 • OECD Country/Region Update 215

Figure 61 Norwegian gas production

100

bcm 90

80

70

60

50

40

30

20

10

0 2000 2001 2002 2003 2004 2005 2006

Source: IEA data (December 2006 provisional). is mostly based on delivered oil prices in To increase exploration in mature areas the target market with the exception of with existing infrastructure. the United Kingdom, where it is sold on To increase information and choice the “NBP” gas index (explained in United available to companies. Kingdom section above). Exports in 2006 rose to 85 bcm. Bringing Ormen Lange and The fi rst license awards after these Snøhvit on stream (see below) will make changes were viewed as a success, with Norway the second largest gas exporter three companies gaining acreage for the after Russia, overtaking Canada. fi rst time and one specialist “tail end” production company applying. For full Following report 38 to the Storting (2003 details of the changes to licensing, refer - 2004) “On oil and gas activities” in 2003, to IEA Energy Policies of Norway (2005).20 the government has recently changed the licensing and taxation policy for upstream Norway plays a leadership role in upstream oil and gas activities. The main objectives technology. Recovery rates are extremely of the change were the following: high by international standards, driven To encourage new, smaller companies to by higher gas prices and incentives for enter the Norwegian continental shelf production of marginal fi elds; however, (NCS) and participate in award rounds. the costs of drilling might become a bottleneck in future exploration. To encourage the speedy exploitation of awarded acreage. Comparatively higher costs than in the

20. http://www.iea.org/textbase/nppdf/free/2005/norway2005.pdf Natural Gas Market Review 2007 • OECD Country/Region Update 216

Figure 62 Expected future Norwegian gas production

140

bcm 120

100

80

60

40

20

0 2006 2007 2008 2009 2010 2011 2012

Source: Ministry of Petroleum and Energy (facts 2006).

United Kingdom sector of the North is almost no on-shore gas distribution Sea are driven by a combination of high network. Domestic power production is environmental standards and signifi cantly almost entirely based on hydro-generation, higher cost for labour. Norway imposes although Norway benefi ts from being part very high environmental performance and of the larger Nordpool electricity system safety standards on the offshore industry, which also uses other generation sources. including regulations on exploration rigs that make it diffi cult for rig owners from Only 1.2% of gas consumption was used other areas of the North Sea to offer their for power generation in 2004. A CCGT services in Norway. plant at Kårstø is under construction and is planned to come on line in the autumn Demand of 2007. It is Norway’s fi rst commercial onshore gas-fi red power plant and it claims The use of gas is limited in Norway itself, the lowest greenhouse gas emissions even though domestic consumption has of any -based power plant in increased from 4.2 bcm in 2001 to 5.8 bcm Europe. There are plans to install a CO2 in 2005. Most of this gas is consumed by capture facility for the plant after 2009. the energy industry itself: 80% of domestic The government and Statoil concluded an consumption is used for oil and gas agreement in 2006 to establish the world’s extraction. Many of today’s gas applications largest carbon capture and storage (CCS) are accordingly found close to the landfall project in conjunction with a projected sites of pipelines along the coast; there CHP power plant at Mongstad. The project, Natural Gas Market Review 2007 • OECD Country/Region Update 217

which is intended to be fully operational currently running over budget and behind by 2014, will have a thermal effi ciency of time. It will be the fi rst export facility around 80%. for LNG in Norway (and for that matter, Europe), with markets in both North Recent and future developments America and Europe.

The most signifi cant recent pipeline The concept of a gas pipeline from Norway development in Norway is the 2-stage to Sweden is under consideration. The Ormen Lange project in the Norwegian initial annual volumes to be carried by Sea. The fi rst stage of this project saw the pipeline are expected to total some the construction of the Langeled pipeline 3 bcm. Plans call for a possible investment system from Nyhamna, Norway to decision in 2009, with the system being Easington, the United Kingdom – the ready for start up in 2011/12. There longest underwater pipeline in the world. are other development projects under Langeled entered operation in September consideration, such as the further 2006, ahead of time and under budget. development of the Troll fi eld, by Statoil Norwegian gas began to fl ow through and Norsk Hydro. The need for a new the southern leg of the Langeled pipeline export pipeline continues to be evaluated system from the Sleipner Riser platform and studies of possible routes are ongoing. to the United Kingdom on 1 October 2006. The United Kingdom, Belgium and the The second stage of the development is to Netherlands are candidates for landfall. bring production from the Ormen Lange fi eld online in September 2007. This is the Territorial issues second-largest gas fi eld in Norway and the fi rst development at a water depth of A recent agreement reached in 2005 800 – 1 100 m. The Tampen Link, also to between the United Kingdom and Norway the United Kingdom, will be another new on the tax treatment for the exploitation link with a capacity of about 10 bcm to be of resources at the boundary between the ready by 2007. two countries has opened the way for their development. A similar agreement will be There has been a ban on Arctic drilling in required with Russia before the boundary Norway since 2001, pending environmental areas of the Barents Sea can be opened for impact studies. However Norway reopened exploration. the southern part of the Barents Sea for exploration and production activity in Shelf boundaries are regulated by the 2003, subject to strict environmental United Nations Convention on Law of the requirements. The Snøhvit fi eld is the fi rst Sea. Since 1996 the Norwegian Government development in this area. Snøhvit is being has been collecting data and mapping developed for LNG export, with initial areas in the Norwegian Sea and Barents production expected later in 2007. This Sea, to fi nd out how far the NCS extends is a particularly challenging development beyond the 200-mile limit. Data collection with many “fi rsts” for the gas industry from the Norwegian shelf has now been worldwide; because of this the project is completed and the documentation has Natural Gas Market Review 2007 • OECD Country/Region Update 218

been handed over to the commission. If Demand Norway’s view is accepted, the NCS will be expanded by an area corresponding to half In 2005 domestic gas use was 17.3 bcm, all the size of mainland Norway. met by imports. Belgium’s domestic gas demand is expected to rise by 5% annually over the period 2004-2010 as the share of Belgium power demand met by gas-fi red electricity increases from 25% to more than 44%. Belgium has no indigenous gas production Long-term projections (to 2020) indicate and therefore relies on imports to meet that gas-fi red generation will expand to 63% all of its domestic requirements. Its of power needs as nuclear power is phased strategic location between major sources out (Nuclear power currently supplies 56% of European gas (to its north and west) of Belgium’s electricity generation). This and primary markets (south and east) implies expanding gas-fi red output from give the country an importance for the 22 TWh to 69 TWh in that time frame, (an trade of gas in Europe well beyond its increase in gas demand of about 8 bcm at own relatively small consumption. As in best practice effi ciency) such an increase other IEA countries, consumption is set represents a major change in the profi le to grow rapidly with the phase-out of and location of demand and would require nuclear power and its replacement with signifi cant modifi cation of the existing the “default option” – natural gas-fi red gas and power infrastructure. Greater gas- generation. fi red power generation is the major factor in the forecast two thirds increase in gas Belgian gas market liberalisation has imports to Belgium by 2020. progressed rapidly to a point. With the landfall of the Interconnector to/from Supply the United Kingdom in 1998, liquidity at the landfall point, the Zeebrugge physical In 2006, 32% of the 17 bcm pipeline hub, expanded rapidly. The number of imports came from the Netherlands, 31% counterparties active at Zeebrugge has from Norway and 37% from other sources, expanded. Nevertheless, the liquidity of the including Russia (5%), the United Kingdom hub is still dependent on the Interconnector, (2%) and 20% from Algeria. Belgium as domestic Belgian competition has not imported 2.7 bcm as LNG from Algeria. developed quickly. At the time of the Distrigas (Suez) is the major importer, last IEA Energy policy review of Belgium accounting for more than 90% of total (2005), the domestic market was over 95% imports in 2004. controlled by one company. The same company held rights to the majority of the LNG capacity at the Zeebrugge hub. Fluxys LNG (Suez) owns and operates the LNG terminal in Zeebrugge and sells terminal capacity and related services. In 2006 the LNG terminal received 54 cargoes. Natural Gas Market Review 2007 • OECD Country/Region Update 219

Figure 63 Belgian gas consumption

18

bcm 17

16

15

14

13

12

11

10 2000 2001 2002 2003 2004 2005 2006

Source: IEA Data (December 2006, provisional).

The LNG regasifi cation and storage facility the interest of the market in additional at the port of Zeebrugge has contributed terminal capacity as the pre-feasibility to the security of Belgium’s gas supply, study is positive. although take away capacity inland has remained in the hands of the incumbent. Midstream and gas quality Fluxys (Suez) publishes available capacity from the Zeebrugge LNG terminal into The domestic gas market is divided Belgium on its website. Unloading capacity between the two qualities of gas used in at the LNG terminal was fully committed Belgium, introduced by supplies from the until 2006 by Distrigas and from 2007 Netherlands, the United Kingdom and onwards it is fully booked by Exxon/Qatar Norway. Dutch L-gas is transported on a Petroleum and Suez affi liates Distrigas network that is physically separate from and Tractebel LNG. Fluxys is currently the H-gas network. The L-gas is sold to fi nalizing the construction of a fourth Distrigas on a take-or-pay contract with LNG storage tank and additional send-out GasTerra running to 2016. As a result, capacity at Zeebrugge, to be in operation there is no competition within the gas at the end of 2007. The import terminal will supply regions solely supplied with L-gas. have doubled its capacity from 4.5 bcm to The policy implemented by the regulator 9 bcm per year as from 2007. From 1 April to solve this issue is to extend the H-gas 2007, a new multi-shipper environment grid to L-gas customers – this process will will be created at the LNG terminal. In 2007 take some time. an open season will be launched to assess Natural Gas Market Review 2007 • OECD Country/Region Update 220

The amount of available transmission It has requested an exemption from TPA as capacity is low with none available at all this infrastructure would be of European (current or planned) on the L-gas network. interest (similar to the investments for the Fluxys is looking into the possibility of LNG terminal). gradually increasing H-gas transmission capacity towards Zeebrugge from Storage and fl exibility 2009/2010. This would allow much larger volumes of natural gas from the east and The Belgian gas network is well north to be moved through the Fluxys grid. interconnected to its neighbours, with The indicative investment programme for North Sea gas from both Norway and the period 2005-2014 represents more subsequently the United Kingdom. The than USD 1.2 billion for transmission and Netherlands’ gas fi elds can effectively storage infrastructure. In 2007 Fluxys will act as swing supply. This has reduced the carry out a new market survey to assess incentive to develop seasonal gas storage, the interests of the market for additional which would have performed the same north-south transit capacity. role. This tendency has been enhanced by the paucity of suitable geological The Fluxys network is well interconnected formations. However, the Dutch and United with adjacent pipeline systems through Kingdom swing capacity is declining fast 18 entry points. The domestic network and Belgium needs to look for alternative will be integrated with the international future fl exibility. pipelines to enhance Belgian security of supply and increase the liquidity of the Short-term storage is available at domestic gas market. Zeebrugge and also by transporting LNG by truck to a storage site in Dudzele, Current investment in international gas which is used as peak-shaving facility. infrastructure is targeted on three key sites Hour-to-hour fl exibility is also obtained in order to increase import capacity and by modifying the withdrawal rates from improve the compatibility of the domestic LNG tankers at Zeebrugge, in addition to network with that of neighbouring the standard use of line-pack. There is one countries. Fluxys is working on capacity site to supply seasonal storage. enhancement at the Zeebrugge LNG terminal, on which it is allowed to earn The cost of balancing services is a concern higher revenues. In 2006 the Interconnector in Belgium, where balancing penalties Gas Pipeline built a compressor station in are amongst the highest in the EU as the Zeebrugge in order to be able to reverse Belgian grid is rather small compared to fl ows to the United Kingdom. Fluxys also adjacent grids. Some degree of imbalance is planning to expand the capacity of is unavoidable in any gas system, as the VTN-RTR pipeline from 2009-2010, it is impossible to accurately forecast which includes the construction a new demand and supply. Flexibility is included compressor station in Zelzate, which will in the base source and shippers can enhance operational fl exibility of the grid obtain additional fl exibility with priority and boost supply capacity from the north. given to small operators. Shippers must Natural Gas Market Review 2007 • OECD Country/Region Update 221

match nominations and deliveries prior the continental EUR/MWH. Liquidity is to delivery and are assessed every half lower than the United Kingdom because hour on the day of delivery across four the Belgian domestic market has been balancing zones. The cost of balancing in split into four balancing points (BAPs). Belgium presents a substantial business The Belgian Northern balancing zone risk for new entrants and is a signifi cant represents the L-gas customers supplied barrier for entry to the market. form the Netherlands; the other three surround the major interconnection points Gas trading to the United Kingdom (West), France (South) and Germany (East). The Zeebrugge physical hub essentially acts as an arm of the United Kingdom The lack of depth can also be seen at times NBP, with prices traded in United of stress in the market. Because Zeebrugge Kingdom pence per therm rather than is a physical hub in only one balancing

Figure 64 Belgian gas transport network

0Miles 100 In te 0 Km 100 rco n (4 n NETHERLANDS 0 e ) cto UK r (42) Zeebrugge

FRANPIPE Antwerp Calais Dunkirk Ghent

RTR Brussels

BELGIUM Aachen GERMANY Blaregnies

FRANCE TE N P Gas pipeline Gas pipeline planned or under const. Major gas processing plant Underground gas storage LUXEMBOURG Underground gas storage planned (24) Pipeline diameter (inches) Lux. City Gas import route LNG import terminal LNG import terminal planned The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

Source:The Petroleum Economist Ltd.. Natural Gas Market Review 2007 • OECD Country/Region Update 222

zone, the owner of the transportation Wholesale prices are determined through capacity to and from the physical hub the Zeebrugge Hub, but do not impact controls access to the Belgian domestic on retail prices in Belgium as these are market. Most of this capacity is held on still linked to oil prices. Making more gas long term contracts. For the fi rst time, on available to third parties, making access 14 September 2006 the regulator required to the hub more transparent and, as a Fluxys to offer transportation services to result, increasing gas volumes on the and from the hub as from 1 January 2007. traded market is essential to increasing Fluxys launched the ZEE Platform Service the liquidity at the Zeebrugge Hub, at the end of 2006. This new service offers which would generate gas pricing that grid users open transfer of gas between refl ects fundamentals in the Belgian different entry points in the Zeebrugge gas market. Liquidity would also be area via a single contract. The Zeepipe increased by collapsing the four regional platform service simplifi es physical access balancing zones into one high-calorie to the Zeebrugge hub. gas balancing zone that includes the Zeebrugge Hub trading point and one Huberator s.a. (Fluxys stake 90%) operates low-calorie zone with quality conversion the Zeebrugge Hub and provides services services. Currently, oil-indexed prices to companies active on the hub. Its dominate within Belgium, providing no facilities comprise an LNG terminal, the useful pricing signals about the supply Zeepipe terminal and the Interconnector and demand of gas. Furthermore, Belgium terminal in the Zeebrugge area. In late does not see pricing signals that would 2005, the company had 46 customers. identify the need for new investment in The net traded volume on the hub in capacity and other infrastructure. This 2005 reached 40 bcm, which is also the puts considerable strain on the Fluxys throughput capacity of the Zeebrugge system and compromises security of the facilities resulting in a churn rate of 1 domestic supply network. for the West BAP. A churn rate of 10 is considered by some a measure of a liquid hub, though other factors such as the Turkey number of market-makers and the number of counterparties are also important. The role of gas in Turkey

In an attempt to increase the liquidity at Turkey’s population has grown by more the hub, Huberator has launched a screen- than 25% over the 15 years from 1990, based exchange for the Zeebrugge market to nearly 73 million in 2005. Even with in partnership with APX Gas ZEE in 2005. slowing growth, by 2020, the population In the future Endex European Energy will reach nearly 90 million. Following the Derivatives Exchange plans to offer economic crisis of 2001, the economy clearing services. Fluxys published new has rebounded strongly, at between 6% trading terms for shippers trading across and 8% per annum. Nonetheless, per the Zeebrugge Hub on 10 September 2006, capita GDP is less than a third of the in order to simplify hub trading. OECD average. The investment climate Natural Gas Market Review 2007 • OECD Country/Region Update 223

has improved substantially over the last role in the electricity sector; gas-fi red six years, stimulating a strong increase in power has gone from 10 TWh in 1990 to foreign direct investment. 71 TWh in 2005, the latter being 44% of power produced. The electricity sector Energy demand per capita is low. However, unsurprisingly is the major driver of gas total primary energy is growing rapidly; demand, accounting for nearly three-fi fths anticipated growth is 7 % over this decade, of gas use. from 86.4 mtoe in 2005 to 126 mtoe in 2010 and 222 mtoe in 2020, although Turkey produces only 3% of its gas needs, forecasts have tended to over-estimate so almost all supplies are imported, with already high demand growth. Gas and coal two-thirds coming from Russia. LNG are predicted to grow rapidly, so that by imports from Algeria and Nigeria provide 2010, their shares of the total supply will one-sixth as does pipeline gas from Iran approach 30 % each (see Figure 66). (4.3 bcm in 2005). Contract LNG supplies have been supplemented by spot pur- Gas has grown its share of the energy mix chases as in most IEA countries. Iranian from just 5% in 1990 to 25% in 2006. In pipeline imports started in 2001 and in 2005, total gas use was 30.9 bcm, up nearly 2003, gas arrived from Russia via the Blue- 100% on 2000 consumption, ranking Stream pipeline under the Black Sea. The just behind Spain and Korea in the ranks pipeline has a capacity of 16 bcm per year, of IEA gas users. Gas plays an important but shipments are likely to rise relatively

Figure 65 Gas transport network in Turkey

GEORGIA BULGARIA Tbilisi Malkoclar

PROJECT2x(24) BLUE-STREAM Bartin Komotini Samsun AZER. Istanbul Eregli ARM. Ipsala (36) Corum Yerevan Marmara Izmit BLUE-STREAM Canakkale Ereglisi POSSIBLE EXTENSION (42)Dogubayazit Bilecik NABUCCO (5 6) (48) Karacabey Kirikale Bazargan AZER. Can (24) Yozgat Sivas TURKEY-EASTERN (4 (12) ) Ankara 8) ANATOLIA PROJECT 6 (3 TURKEY IRAN Kirsehir Aliaga (36) (40) Afyon (40) Malatya Izmir Usak Aksaray )

0

(40) Nigde (4 (40) Konya Isparta Kahramanmaras (40) IRAQ Eregli Seydisehir (40) Karaman Adana Gaziantep Gas pipeline Ceyhan Antalya Icel (Mersin) Gas pipeline planned or under const. Kilis Underground gas storage Hatay ARAB GAS PIPELINE (AGP) PLANNED Underground gas storage planned EXTENSION (24) Pipeline diameter (inches) 0 Miles 100 LNG terminal Vassiliko CYPRUS SYRIA 0 Km 100 From Homs LNG terminal planned The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source:The Petroleum Economist Ltd.. Natural Gas Market Review 2007 • OECD Country/Region Update 224

Figure 66 Turkish primary energy supply

250

Mtoe

200

150

100

50

0 1980 1985 1990 1995 2000 2005 2010 2015 (est.) 2020 Coal and coal products Oil Natural gas Nuclear Other

Source: IEA data and Turkish government.

Figure 67 Turkish gas supply by source and demand by sector

Supply sources 2005 Consumption 2005 100%

80%

60%

40%

20%

0% Russia, BlueStream Russia, Turusgas Electricity Residential Russia West Iran Algeria Nigeria Industry Fertiliser

Source: IEA data. slowly to that level, standing at 7 bcm per is growing in the power, industrial and year in 2006. The threat of “oversupply” residential sectors as gas distribution is not great as there is fl exibility in the networks are expanded, especially in cities. Blue-Stream contracts. Meanwhile demand Natural Gas Market Review 2007 • OECD Country/Region Update 225

As noted elsewhere in this Review, in The tariffs for transportation on the high December 2006 and January 2007, Iran pressure grid and for distribution are set reduced its pipeline gas delivery to Turkey by the regulator, but those for transit due to domestic gas supply problems, as will be set by the Minister, probably at had happened previously. The winter was least until the expected East-West transit exceptionally cold and many Iranian cities structures have been set up. saw their gas supply cut off. Iran is rapidly expanding its national gas networks, which Gas release programme has caused many technical and operational problems in cold winters, leading to drops The fi rst transfers of import contracts in gas pressure in its export pipelines. (12%, 4 bcm per year for 15 years) to the private sector were tendered out and Gas infrastructure awarded at the premium offered by the highest bidder. They are to be implemented After completing the East-West con- by BOTAS before the end of 2007. nection to allow for the import of gas from Iran in 2001, BOTAS (the Petroleum Pipeline As in some other IEA countries implemen- Corporation, a 100% state-owned company) ting gas liberalisation efforts, storage is more than doubled its grid between 2002 and considered secondary. This means that 2005 giving it a total length of 7 809 km. In balancing problems are surfacing. BOTAS 2006 another 2 359 km was built, extending does not offer storage while commercial the grid to more than 10 000 km. storage is not available. Buyers seem to have different attitudes on the need to Although Turkey has rented storage ca- address this issue before deliveries start, pacity in Ukraine to date, the fi rst sizeable or instead rely on improvised solutions storage in Marmara Sivrili will come on once the scope of any problems becomes stream in 2007. This is a depleted gas fi eld known from practice. with 1.5 bcm working volume to the west of Istanbul. In addition, the tendering process Distribution developments has been started for a storage site which will ultimately contain 5 bcm of gas in caverns at The fi ve older grids in the main cities are the salt lakes 150 km SE of Ankara (Tuzgölü). well developed. They were owned and Plans are also being made for a smaller controlled by the municipalities, but two 0.6 bcm storage in the South near Mersin. have now been privatised leaving Istanbul, Ankara and Izmit. These grids have over Market structure and liberalisation 4 million connections and aggregate sales of 8 bcm per year. The Government BOTAS is the sole importer of gas and the started a privatisation process for the owner of the high pressure grid. Under the grids in Istanbul (IGDAS), Ankara (EGO) Gas law it has to give up 80% of its import and Izmit (IZGAZ), but the tender has been activities by 2009 and is not allowed to withdrawn. conclude new import contracts until that situation has been achieved. Natural Gas Market Review 2007 • OECD Country/Region Update 226

Retail distribution to the rest of the but identical exit tariffs throughout the country is well underway. Concessions for country. Imbalances are likely and will 30 years are being issued by the Regulatory require balancing by BOTAS. A network Body (EMRA) after a tender process. Local code has been in force since 2004, but investors have shown particular interest has not been implemented as the market in the 27 new grids currently operating. has only one supplier. Discussions on Almost USD 400 million has been invested possible improvements are ongoing. The in these latter grids while USD 650 million return on investment for BOTAS is set by is planned for 2007. So far 450 000 new the Government, based on international connections have been made with sales of benchmarking. No incentive regulation is 2 bcm in 2006 by the new operators. This in place yet or offi cially planned. Storages is likely to rise to 600 000 connections and will not be regulated under current rules. 2.5 to 3 bcm in 2007. Gas pricing, as well as transportation and The competition for these grids is strong distribution tariffs are regulated by EMRA. despite the fact that owners can only BOTAS, IGDAS and EGO make adequate charge customers a connection fee (cur- returns, while new distributors have rently USD 180) in addition to the city low profi tability for reasons described above. The full impact of liberalised gate price. The fi xed and variable costs of pricing will become clearer once the gas distribution for a fi xed period of 8 years are release program becomes effective and not therefore passed on to the consumer, the successful bidders have to survive in resulting in very low margins. The inves- an environment based on the traditional tor and owner, typically a construction border price plus the same charges for company, is obviously banking on the transmission that their government- regional monopoly concession of 22 years owned competitors are facing. It is unclear following purchase as well as the income how prices will be affected for different from associated services. Some smaller classes of consumers as markets liberalise grids have been sold and acquired by other given existing price controls. grid owners. The largest number of grids in the hands of one owner is eleven. Supply developments The Bluestream pipeline is running at only All grid operators/licence holders including about one-third of capacity, while the the old ones are members of an active, new fi rst Gazprom contract, for imports from grid organisation Gazbir (Union of Natural the West of Turkey via Bulgaria (6 bcm per Gas Distribution Companies) which is well year) will expire in 2011. Technically, the recognized by the authorities and involved Bluestream system could accommodate in international bodies like Eurogas and IGU. these volumes at its current supply levels as well, but the potential role of Gazprom Regulatory developments and prices would then be reduced (given the need for other imports at the expected high levels The whole Turkish grid serves as one Entry of demand). The doubling of Blue-Stream Exit zone with small differences in entry announced in the past would help, but the tariffs depending on the entry point, timing of that expansion is unclear. Natural Gas Market Review 2007 • OECD Country/Region Update 227

The contract with Azerbaijan (2.8 bcm for the export potential of Azerbaijan requires 2007 ramping up to 6.6 bcm per year) has further clarifi cation it could be as high as become less certain after the cancellation in 15-20 bcm by 2015. Pricing issues between early 2007 by SOCAR of the supply contract the Azeri Government and BP/Statoil are with Gazprom (see Central Asian section). still to be resolved. New developments in Although in the short term, it appears Turkmenistan ( rich in gas resources and that current production does not allow already a large exporter westwards) and the Azeri gas industry (SOCAR, BP Statoil, Kazakhstan, where considerable volumes Total) to fulfi l all domestic and export of associated gas will be produced from oil requirements plus the needs of Georgia as fi eld development, mean that new volumes a transit country, Azeri and east of Caspian are likely to become available close to the gas potential still have considerable upside Turkish market (see also Central Asian in the medium to long term. Iran seems to section). have regular supply problems in winter, as gas fl ow to Turkey tends to be very low Discussions are occurring about future between December and March. gas supplies from northern Iraq including a potential LNG liquefaction plant in Exploration is at a low level; domestic Ceyhan. Such plans may need to await an production seems set to meet only a very improvement in the situation in Iraq. small part of Turkey’s gas needs. Therefore, in order to meet its own demand, Turkey has Turkey as a transit country signed eight long-term sales and purchase contracts with six different supply sources Turkey has high hopes of playing a ranging from Turkmenistan, Azerbaijan signifi cant transit role, bringing gas from and Russia to Middle Eastern and African the Caspian or the Middle East to Europe. suppliers. In addition, Turkey wants to Turkey is keen to establish new gas supply promote gas trade with potential suppliers routes, to increase co-operation among and shippers. neighbouring countries and to stimulate the integration of Turkish and European Within this framework, to meet the gas markets. increasing natural gas demand and also to diversify its gas trade portfolio, Turkey One project under construction is the plans to develop a new LNG terminal in Turkey-Greece Pipeline Project, a 300 km Ceyhan. Turkish authorities envisage that interconnector, passing under the Sea of Ceyhan will become one of the major energy Marmara. Interconnection to Italy is also hubs in the Eastern Mediterranean. being considered; transport volumes could reach 11 bcm, with 8 for Italy and the Due to signifi cant gas supply problems with balance for Greece. Iran, Turkey imported extra LNG in winter 2006/07 (1.5 bcm) through the only receiving terminal built by a private company (in Izmir) constructed in 2002 by EGE gas, but being used for the fi rst time now. Though Natural Gas Market Review 2007 • OECD Country/Region Update 228

Box 5 Nabucco

At 3 400 km in length, Nabucco is designed to link Caspian and Iranian gas supplies with eastern Austria via Bulgaria, Romania and Hungary. The consortium (-based Nabucco Gas Pipeline International) consists of Austria’s OMV AG, Turkey’s Botas, Bulgar Gas of Bulgaria, Romania’s and Mol of Hungary (20% interest each). The fi rst co-operation agreement for this project was signed in 2002, with a feasibility study completed in December 2004. Construction of the pipeline is planned to commence in early 2008, for fi rst phase completion in 2011. A fi nal investment decision is expected by end-2007. Initial throughput capacity is put at between 4.5 to 11 bcm per year with a gradual increase to between 25.5 and 31 bcm per year by 2020. During a conference of Energy Ministers held in June 2006 in Vienna, the pipeline project member countries agreed to accelerate commercial, regulatory and legal work necessary for the implementation of the project “in the shortest possible time”. Nabucco was characterized as one of Europe’s most important energy projects, one that would allow the EU to diversify both its transport routes and its suppliers. The consortium initially regarded Iran as a primary source of gas for the fi rst stage of the project and Tehran signed a Memorandum of Understanding with OMV in January 2004 to assess what role the National Iranian Gas ExportCo (NIGEC) could play in the pipeline. However, Iran’s exports to Turkey have been much lower than those stipulated in the contract and sometimes been interrupted, as noted above; currently, project sponsors have reoriented their supply priorities in favor of the Caspian, in particular Azerbaijan. Another important pre-condition for this project (and other transit projects that may arise) is clarifi cation of the regulatory regime covering transit gas, plus plans to deal with possible congestion as domestic gas use grows. Further details on regulatory issues in IEA Europe are discussed in the sections on Investment and Regulation.

Conclusions and outlook The outlook suggests a continued strong role for gas in power generation, from Acceptance by the public and by local 71 TWh in 2005, to more than 100 TWh investors of gas infrastructure is good. in 2010 and 165 TWh by 2020. Even then, Turkey now has a nationwide gas grid, this implies a lowering of the share of gas, entry points from several directions and displaced by ambitious plans to raise the some emerging supply fl exibility through share of coal and to introduce nuclear storage sites. The result is continued high power by the end of the forecast period. growth in spite of increasing global price levels. Liberalisation is progressing, but On the gas supply side, Turkey has slower than anticipated earlier. All the taken steps to diversify import sources institutions are nevertheless in place. and routes, including using spot LNG Natural Gas Market Review 2007 • OECD Country/Region Update 229

Figure 68 Nabucco project Vienna SLOVAK REP. Baumgarten Bratislava UKRAINE AUSTRIA Budapest HUNGARY MOLDOVA SLOVENIA Ljubljana Trieste Zagreb ROMANIA Chisinau

CROATIA N

Adriatic LNG A Krk Is. BU Belgrade BOSNIA- CCO HERZEGOVINA (56) Bucharest Sarajevo & JECT MONTENEGRO PRO Rome BULGARIA Sofia Skopje 2x(24) Brindisi LNG Tirana MACEDONIA ALBANIA BLUE-STREAM 0 Miles 200 Samsun Istanbul 0Km 200 Taranto Gas pipeline M. Ereglisi GREECE NABUCCO (56) Gas pipeline planned or under const. Kirikkale Nabucco pipeline Ankara TURKEY (56) Pipeline diameter (inches) LNG import terminal Izmir LNG import terminal planned Revythoussa Athens The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source:The Petroleum Economist Ltd.. markets. In addition to existing sources (Russia and Iran), natural gas is expected to arrive from Azerbaijan in mid-2007. In the longer term, Turkmenistan or Egypt could be other alternatives. Stabilisation of the political situation in Iraq would offer great potential for gas exports due to its proximity to Turkey and vast gas resources.

Natural Gas Market Review 2007 • European Regulatory Issues 231

EUROPEAN REGULATORY ISSUES

The following section is divided into two The second part is a discussion of the parts. internal regulation of gas markets within four selected member countries in the The fi rst part is intended as an illustrative North West of Europe: The United Kingdom, example of wider cross-border regulatory The Netherlands, Norway and Belgium. issues in Europe, although precise details In the context of the rapidly changing are not applicable in all circumstances. As European gas market described above, noted in the Investment chapter, cross- this area is clearly the crossroads. These border regulation is probably the largest four countries account for fi ve-sixths of single factor inhibiting investment in European production, but only a third of downstream European gas infrastructure. demand and therefore are already a large This is a major challenge for a region which, transit area (Netherlands gas movements according to the Supply and Demand are twice national gas use and for Belgium section, has to deal with a major structural transit fl ows are nearly four times domestic change in gas supply to 2015. Between gas use). Emerging LNG import hubs, (as 2004 and 2015, annual IEA European gas described earlier), will accentuate these demand is expected to grow by 111 bcm trends, as will the advance of regulatory – all of which is likely to be imported. The reform. The area is emerging as something particular investment discussed in this approaching a competitive sub European part, the expansion of a major import line market, but achievement of this potential is into Italy, is important for IEA countries to clearly dependent on regulatory policies. understand for several reasons: The overview of policies present a rich Italian domestic production is declin- tapestry of differing approaches, with ing while gas demand and import some types of investment treated more requirements are growing, being favourably in some areas, relative to others. driven by power demand growth. The For example, low transport tariffs in the required investment in infrastructure Netherlands may favour transit through as a result of this structural shift can be that country, even if it is not necessarily seen as illustrative of the investment the best route. Uncertainty fl owing from requirements in the wider European legal challenges complicates an already context. fragmented regulatory picture. It seems clear that these approaches will certainly The current lack of consistent and not make large scale cross border transport stable regulatory powers or oversight of gas easy, cheap or quick to achieve. for cross-border investments between European countries and the resultant uncertainty is illustrated. Cross-border regulatory issues in Europe: Italian example The general lack of experience in conti- nental Europe concerning expansion The Italian gas market faced severe supply of pipeline capacities on a competitive diffi culties in winter 2005/06 forcing basis is highlighted. the Italian government to declare a “Gas Natural Gas Market Review 2007 • European Regulatory Issues 232

Emergency” just before Christmas 2005. As 2005/06. Nevertheless, the experience of a reported in the GMR 2006, this situation “gas emergency” has convinced the Italian was brought about because of a severe government of the importance of providing and prolonged cold winter which increased information to market participants. Physical demand for gas heating and for power fl ow information is now available to the generation. Less reported is the effect of market, by pipeline, on at least a monthly the high European power market prices. basis for all entry and exit points on the High power prices gave the Italian gas-fi red Italian system. generators fi nancial incentives to produce power for export – effectively therefore, Observation suggests that Italy’s gas market Italy exported large volumes of gas in can not be described as “competitive” or the form of power (usually for peak load). “liberalised”. In competitive liberalised Because there is no meaningful competition markets, capacity use is optimised based within the Italian gas market and gas on supply and demand fundamentals. prices are fi xed to oil, not responding to There is 100 bcm of physical entry capacity demand fundamentals, the gas price did into Italy which could be used for imports, not increase in response to gas supply but total imports were 73.5 bcm in 2005 tightness – an increase which would have and 77.4 bcm in 2006 despite the gas lowered industrial and generation demand emergency. Physical entry capacity to as seen in the United Kingdom in winter the Italian grid is underused because it is

Figure 69 Under-utilisation of Italian import capacity

120 120

110 110

ts (bcm)

100 100

t capacity (bcm)

Italian impor 90 90

80 80

Italian impor

70 70

60 60

50 50

40 40 2000 2001 2002 2003 2004 2005 2006

Source: IEA data & GIE capacity data. Natural Gas Market Review 2007 • European Regulatory Issues 233

tied to long-term contracts which cannot on this link is “contractual” rather than respond quickly to unforeseen demand. physical. A precise analysis of transit fl ows is A relatively mild winter in 2006-07 has not possible because of the lack of data and masked the problem, but new capacity the lack of regulatory control of a pipeline is only due online after 2008 (and only which spans two countries. then in small quantities). The Italian gas market is therefore likely to remain tight TAG is operated by a private company and unless existing capacity is made available its operations are not regulated because it to market players with available supply. falls into the regulatory gap between Italy In addition, Italy has only one operating and Austria. Under Austrian regulatory LNG terminal, with delays slowing other rules, capacity allocation, congestion terminal developments. management and related disclosures are matters for the transit companies. A major import pipeline from Austria can Nevertheless, on 6 December 2005 the provide an illustrative example of some Italian and Austrian regulators met to of the challenges to Italian policy makers discuss the congestion on TAG gas transit if they are to optimise import capacity system, which was said to pose a threat to to Italy. This example is indicative of a competition development and electricity wider problem in Europe with regards to and gas supply security in southern Austria, several key aims of the internal market Slovenia and Italy. They concluded that it – to increase cross border investment, was likely that inadequate unbundling of provide security of supply and to promote ENI’s transportation arm was one of the competition. principal reasons, as the dominant Italian gas company, ENI has majority control of Import capacity investment: the the TAG company. TAG pipeline as a lesson for Europe? The lack of competition on this route was The TAG gas pipeline is the Austrian stage the subject of a settlement21 between ENI, of the pipeline system which links Russia, Gazprom and the EC, as a result of which Ukraine, The Slovak Republic, Austria ENI undertook to promote an increase of and Italy – and is therefore an extremely the capacity in TAG between 2008 and important source of gas imports for Italy. 2011 depending on certain Italian market Capacity on the TAG pipeline is almost 100% developments. booked on long-term contracts as is usual for older infrastructure in Europe, however As in many European countries, rather historic capacity utilisation statistics are than hold an “open season” to determine not published. As with many other cross- potential shipper interest, TAG ran a border points in Europe, the congestion long-term allocation procedure. An “open

21. In 2003 the European Commission’s competition services reached a settlement with the Italian oil and gas company ENI and the Russian gas producer Gazprom regarding a number of restrictive clauses (essentially destination clauses) in their existing contracts. The settlement of the Gazprom/ENI case is very signifi cant because of the large volumes of gas involved. ENI is one of the biggest European customers of Gazprom accounting for 20 bcm per year. Natural Gas Market Review 2007 • European Regulatory Issues 234

season” procedure has been successfully 3.3 bcm per year. Some 34 enterprises from 9 used to build and then later to expand the countries took part in the auctions. Clearly, capacity of the Interconnector between a transparent, market-based process should the United Kingdom and Belgium and is be used in order to determine required also a standard market-based mechanism capacity on interconnections so vital for used as the basis for investment in pipeline security of gas supply. capacity in North America (e.g. for the USD 3 billion Rockies Express pipeline, see Observations below point clearly to the North American section). key issues facing the Italian government and regulator: The allocation procedure used by ENI The major incumbent supplier (ENI) owns was based on many smaller capacity lots the system and has contracted almost than usual in an open season procedure. all transportation capacity on a long- According to available information, Gazprom term basis, with very small quantities proposed at an early stage to introduce left for the operational companies. This eligibility restrictions, such as ownership of places signifi cant risk for Italian gas existing gas supply contracts or suffi cient users with one party who might not fi nancial resources, in order to prevent such have the appropriate supply to meet a fragmentation of the market. However, their demand at the right time. no such requirements were imposed. It is noteworthy that although the auction Transportation capacity is only released took place in Austria, neither the Austrian at the discretion of the incumbent nor the EU regulatory authorities acted as over short periods, mostly during the its organisers. The bidding was organized summer months. Capacity bookings by ENI. from shippers not registered in Italy are not accepted and standard agreements Italy’s Authority for Electric Energy and for periods shorter than one year Gas (AEEG) and its Austrian counterpart are not available. That new market E-Control objected to this allocation of participants cannot plan a business pipeline capacity on the grounds that around capacity availability severely it breached EU directives. In particular, discourages potential new entrants and undermines optimisation of the the authorities were opposed to the way existing infrastructure. ENI ‘fragmented’ the additional October 2008 transport capacity by assigning it Neither regulator from either Italy to 149 operators from 10 countries, each or Austria exercised competence to with about 20 mcm per year of capacity. oversee allocation of capacity to third “ENI prefers to fragment the market” an parties on this crucial gateway to the authority spokesman noted at the time. market. Thus new pipelines between the two countries are “unregulated” At the end of June 2006 TAG was fi nalising for practical purposes. Companies not the contractual conditions with the win- subject wholly to regulation of one or ning bidders of the 21 June 2006 online other country therefore fall through auction of the second capacity release of the regulatory gap. Natural Gas Market Review 2007 • European Regulatory Issues 235

The release or allocation of international enhancement far outstripped the supply. capacity is not co-ordinated with the However, commercial pressure did not release of necessary entry capacity into bring about the actual investment that the SNAM RETE gas system, the Italian consumers clearly needed; it was only national grid controlled by ENI. a result of the EC settlement discussed above that any steps were undertaken. Summary The way that the enhancement was made however, resulted in underinvestment on Pipeline regulation is relatively new to many behalf of the Italian (European) consumer. European countries, where downstream An “open season” process involving infrastructure should now be regarded as shippers making long-term commitments a natural monopoly and separated from to capacity would have enabled the market, the competitive business of gas supply. As rather than the incumbent, to determine evidenced by the Italian problems in winter the required level of investment. It is clear 20005/06 which may well occur again in the that such enhancement should be subject next cold winter, there is a fundamental to reasonable pre-qualifi cation conditions, shift in the supply/demand balance across to prevent small volumes of available Italy which could be used as a model capacity being spread over many parties. for Europe. Despite the overwhelming It is also clear that regulators can learn a economic case for investment in new lot from this experience. infrastructure, the commercial incentives to invest are blurred. In the Investment section, we noted that: Internal regulation of gas markets in North West Europe “Within Europe, but across several countries there is an even greater [invest- This section covers regulatory develop- ment] problem, which is that there is no ments in four North West European harmonisation of regulatory structures countries over the last decade or so. It within the region, nor a European regu- is organised by theme rather than by latory body. This means that a project country, to allow the reader to more to build a gas pipeline between two directly compare relevant topics across countries might be profi table on one side countries. The discussion provides in- of the border but not on the other. Even sights into how regulation is affecting if it were profi table at all, such a pipeline investment, through creating unnecessary faces formidable obstacles to be built in uncertainty, how liberalised markets can the current environment because of a lack create incentives for investment and of timely regulatory decisions. Pipeline how markets can adapt in the presence of projects which must cross several European pseudo-monopoly incumbents. countries face considerable regulatory risk and uncertainty if they are to proceed.” More information is available in recent IEA publications: Energy Policy Reviews of; In the example of the TAG allocation, Netherlands (2004); Belgium (2005); Norway it is clear that the demand for capacity (2005) and United Kingdom (2006). Natural Gas Market Review 2007 • European Regulatory Issues 236

United Kingdom: The Department of Trade and Industry (DTI) industry organisation has the primary responsibility for energy policy goals and setting the framework In 1996 the Network Code was implemented which delivers them. DTI’s role is to set out providing common terms for all shippers a fair and effective framework in which to access the gas transportation system competition can fl ourish for the benefi t of and thereby compete in the retail market. customers, the industry and suppliers and By 2001 the former integrated monopoly, which will contribute to the achievement British Gas, was privatised and had become of the United Kingdom’s environmental three separate companies – a network and social objectives. The Secretary of company (Transco); a downstream gas State for Trade and Industry is primarily supply company (Centrica) and an upstream responsible for the development of the production company (BG Group). The gas United Kingdom’s natural gas resources, transmission system and four of the eight holding authority to licence and regulate distribution networks are now owned and gas production and the associated off- operated by National Grid; the other four shore gas industry. previously owned by National Grid, were sold to three other organisations in 2005. Transmission and distribution network businesses are regulated by Ofgem, the Offi ce of Gas and Electricity Markets. It

Figure 70 United Kingdom gas industry organisation

Policy: government

Shareholders: Shareholders: private & institutional private & institutional

Grid owner Grid owners and operators: & TSO: 3 distribution companies Producers National Grid & National Grid Shareholders: private & institutional Distribution Customers Gas fields distribution grids Transmission grids grid Import (pipelines), Customers LNG import, transmission grid storage

Regulators: Power plants, large DTI/Ofgem Ofgem industry, export Shippers / traders / suppliers Natural Gas Market Review 2007 • European Regulatory Issues 237

is directed by a board whose members are integration of the North-West European appointed by the Secretary of State. Ofgem gas market and further developing the is funded by the energy companies that Netherlands as a gas hub by attracting are licensed to run the gas and electricity gas fl ows and related investments. The infrastructure. Netherlands Competition Authority (NMa) has been given the status of an auto- The Gas Act provides for a licensing frame- nomous agency, fully independent from work for gas transportation companies, the government. Also the powers of the interconnector operators, shippers and NMa are enhanced as it can impose fi nes. suppliers. To be granted a gas transport Notwithstanding its independent charter, license a company must meet several the NMa is funded with the budget of the obligations, such as being independent Ministry of Economic Affairs. from other functions (production, supply, etc.), satisfying reasonable demand (so The directorate DTe of the NMa (NMa/ far as is economical), developing and DTe) is the energy regulator. For gas maintaining an effi cient system, not transmission and distribution the Gas undertaking transactions that create a Act introduces regulated third party cross-subsidy with another entity and access (TPA). The NMa/DTe regulates the being able to meet 1 in 20 peak day demand. activities of the network operators on the It also must sign up to the Network Code, basis of cost-plus. Article 22 EU Directive to the approval of Ofgem. 2003/55/EG exemption from regulated tariff structures and access conditions is Ofgem is, under the Utilities Act, responsible possible under specifi c circumstances. The for the oversight of Wholesale and Retail Ministry can relieve a network owner from markets and monitors the behaviour of the requirement to appoint a network licensees in them. Unlike most European operator. It can also exempt large, new regulators, under the Competition Act, cross-border transmission grids, LNG- Ofgem is also a formal competition auth- installations and storage from regulation. ority for the electricity and gas sectors. Grid owners have to appoint a network This function – competition oversight – is operator, this appointment is subject to becoming increasingly important in more Ministerial approval. liberalised markets. N.V. Nederlandse Gasunie (Gasunie), the Netherlands: industry organisation Dutch gas transport company, is owned by the Ministry of Finance. Gas Transport The Ministry of Economic Affairs is respons- Services (GTS), the gas transmission ible for energy policy in the Netherlands system operator (TSO) that operates – a legacy of the important role of state the gas transmission grid owned by participation in the development of the Gasunie, was founded on 2 July 2004. It is very large Groningen fi eld in the north a 100% subsidiary of Gasunie, operating of the Netherlands. As liberalisation has independently as required by law. The TSO taken wing, the government now focuses is not allowed to carry on activities by on diversifying gas supply, enhancing which it would compete with other market Natural Gas Market Review 2007 • European Regulatory Issues 238

players, except if the activities are part of An extra dimension of this arrangement is its legal tasks. The trading division of the that the state, producers and GasTerra have former Gasunie, GasTerra (owned by Shell, agreed to prolong the life of the Groningen Exxon Mobil (25% each), EBN (40%) and fi eld by encouraging production of other, the Ministry of Economic Affairs (10%)), more expensive fi elds (‘small-fi elds policy’, has been legally and fi nancially separated; codifi ed in the Gas Act). The gas from the ownership unbundling took place on small fi elds is high calorifi c gas and the 1 July 2005. properties vary signifi cantly. GasTerra has the obligation to offtake the small fi eld The government is highly represented gas on reasonable conditions. This can be in the structure of the upstream gas seen as the corollary of exclusive access to market. While NAM has a 60% stake in the Groningen gas. The operators of the small Maatschap Groningen, the state holds the fi elds are guaranteed a market based price remaining 40%. In this partnership they for their gas. Pursuant to the Gas Act GTS each have 50% of the voting rights. The has to develop connection points for the Groningen fi eld is operated by and for the intake of small fi eld gas. benefi t of the Maatschap. The partnership agreement stipulates that the Groningen During the last 40 years the small-fi elds gas must be marketed via GasTerra; its policy has been executed to preserve the annual profi ts are capped, with the rest of unique fl exibility of the Groningen fi eld, the pre-tax profi ts going to the Maatschap. which is enough to cope with seasonal

Figure 71 Netherlands gas industry organisation

Policy: government

Shareholder: state

Shareholders: Shareholder + grid Shareholder + grid owner: Shell, Exxon Mobil owner: Gasunie distribution companies

Other producers Distribution network Owner and operator: NAM TSO: GTS operators

Customers Shareholders: Gas fields Distribution Transmission distribution grids state, Shell, grids grid ExxonMobil Storage, Customers import (pipelines) transmission grid

GasTerra Regulator: NMa/DTe Power plants, large industry, export Shippers / traders / suppliers Others Natural Gas Market Review 2007 • European Regulatory Issues 239

demand variations in the Netherlands industry in Norway, which is the main and also in the wider European context reason for the active government (especially Germany). It provides swing, involvement. The Ministry of Petroleum which enables the small gas fi elds to produce and Energy (MPE) is responsible for energy at rather constant rates. Nonetheless, policy to ensure the best possible use of compression capacity has been installed the country’s natural resources. It is also in and will have to be expanded; the natural charge of the overall license award process. pressure of the Groningen fi eld has already In connection with offshore operations, declined by about 50% and the production the MPE develops and administers capacity is falling further. As operational treaties covering fi elds and transport costs of the Groningen fi eld increase, local systems which extend beyond Norway’s storages will become more economic (and boundaries. The Norwegian Petroleum necessary) to balance seasonal demand. Directorate (NPD) is the regulatory agency in this area. The NPD is an independent Gas revenues represent a signifi cant part state administration body reporting to of government income. The government the MPE. has protected domestic resources by controlling the depletion of the Groningen The NPD was established by the Storting fi eld using a production cap, maintaining (parliament), which determines the legis- the small fi elds policy and promoting lative framework for the energy sector. imports. The Netherlands imported 23 bcm Major development projects or issues of in 2005: 13.3 bcm from Germany, almost principle must be considered and approved 7 bcm from Norway and some 2.8 bcm from by the Storting. Unlike parliaments in Belgium. The formerly applied indirect other countries, the Storting is involved ceiling on Groningen production has in energy-policy making to a considerable been replaced by a specifi c cap. However, detail, refl ecting the importance of energy market liberalisation now demands a resources to the economy and the concern policy review. The offtake guarantee gives about the environmental impact of energy producers reduced incentives to adapt the use. production profi le to market demand. The Groningen gas and the small fi eld offtake Market oversight is provided by the keep GasTerra in a stable market position. general competition regulator, the A specifi c policy is needed to encourage Competition Commission, but there is small fi elds production; a liquid market no independent regulator. Despite this, also gives a guarantee to producers that Norway has achieved a degree of balance they can sell their gas. through collective ownership of the majority of offshore pipeline networks Norway: industry organisation while regulatory responsibility for the gas industry lies within the MPE. The Norwegian state owns the petroleum resources on the NCS and has the authority was established by the Ministry of to manage and control exploration and Petroleum and Energy on 14 May 2001 as production. Petroleum is the largest a wholly state-owned limited company. Natural Gas Market Review 2007 • European Regulatory Issues 240

Figure 72 Norway gas industry organization

Policy: government

Shareholders: Shareholder: state state, others Other producers Grid owners: as owners producers & operators

Owners & operators: Other network Export, power plants, Statoil, Norsk Hydro TSO: Gassco operators large industry, distribution

Gas fields Offshore network Customers

Regulator: government Shippers / suppliers (producers)

It took over the operation for all gas Belgium: industry organisation transport from the Norwegian continental Energy policy responsibilities are split shelf on 1 January 2002. Before that date, between the federal and regional gas transport was provided by a number of governments. The federal government companies. The creation of Gassco forms is responsible for issues such as security part of an extensive reorganisation of the of supply, gas tariffs and network Norwegian oil and gas sector since 2001. regulation for large infrastructure for storage and transmission. Energy policy Establishing Gassco has satisfi ed the aims at enhancing gas market reform requirements for ownership of gas and diversifi cation. Gas transportation transport operations in the European gas companies and suppliers must hold a licence market specifi ed in the European Union’s from the federal Minister responsible for gas directive, however the issue of energy policy. The regional governments establishing a regulator to manage Third of Flanders, Wallonia and Brussels-Capital Party Access has not been addressed. While are principally responsible, among other common ownership of the system ensures things, for regulation of distribution and that the gas is transported with maximum supply. The federal government and the effi ciency, there may be questions as to three regional governments have created the independence of the pipeline system an advisory body for discussions on all especially given the state interest in energy matters transferred to the regions. production activities on the NCS. The Belgian regulator, CREG, is funded by a surcharge on customer utility bills and is therefore fi nancially independent from the Natural Gas Market Review 2007 • European Regulatory Issues 241

government. However, CREG commissioners the minister rather then given statutory are appointed by the government. The power. Further, the General Council (rep- general function of CREG is to ensure that resentatives of the gas market and the market players comply with the relevant government) monitors the work of CREG laws and decrees. It monitors the natural and may also give advice to the regulator gas market and is currently responsible for and the government. The responsibility for price setting in the “captive market”, that developing long-term indicative invest- will open to competition in July 2007. CREG ment plans lies with the government in has powers to approve access conditions collaboration with the Federal Planning and tariffs for transmission, distribution Bureau, after consultating CREG, unlike and connection as well as other regulated in the United Kingdom, Netherlands and assets; a special tariff structure applies to Norway where it falls under the remit of transit, storage and LNG. It fi xes tariff rates the separate pipeline network operator. over four years (as from 2007) and must The indicative plan covers ten years and is guarantee an equitable profi t margin to the revised every three years. operators of regulated assets. For specifi c facilities the law provides for an exemption Owing to the federal structure of Belgium, from the normal tariffs, allowing for it was the responsibility of the regions potential market abuse. to decide on their rate of local market opening, though all must be open by July The independence of the regulator is an 2007 under EU rules. The regional Gas issue in Belgium. Not all the regulators Decrees provide for regulated third party decisions are binding – CREG assesses access in their own region. Distribution applications for transportation and supply tariffs, proposed by the distribution grid licences but is only charged with advising managers, are subject to approval by the

Figure 73 Belgium gas industry organisation

Policy: government

Shareholders: Grid owner & Grid owners & operators: Suez, Publigas, TSO: Fluxys distribution companies state, others

Customers Import (pipelines) Distribution Transmission grids distribution grids Storage, grid Customers LNG import transmission grid

Distrigas Regulator: CREG Power plants, large industry, export Shippers / traders / suppliers Others Natural Gas Market Review 2007 • European Regulatory Issues 242

federal regulator which is, itself, subject to (57.25%) in both Distrigas, the dominant approval by the government. Suppliers at gas supplier and Fluxys, the gas pipeline the federal level must hold a supply licence operator. The regional utilities (as Publigaz) from the Minister of Energy Affairs, or own 31.25% while 11.5% is currently listed from the regional authority. New entrants on the Belgian stock exchange (Euronext have begun to emerge, but Suez-owned Brussels). The federal government retains companies continue to dominate, with a a preferential golden share, designed to 95% market share in 2005. allow it veto power if the objectives of federal energy policy may be compromised In the liberalised parts of the natural gas by the actions of the company. Distrigas is market, prices are not regulated, but the involved in gas import, trade and supply Ministry of Economic Affairs can defi ne (including LNG) and supply of some transit price ceilings. As discussed earlier, the capacity for a limited time from now. Suez retail prices do not follow the price of the and Publigaz have only recently agreed Zeebrugge hub, so cannot be said to be that Distrigas is to withdraw from transit determined by the gas market. For captive activities – which it will sell to Fluxys customers uniform gas prices are set by (another Suez company). the federal government. CREG proposes tariffs that are subject to approval by the United Kingdom: midstream Ministry of Economic Affairs. National Grid has two roles: as asset Cross-subsidies between energy products owner it is responsible for developing and and consumer groups are not allowed. maintaining the transmission system; as However, several subsidies remain: a fund for system operator it has the obligation to heating oil provides rebates to low-income operate the system in an effi cient and safe heating oil customers during periods of manner. Prices for use of the transmission high prices, foreclosing increased gas use system are regulated, refl ecting the in households. According to a 2001 study, relatively low risk environment. However, 43.1% of Belgian households heated their the business of the system operator faces homes with heating oil, 44% with natural more uncertainty due to the complexity gas. Oil provided nearly 40% of energy and exposure of its (daily) tasks. Hence needs in the residential/commercial sector Ofgem applies two types of regulation. in 2004, a high fi gure. In addition, different As grid owner, National Grid earns a rate taxation levels for different classes of of return to encourage effi cient business customers function as cross-subsidies. conduct. The rate control is based on a formula to set the level of allowed The national gas transmission grid is revenues. As system operator, National operated by Fluxys, the unbundled trans- Grid faces seven output incentive measures portation company of former monopoly from which it may gain or lose dependent Distrigas. After the legal separation in on performance. Broadly the different 2001, the two companies still have the incentive schemes can be classifi ed into same shareholder structure. Suez, a French investment incentives and day-to-day energy company, has a majority stake operating incentives. Natural Gas Market Review 2007 • European Regulatory Issues 243

Price auctions of entry capacity on the Netherlands: midstream transmission system were introduced by Ofgem in 1999. Of the maximum physical GTS manages the national gas trans- capacity at each entry point (the “baseline”), mission network including international National Grid must offer 90% to the interconnections as an entry / exit system market through auctions. Long-term entry and facilitates network access on a fi rst capacity auctions generate estimates of come, fi rst served basis. It also operates value which give National Grid investment the LNG peak-shaving installation. The signals. While National Grid is not required basic gas transmission activities of GTS to build all of the incremental capacity bid – gas transport and ancillary services like for in the auctions, its price control does quality conversion, as well as connection to give incentives to invest and to maximise the grid – are regulated by the NMa/DTe. the technical availability of its network. Regulated TPA was introduced on 1 July 2004 by the amended Gas Act. The NMa/ Ofgem can give interconnector operators DTe verifi es the compliance of network exemption from the TPA obligations under operators to their legal obligations, e.g. the Gas Act for interconnectors if such to have suffi cient transportation capacity access is not necessary for the operation of available. GTS has to provide the NMa/DTe an economically effi cient gas market and, with a ‘quality and capacity document’ in the case of new facilities and signifi cant every two years, in which it assesses the increases in capacity, where various other capacity requirements and shows how criteria (such as the enhancement of these will be met. security of supply) are satisfi ed. In deciding whether to allow an exemption, Ofgem will The Nordstream pipeline, planned for consider participants’ market share and any completion in 2010, is intended to concerns over capacity-hoarding; it may transport gas from Russia (Baltic Sea) also attach conditions to the exemption. directly to Germany and perhaps onwards to the Netherlands (further details in National Grid produces a report every section on Germany). European TPA rules year which projects expected supply and will not apply on the grounds of increasing demand ten years into the future. The fi fth security of supply and on the grounds that such report, “Gas Transportation Ten Year the project is too risky otherwise. Statement”, was released in December 2006. In it, National Grid forecasts likely domestic In an open season, GTS established long- demand, domestic production and imports term shipper commitments for especially from existing, under construction and entry capacity in the northeast of the planned pipelines and LNG import facilities. Netherlands and exit capacity in the In the ten year statement, it projects that southwest, anticipating westerly fl ows the country’s import dependence will from Nordstream. To accommodate these grow to 53% by 2010 and to 77% by 2015, transportation requirements GTS has notwithstanding lower demand growth proposed investments of approximately from higher prices. Growth in gas import USD 1.5 billion to the NMa/DTe. GTS has infrastructure is forecast to meet this need. requested comfort on the conditions under Natural Gas Market Review 2007 • European Regulatory Issues 244

which investment is taken into account in revenue has to decrease. This aims at the regulated asset base (RAB). The NMa/ reducing tariffs on existing assets but is DTe has concluded in a so called “informal clearly detrimental to investment in new view”, which is not binding on the NMa/ infrastructure while GTS is not encouraged DTe, that the current transport capacity to expand services and sales. on the high calorifi c network insuffi ciently safeguards future supply security, but GTS has challenged the regulations in that an investment of USD 900 million is court, arguing that tariffs should rather required to safeguard supply security for be based on benchmarking, taking into Dutch consumers. This informal view does account the international context. On not provide the comfort asked for by GTS. 30 November 2006 the Dutch court The fi nal outcome of the open season is annulled the regulation, stating that the still unclear. regulator had developed a revenue-based methodology rather than the services- Dutch tariffs are among the lowest in based one, as stipulated by the Dutch Europe. The NMa/DTe has obliged GTS to Gas Act. The Ministry of Economic Affairs lower its gas transmission rates every year is working on new legislation to create by 5% (nominal) from 2002 to 2006. There certainty for both networks users and is a fear that “cheap tolls” will make the investors in extra transport capacity. Netherlands the “highway” for European gas fl ows north to south at the expense Belgium: midstream of the domestic use of the grid. Suppliers and large consumers are responsible CREG has set a condition that the gas for the contracting of suffi cient trans- network should be expanded in every case mission capacity, but they may tend to where it is necessary to meet reasonable underestimate the risks of being too late market demand. Network development in contracting. In July 2006 the NMa/DTe to meet inland consumption should not obliged GTS to reserve domestic exit require long-term commitments from capacity for this reason. GTS considered shippers. this a disregard of European law and an unlawful attempt to limit the effect of The Belgian Gas Act stipulates the artifi cially low tariffs and accordingly fi led appointment of a single transmission a lawsuit. system operator. Fluxys owns and operates the transmission grid on the basis of The NMa/DTe established a tariff structure an “enhanced entry/exit system” and, for GTS in 2005. Its calculation of the since November 2002, regulated third- revenue that is allowed on the RAB is party access (TPA). It offers capacity and based on a cost-plus methodology with a fl exibility services at regulated tariffs. In revenue cap rather than a rate of return 2006, 74 bcm was transported through the as in the case in the United Kingdom. The Belgian transmission system. Over 77% NMa/DTe also defi ned the method to be of this quantity, 57 bcm, was destined for used to calculate an effi ciency rebate: international transit. Only 17 bcm was used a percentage by which annual allowed for consumption and storage in Belgium. Natural Gas Market Review 2007 • European Regulatory Issues 245

The total transmission and transit capacity by Fluxys. It also asked Fluxys to submit a of the Belgian system is about 80 bcm per proposal for new gas transit regulation. year. CREG wants a new entry / exit system to the Belgian network, with a single Capacity is allocated by applying the fi rst balancing zone corresponding to one set come, fi rst served principle. Conditions of gas quality specifi cations instead of the and tariffs are proposed by Fluxys and current four; it also wants to have enhanced have to be approved by CREG on a service- access to transmission capacity, to the by-service basis. The system used by Zeebrugge Hub and to storage facilities. CREG to calculate tariffs that Fluxys is CREG also recommends that any (physical or allowed to charge its customers is based contractual) separation between transit and on reasonable costs and a fair profi t domestic transmission should be avoided as margin. Fluxys introduced a secondary this is irrelevant in an EU context. market in 2006 by providing a platform to offer transportation services. Shippers In June 2005, Fluxys sent out an information are legally obliged to make available on request to appraise the market interest the secondary market the fi rm transport for long-term transit capacity to the capacities which they no longer require United Kingdom. As part of the indicative for a specifi c period or permanently. investment program for 2006-2015, Fluxys approved the decision to increase the CREG sets a weighted average cost transmission and transit capacity on the of capital (WACC) on a yearly basis, Eynatten/Zelzate- Zeebrugge (VTN2) east- representing a maximum return on Fluxys west axis which includes the construction investments in regulated activities. This of a compressor station in Zelzate. WACC is then multiplied by an asset This compressor station will enhance value (the regulated asset base, “RAB”) to operational fl exibility of the grid and arrive at the profi t before tax that Fluxys boost supply from the north. Work began is allowed to earn. The value of assets in 2007 and the station is due to enter assessed to earn this WACC is based on a service for the Belgian market in mid-2008. replacement value of the asset portfolio VTN2 also includes work to lay a second adjusted for investments or divestments pipeline on the Eynatten-Zeebrugge axis and working capital. On the basis of 2006 between Eynatten and Opwijk to increase the WACC was set at 7.05% and the supply capacity from the east. Enhanced RAB amounted to USD 1.1 billion for the capacity in the direction of Zeebrugge transportation business. For storage and would enable liquidity growth on the terminalling the WACC was set at 7.5%. In Zeebrugge Hub. Alongside the Fluxys addition to this return on existing assets, project, a parallel initiative has been taken Fluxys is allowed to pass through the costs in the Netherlands to attract more gas of operational expenditure incurred while fl ows from the east and north. maintaining the network. Currently capacity on the VTN/RTR In September 2006 CREG opened a consul- pipelines, linking the United Kingdom tation on the access conditions offered with the Netherlands and Germany, is all Natural Gas Market Review 2007 • European Regulatory Issues 246

contracted by Distrigas (Suez) on a long- Norway: transmission pipelines term basis, meaning that it controls the bridge between the largest European gas The MPE actively promotes measures to markets and their closest suppliers. Segeo increase the number and diversify the s.a. (Fluxys stake 75%, Gaz de France 25%) types of companies active on the NCS. On owns the gas transmission infrastructure 1 January 2007 the regulations relating to between Gravenvoeren and Blaregnies. area fees changed. The main rule of the These pipelines are referred to as “transit” new provisions is that no fee will be paid pipelines because of the original function for areas with ongoing exploration and of transiting gas across Belgium and there production, while areas without activity were arguments that this exempted the will pay a higher fee than before. The pipelines from the EU TPA rules applicable purpose is to encourage licensees to speed to domestic networks. The European up exploration in licences which are on Commission does not recognise transit as hold, or to cede them to the state in order being separate from transmission within to give other companies a chance. the EU. Pursuant to EU regulation both of these activities are transmission within Gassco administers the regulated third party access (TPA) regime which applies Europe and therefore subject to the same to gas pipelines on and from the NCS regulated TPA principles. and related installations. It is responsible for allocating capacity; the production By marketing transit capacity, Distrigas acts companies’ access to capacity in the de facto as transmission system operator. system is based on their needs for gas On 14 September 2006, the regulator transport. In order to secure good resource decided that this was unlawful. Just before management, booked transport rights can the decision of CREG, on 8 September, Suez be transferred on the secondary market and Publigas had announced their intent to between shippers. As the system is a propose a transfer of Distrigas natural gas natural monopoly, gas transport tariffs transit business to Fluxys. CREG ruled that are governed by special regulations issued the unlawful situation must be resolved by the MPE. The cost-based transportation by 31 December 2006. The transit capacity tariffs are subject to MPE approval. A must be passed to Fluxys; the access rules maximum rate of return in new pipelines would be the same as those applying to is generally specifi ed. The regulations transmission as from 1 January 2007. ensure that the economic returns are The same had been decided for access earned from producing fi elds and not from capacity to and from the Zeebrugge Hub the transportation system. Tariffs are (regarding the Zeepipe terminal and the based on an entry/exit methodology. The Interconnector terminal). On 21 December system is divided into fi ve entry/ 2006 Fluxys announced that Distrigas exit areas, depending on the gas quality or had commissioned Fluxys to handle, in the processing terminal. the name and on behalf of Distrigas, the management and marketing of its transit Gassco is responsible for the maintenance capacities in Belgium as of 1 January 2007. and the further development of the Natural Gas Market Review 2007 • European Regulatory Issues 247

upstream network. It makes independent supply capacity would be more than assessments and recommendations for twice peak demand by 2010. In mid-2006 infrastructure development. Gassco National Grid identifi ed eleven gas storage presents investment proposals based on projects in some stage of construction or an overall assessment of development development. They are all planned to come needs and resource management. Getting on-line by 2010 and would add 5.7 bcm to these approved will depend on the the existing storage capacity of 4 bcm. In willingness to invest by owner companies May 2006, the Secretary of State issued and resource owners. Gassco develops the a statement addressing the urgency of annual transport plan, an annual rolling 10- new infrastructure with specifi c focus year transport plan based on information on storage facilities. He announced three provided by the respective stakeholders. measures: establishment of legislation to allow innovative projects (e.g. gas storage United Kingdom: storage in offshore salt caverns and LNG projects with offshore unloading) to go ahead, a Import facilities and storage capability review of onshore consents regimes and must be suffi cient to meet the winter improvement of public understanding of peak. The maximum demand seen in the the need for new infrastructure. Storage winter of 2005/06 was 411 mcm per day. As projects are also deterred by the diffi culties a signifi cant producer of gas, much of this in converting production licenses to fl exibility used to be provided by increasing storage licenses for offshore fi elds, an issue or decreasing offshore production as being addressed by the government. demand required. As the fl exibility from domestic fi elds is now insuffi cient to Belgium: storage meet peak winter demands, seasonal storage units will indeed play a crucial role. Belgian law stipulates that the seasonal Existing storage peak withdrawal capacity capacity is reserved for shippers supplying amounts to about 120 mcm per day. the domestic market. Fluxys stores gas in an The recent large discrepancies between underground storage in Loenhout. It is used winter and summer prices (e.g. spot and by three parties. CREG has recommended futures prices in Summer 2006) provide a that the storage capacity at Loenhout strong market incentive for more storage be increased. In 2005, Fluxys decided to plants to be built and a number of private carry out a gradual enhancement by 2011- companies have made plans to do so. 2012. In June 2006 Fluxys and Gazexport, However, these plans have been hampered a subsidiary of Gazprom, agreed to jointly to a great extent by local opposition and a explore the underground gas storage general failure to gain planning consents possibilities in Poederlee. Fluxys also has – especially offshore, where there are agreed to co-operate with VITO to explore many responsible agencies. other potential storage sites in Belgium and in neighbouring countries. A major factor deterring storage investment is that, if all proposed import and storage projects went ahead, peak Natural Gas Market Review 2007 • European Regulatory Issues 248

United Kingdom: LNG Belgium: LNG

LNG import facilities are subject to a In the transitional regime, Fluxys has regulated TPA regime, meaning that non- been appointed as transport/transit and discriminatory terms of access must be storage operator and Fluxys LNG for LNG- published and pricing methodologies terminalling. In 2007, the procedure will be must be approved in advance by Ofgem. launched to appoint a single transmission The fi rst operating LNG import terminal system operator on a defi nitive basis for (at the Isle of Grain) has been exempted a 20 year period. CREG sets a weighted from TPA requirements. Other LNG average cost of capital (WACC) on a yearly projects have also applied for exemptions. basis, representing a maximum return on While this at fi rst appears contradictory to Fluxys investments in regulated activities. United Kingdom open market philosophy, For storage and terminalling the WACC the government seems to have taken the was set at 7.5%. approach that the more competitors in the market the better. From 1 April 2007, a new multi-shipper environment was created at the LNG terminal. In 2007 an open season will be It seems logical that some facilities launched to assess the interest of the are exempted from EU TPA regulations market in additional terminal capacity as designed to increase competition, on the the pre-feasibility study is positive. grounds that other forces are providing the same outcome. The third-party-access Netherlands: LNG exemptions will result in the following market parties obtaining LNG regasifi cation The Ministry and the NMa intend to allocate capacity in the United Kingdom (many of initial capacity to LNG terminals through which are new to the wholesale market); an “open-season process”. There are two Sonatrach, Centrica, Gaz de France, proposals: The LNG company can choose Excelerate, Petroplus, BG, Petronas, Qatar to create extra capacity through a larger Petroleum, ExxonMobil and Total (see LNG LNG terminal, or the available capacity section for further details). can be shared on a pro rata basis by the market parties. Long term-contracts can This should be contrasted with the be exempted for the duration of the period situation in some other European count- up to the breakeven point (‘’investment ries where a dominant supplier in an horizon’’), which the NMa assumes to be uncompetitive market might wish to approximately 15 years. build an LNG terminal. In this case it is more logical that TPA rules apply and the To prevent the hoarding of capacity, supplier is forced to make a proportion of unused capacity should be offered to the capacity available to new entrants, or third parties through a secondary market that open season procedures apply. mechanism. The time that a certain slot needs to be released on the secondary market can be neither too far from, nor Natural Gas Market Review 2007 • European Regulatory Issues 249

too close to, the time of use, because Government policy strives to maximise third parties need time to buy supplies economic production from domestic and arrange shipping. A booking period reserves. The addition of two new types of two months is considered to be a of licence has been central to maintaining reasonable time by the NMa and the interest and investment. These are the Ministry. Therefore, the owner of the “promote” licence, at a tenth of the cost of capacity should confi rm the contracted a traditional licence for the fi rst two years, capacity two months before the date of to attract new smaller investors and the use. The NMa and the Ministry intend to “frontier” licence, to ensure the maximum require the application of a transparent opportunity for appraisal of prospects principle by which the capacity would be west of Shetland. This new type of licence offered on a secondary market if not used allows companies to take larger areas in the on the primary market. fi rst instance. It offers six years in which to complete the exploration-phase work United Kingdom: programme, two years longer than the recent developments more traditional licence. Environmental assessments have been carried out for a On 16 October 2006 the DTI started a large proportion of the United Kingdom consultation process on energy, which territory to make available as much will feed into a white paper. Part of this acreage as possible for exploration and consultation process was to ask gas development. Industry has agreed a code market players whether existing security of practice to help ensure that third party of supply measures in the gas sector were access to infrastructure can be achieved on suffi cient. In the document the Secretary fair and reasonable terms and to promote of State declares that the government non-blocking commercial behaviours on is currently working on strengthening the UKCS. Reaction to these changes has the present framework, e.g. by looking been positive: in 2005 the highest number to improve the planning process for of licences was awarded in the United investments in new gas infrastructure Kingdom’s North Sea history. However, and to clarify the rules for offshore gas there is currently concern about the low storage and certain LNG installations; by overall availability of drilling rigs needed considering possible revisions to the gas to capitalise on this success. sector emergency user arrangements; and by providing more information to Norway: recent developments market participants to help them in their consumption and investment decisions. The government is actively trying to derive The government has not changed its view the maximum long-term value from the that the costs and the risk of unintended resources on the NCS, which requires that consequences from creating a strategic all profi table petroleum resources on the gas reserve unilaterally, outweigh the NCS are produced and that exploration potential benefi ts. and production is undertaken in extreme climatic conditions and in deeper waters. According to government estimates, this Natural Gas Market Review 2007 • European Regulatory Issues 250

Figure 74 Proposed organisational remedies for the merger of Suez & Gaz de France

Merged entity max. 45% in Fluxys s.a. Gaz de France max. 60% in Fluxys International s.a. 25

Segeo Suez 100 Distrigaz (transmission, & Co (transit) transit) Transmission, 57.25 transit, storage 57.25 Fluxys Fluxys s.a. (transmission, owner & operator 7 storage) Operation Distrigas (supply, LNG terminal transmission, transit, storage) LNG terminal & Fluxys non- regulated Fluxys LNG International s.a. assets (BBL, owner = Divestment Huberator etc.)

is expected to result in gas production than 60% in Fluxys International s.a., for up to 100 years. Total discovered and which will own the LNG terminal and the undiscovered gas resources on the NCS are unregulated assets and 45% in Fluxys approximately 6 000 bcm, while 1 100 bcm s.a., which will own and operate all trans- have been recovered. Gas exports are mission, transit and storage in Belgium and expected to reach 94 bcm in 2007, with which will also operate the LNG terminal. plateau production of 120 bcm expected To this end, Gaz de France will transfer to by 2010. it its 25% holding in Segeo (which owns a gas pipeline in Belgium linking the Dutch Belgium: recent developments and French borders) and Suez will transfer to it Distrigaz & Co (which markets transit In November 2006 the European capacity on the Norwegian (Troll) and Commission approved the proposed German (RTR) routes). merger of Gaz de France and Suez, subject to conditions. Suez has to completely di- However, the plan to merge still faces vest Distrigas. Fluxys and Fluxys LNG have other obstacles. The French Constitutional to be reorganised in two new companies, Council has ruled that the merger cannot Fluxys s.a. and Fluxys International s.a. take effect before full market opening on The merged entity cannot retain more 1 July 2007. Natural Gas Market Review 2007 • Annex A 251

ANNEX A: EXISTING GAS SECURITY MEASURES IN IEA COUNTRIES/REGIONS

This section provides an overview of One of the notable features in the country’s measures directed at safeguarding security gas consumption is the virtual absence of of gas supply in selected countries and gas use in power generation (less than 4% in the EU. The range of measures refl ects of power supplied in 2005) because of the the differing gas market circumstances, dominance of nuclear power generation, including availability of suitable geological although some companies have plans to storage. develop combined-cycle power plants. Heating demand is a big component of gas demand and represents almost 40% France of sales in an average year, which leads to high seasonal demand fl uctuations. France imports 97% of its gas supply. The share of natural gas in the country’s total The priority of the country’s energy policy primary energy supply (TPES) is 14.9%, is to ensure uninterrupted supply for signifi cantly lower than the IEA European customers with public service obligations average of 24.3% or the OECD average of (administrations, small commercial and 21.9% in 2005. households) which represent more than half of the country’s fi nal gas consumption. It has well diversifi ed supply, an emphasis on long-term contracts and relatively Long-term security of supply of gas in ample underground storage capacity. France is based on: diversifi cation of supply

Figure 75 France’s gas sources

bcm Non-specified 40

Russia

30 Maximum Norway dependence on a single country: 23% 20 French Netherlands domestic production: Netherlands France 2% Egypt 10 Nigeria Domestic LNG: 26% France production: 45% Algeria Algeria 0 LNG: 10% 1973 2004

Source: Natural Gas Information 2006, IEA, Ministère de l’Économie, des Finances et de l’Industrie. Natural Gas Market Review 2007 • Annex A 252

sources and transit routes; emphasis on three salt-cavern underground storage long-term gas supply (85% of the total); facilities in total have 11.7 bcm of working availability of infrastructure (transmis- capacity, which, when full at the start sion network and storage); and knowledge of winter is about 25% of the country’s of energy consumption. In fact the country annual consumption. Storage facilities has one of the most diversifi ed gas supply in France have a withdrawal capability of portfolios in the world. 200 mcm per day.

The country’s domestic gas production, Inventories are built up in summer months which represented 45% of the supply in from April to October and withdrawn in 1973, is approaching its end. winter months from November to March. In addition to seasonal balancing, storage also plays an important role in regulating Figure 76 France’s gas entry points daily and weekly changing sales patterns, as well as optimising operations of the Entry capacity (2006) transmission network. Storage of this size is also capable of dealing with potential Montoir de Bretagne Quevy (H) supply interruptions.

Fos sur Mer Blaregnies (H) Given that no new storage capacity has entered service for nearly a decade and a half, while consumption has risen by Tasnieres (L) 60%, a number of new storage facilities Dunkerque are under consideration. In addition, some

Obergailbach potential sites are being evaluated in salt layers, notably in the Alsace region. Salt caverns are generally expected to play Source: Ministère de l’Économie, des Finances et de l’Industrie. an increasingly important role, because of higher deliverability that can cope France also has two export points on the with sharper daily demand fl uctuations. Swiss and Spanish borders, Oltingue and Aquifers especially in the southwest are Larrau (the Lacal pipeline) respectively. In also being investigated to increase longer- addition, the new Euskadour gas pipe, which term storage capacity. entered into service in the fi rst quarter 2006 from Spain’s Basque region to the In order to ensure that companies use southwest of France, has a transportation all the working capacity in the facilities, capacity of 0.5 bcm per year. The 28 km the French government in summer 2006 pipe also has reverse capability. issued a decree to oblige gas distribution companies to have more than 85% of their Another strong point of the country’s allocated capacity fi lled by the beginning gas supply structure is the amount of of November (based on the August 2004 underground storage. Twelve aquifer and Energy Act). Natural Gas Market Review 2007 • Annex A 253

Table 34 Existing underground gas storage in France Working Type Depth (m) Start Operator capacity (mcm) Beynes profond Aquifer 400 740 1975 GdF

Beynes supérieur Aquifer 210 400 1956 GdF

Céré-la-Ronde Aquifer 390 910 1993 GdF

Cerville-Velaine Aquifer 650 470 1970 GdF

Chémery Aquifer 3,780 1085 1968 GdF

Etrez Salt Cavern 450 1400 1979 GdF

Germigny-sous-Colombs Aquifer 760 850 1982 GdF

Gournay-sur-Aronde Aquifer 900 720 1976 GdF

Izaute Aquifer 1,290 510 1981 Total

Lussagnet Aquifer 1,100 600 1957 Total

Manosque Salt Cavern 210 910 1993 GdF

Saint-Clair-sur-Epte Aquifer 380 740 1979 GdF

Saint-Illiers Aquifer 590 470 1965 GdF

Soings-en-Sologne Aquifer 220 1140 1981 GdF

Tersanne Salt Cavern 200 1400 1970 GdF

Total 11,530

Source: Natural Gas Information 2006, IEA, Cedigaz: Underground Gas Storage in the World, Armelle Lecarpentier, June 2006.

Table 35 Major new and expansion storage projects in France

Project Region Type Capacity

Pecorade Southwest Depleted oil field n.a.

Lussagnet expansion Southwest Aquifer 2.4 –-> 3.5 bcm

Hauterives Southeast Salt cavern n.a.

Trois-Fontaines East Depleted gas field working capacity 80 mcm

Etrez expansion East Salt cavern n.a.

Source: Natural Gas Information 2006, IEA; Cedigaz: Underground Gas Storage in the World, Armelle Lecarpentier, June 2006. Natural Gas Market Review 2007 • Annex A 254

Figure 77 France’s transportation and storage system

London NETHERLANDS Dunkirk Calais Cherbourg Boulogne Brus. Blaregnies Brest Lannion Le Havre GERMANY (4 BELGIUM

(30) 4 ) LUX. Rennes Lux. City Paris (2 Montoir (2 0 (36) 2 ) Includes imports from Nigeria (12) ) for Italy under swap arrangement Nantes Troyes Nancy (10) Tours Les Sables (2 4 ) (36)

La Rochelle (36) Roussines (18) (24) Le Verdon Limoges ) 4 2 Tulle Etrez Bordeaux ( SWITZERLAND FRANCE Evian AUSTRIA Lyon Aurillac Bidart Tersanne Gas pipeline ITALY St. Affrique Gas pipeline plannedSLOVENIA or under const. (10) (24) Major gas processing plant Manosque Underground gas storage Fos (16) CROATIA Perpignan Underground gas storage planned SPAIN ANDORRA (under const.: Nice Madrid 2007) Toulon (24) Pipeline diameter (inches) Gas import route LNG import terminal LNG import terminal planned 0Miles 100 200 Ajaccio LNG export plant Sagunto 0Km 200 300 LNG export plant planned e The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

Source: Ministère de l’Économie, des Finances et de l’Industrie and The Petroleum Economist Ltd..

French decree In the latter half of 2006, France saw more LNG terminal plans, encouraged by some Au 1er novembre de chaque année, les volumes de gaz stockés par un indications that the country’s gas sector fournisseur ne peuvent être inférieurs was opening up for competition. They à 85 % des droits de stockage en included three new entrants into the volume utile, tels que défi nis à l’article country’s gas business. France could have 5 du présent décret, de ses clients as many as seven terminals totalling at domestiques, y compris des ménages least 45 bcm per year by 2011-12. résidant dans un immeuble d’habitation chauffé collectivement, et de ses autres clients assurant des missions d’intérêt général. (Article 13, Décret n° 2006-1034 du 21 août 2006 relatif à l’accès aux stockages souterrains de gaz naturel) Natural Gas Market Review 2007 • Annex A 255

Spain market very rapidly since 1990: Norway in 1995, Qatar in 1997, Trinidad and Nigeria Spain’s natural gas market developed later in 1999, Oman in 2000 and Egypt in 2005, than other western European countries in addition to traditional exporters Algeria because of low levels of domestic and Libya. Therefore the current supply production and its geographic location portfolio is quite well diversifi ed in terms far from major European gas fi elds. The of pipeline vs. LNG supply sources. country’s gas infrastructure has been developed mainly since the 1990s, when Over the past three years, gas demand energy diversifi cation and raising natural in the country has increased by 13-18% gas’ share were given prominence in the annually, reaching 32 bcm in 2005, due to country’s energy policy agenda. The share strong economic growth and increasing of natural gas in total primary energy gas use in power generation. Development supply has grown from 5% in 1990 to of combined-cycle power plants, which more than 25% in 2004. entered into operation only in 2002, is expected to drive growth of gas use in the As the domestic production from future. The composition of gas use in 2005 Marismas fi elds has been almost depleted, was: 55% for industrial, 30% for power the country is virtually entirely dependent generation and 15% for small commercial on imports for natural gas supply. New and residential sectors. In 2006, it was exporters have gained footholds in the 52% for industrial, 34% for power

Figure 78 Spain’s gas sources

Norway bcm 30

Algeria pipe 25 Maximum dependence on a single country: 43%

20 Algeria LNG

15 Egypt Libya LNG: 65% 10 Nigeria

Oman 5 LNG from Algeria and Libya Qatar 0 1973 2005

Source: Natural Gas Information 2006, IEA. Natural Gas Market Review 2007 • Annex A 256

generation and 13% for small commercial rather small compared to other European and residential sectors. The consumption countries. However, the strong rise in gas of combined-cycle power plants grew by demand for power generation has not 45% in 2005. been evenly spread throughout the year. Especially in 2005 and 2006, the total daily Due to generally milder weather and demand for natural gas broke records on consequential smaller residential gas use, several occasions during winter months. seasonal fl uctuations in gas demand are

Table 36 LNG terminals in Spain and expansion plans LNG storage Equivalent days Terminal Tank capacity in of national gas Start Operator liquid (m3) consumption Existing Barcelona No. 1-4 240 000 1969 Enagas No. 5 150 000 2005 Enagas Huelva No. 1-3 310 000 1988 Enagas Cartagena No. 1-2 157 000 1989 Enagas No. 3 130 000 2005 Enagas Bilbao No. 1-2 300 000 2003 Bahia de Bizcahia* Subtotal 1 287 000 8.6 as of 2005 Sagunto No. 1-2 300 000 2006 Saggas** Barcelona No. 6 150 000 2006 Enagas Huelva No. 4 150 000 2006 Enagas Subtotal 600 000 4.0 2006 (2005-06 addition) 880 000 5.9 Total 1 887 000 12.6 as of 2006 Future plans Mugardos (El Ferrol) No. 1-2 300 000 2007 Reganosa Group*** Cartagena No. 4-5 300 000 2008-2010 Enagas Bilbao No. 3-4 300 000 2008-2010 Bahia de Bizcahia Barcelona No. 7-8 300 000 2009-2010 Enagas Huelva No. 5 150 000 2009 Enagas Sagunto No. 3-4 300 000 2009-2011 Saggas El Musel No. 1-2 300 000 2010 Enagas *BP, Repsol, Iberdorola, EVE. **Endesa, Iberdrola and Union Fenosa along with the Oman government. *** Endesa, Union Fenosa Gas, Galicia’s Tojeiro group, Algeria’s Sonatrach, the Galician government, Caixa Galicia, Banco Pastor and Caixanova. Note: The list does not include terminal plans in the Canary Islands. Source: Natural Gas Information 2006, IEA, company information. Natural Gas Market Review 2007 • Annex A 257

Figure 79 Spain’s transportation and storage infrastructure Mugardos (under const.: 2007) El Ferrol La Coruna Le Verdon (20) Lugo Ovièdo Bordeaux Vigo SWITZERLAND Tuy Orense FRANCE Lyon Ponferrada Leon Bilbao Bidart Porto Zamora (26) PORTUGAL Soria Carrico (26) Huesca Fos-sur-Mer (20) SPAIN ANDORRA Perpignan ITALY Lisbon Madrid Talavera Guadalajara Setúbal Cuenca (24) Gerona Tivissa Badajos Almendralejo Teruel Barcelona Sines (32) TRANVERSAL AXIS (26) (26) Lliria Cheste Sagunto Albacete Gas pipeline Huelva Valencia Linares Gas pipeline planned or underRome const. Caudete (30) Seville Palma Jaén Major gas processing plant Jerez Ibiza (48) Murcia Alicante Underground gas storage Cartagena Underground gas storage planned Barbate Malaga Tangier Gibralter (UK) Almería (24) Pipeline diameter (inches) 0Miles 100 200 Gas import route LNG import terminal (4 0Km 200 300 8 (2x24) LNG import terminal planned ) MEDGAZ Arzew Algiers Oran Rabat MOROCCO LNG export plant Beni-Saf Fès ALGERIA LNG export plant planned The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source: The Petroleum Economist Ltd..

The total length of Spanish gas pipelines directly linking Beni Saf on the Algerian was 58 870 km at the end of 2006, including coast to Almeria on the Spanish coast, around 41 000 km for distribution. The is underway. Completion is expected in network covers most of the country and early 2009. Most of the initial capacity of it has fi ve international connections via 8 bcm per year should be absorbed by the pipelines: Larrau, receiv-ing gas from Spanish market. Norway via France; Tarifa receiving gas from Algeria via the Pedro Duran Farell In addition, the country has fi ve LNG pipeline; Tuy and Badajoz interconnecting receiving terminals in operation: with Portugal; and the two-way Euskadour Barcelona, Huelva and Cartagena by gas pipeline between France and Spain, Enagas, Bilbao by Bahia de Bizcahia Gas, SL which entered into service in the fi rst (owned by BP, Repsol, Iberdrola and EVE) quarter 2006. The two connections and Sagunto by Saggas (owned by Endesa, with France are currently capable of Iberdrola and Union Fenosa along with the transporting 3 bcm per year from France Oman government). Another one is being to Spain. constructed at Murgados (El Ferrol), due to be completed in 2007. Enagas is also Furthermore, the construction of a new expanding its existing three terminals deepwater import pipeline, Medgaz, and has a plan to build and manage a new Natural Gas Market Review 2007 • Annex A 258

import terminal in the port of El Musel, In the winter of 2005 - 2006, due to severe the Bay of Biscay, in northern Spain. cold weather combined with low hydro output and tight global LNG market Spain currently has two underground conditions, the Ministry of Industry, storage facilities in depleted gas fi elds and Tourism & Trade mandated that 2 LNG plans to install some additional storage cargoes be stationed off the coast at all capacities, according to the Revisión 2005 times as insurance against shortages. – 2011 de la Planifi cación de los Sectores In 2006, the country saw lower gas de Electricidad y Gas 2002 – 2011 (Updated demand growth (gross inland deliveries up Mandatory Planning for Gas and Electricity only 2.3% in 2006, compared with +18% in Markets for 2005 - 2011) approved by the 2005, and fi ve years of strong double digit government. Those projects, if realised, growth), especially in the power sector, as would boost total working capacity to hydro power conditions were improved. 7 bcm in 2011. Combined with LNG terminal Land-based gas storage has also been storage, the country could have 70-day augmented (Marismas Phase 1). national consumption equivalent working storage capacity in 2011, assuming a 6% LNG storage capacity was increased by annual growth in gas demand in the period. 600 000 m3, which is equivalent to 4 days

Table 37 Underground gas storage in Spain Equivalent days Working of national gas Deliverability (mcm per day) capacity (mcm) consumption Existing Serrablo depleted field 820 6.8 Gaviota depleted field 1 446 5.7 Subtotal 2 26625.6 12.5 Planned for 2005-11 Marismas (Phase 1) depleted field 300 1.6 Marismas (Phase 2) depleted field 600 4.4 Poseidon depleted field 250 1.5 Gaviota expansion depleted field 1 558 14.2 Yela Aquifer 1 050 15.0 Castor (Amposta) depleted field 1 300 25.0 Reus Aquifer n.a. n.a. 7 324 82.8 assuming current demand Total in 2011 58.3 assuming 6% growth in demand

Source: Natural Gas Information 2006, IEA, Cedigaz: Underground Gas Storage in the World, Armelle Lecarpentier, June 2006. Natural Gas Market Review 2007 • Annex A 259

of national gas consumption. The Magreb fl uctuations are becoming larger. The pipeline increased capacity in 2006 by ratio between average summer and winter 1-2% of annual Spanish demand consumption now stands at 1 to 4. Local gas distribution networks cover 40% of Enagas had a “winter performance plan” household energy demand in the country. in place in 2006 - 2007. LNG commercial storage was regulated between a mini- Hungary produced 3 bcm of natural gas in mum 3 days and maximum 5 days per 2005, a signifi cant decline of 38% from the operator, intended to stop hoarding, but production of 4.9 bcm in 1990. It is expected also ensuring some storage. that production will decline further in the future to 2.3 bcm in 2010. Exploration activity is focused on central Hungary. Hungary Domestic production accounted for 19.3% Natural gas is the most important fuel of total gas supply in Hungary in 2005. in Hungary, representing 44% of the The main producer of natural gas is the country’s total primary energy supply petroleum company Mol. The only other in 2005. This is signifi cantly higher than producer is Winstar, with a production of the IEA European average of 24.3% or the 0.3 bcm in 2005. Proven reserves of Mol OECD total of 21.9% in 2005. The supply of fell from 29.25 bcm in 2004 to 27.5 bcm in natural gas has increased by an average of 2005. A potential new producer, Toreador, 2.1% per year since 1990. plans to open production from a gas condensate fi eld at Örmenyes. The Hungarian government predicts that supply of natural gas will increase slightly With the predicted increase in demand and by 3.2% until 2010 and more rapidly reduction in production over the coming thereafter. Most of the additional demand years, the Hungarian government expects is expected to come from gas use in power that domestic production will cover 14.4% generation. of demand by 2010 and 9% by 2020.

Natural gas is an important energy source Special royalties are paid on gas production for power generation and heat production from wells that started before 1998, to in Hungary. In 2004, natural gas accounted fund the household gas subsidy. In 2006, for 35% of Hungarian power generation. the Hungarian government and Mol Heat and electricity production together renegotiated the royalty agreement, to used 28% of total gas supply in that incentivize Mol to consider increased year. Residential and commercial gas use investment in continued production from accounted for about half of all gas supplied these wells. in Hungary. Hungary has not been fully self-suffi cient Because of the growing use in the in gas since 1970s and today relies on residential sector and the shrinking use imports from Russia. Total imports in in the industrial sector, seasonal demand 2005 reached 12 bcm. Of this, 2.2 bcm Natural Gas Market Review 2007 • Annex A 260

Figure 80 Hungary’s gas sources

bcm 14 Others

12

10

Russia 8

6 Russia

4 Germany France Hungary 2 Hungary

0 1973 2005

Source: Natural Gas Information 2006, IEA. were contracted from new suppliers such connections by pipeline are with Ukraine, as Gaz de France, with physical supply Austria and Serbia. The Ukraine pipeline is being 100% from Russia. The Russian the prime import route for gas into Hungary, share of Hungary’s gas supply is nearing while the Austrian pipeline is primarily 80% of contracted volume and this could used to balance the system and at times of increase to 85% in 2020 according to the high demand. The Serbian pipeline serves government’s scenario, if no measures for as a transit pipeline, through which gas is import source diversifi cation are taken. sent into Balkans under a 20-year contract concluded in 1998. At the moment, only the Imports are under fi ve long-term supply Ukraine pipeline has spare capacity. Capacity contracts held by Panrusgaz, originally a at the entry points is allocated by auction. joint-venture of Gazprom and Mol with each owning 50% of the shares. With the Further international connections are under sale of the gas supply and storage business discussion, including the Nabucco pipeline, from Mol to E.On in 2006, E.On took over an extension of the pipeline Mol’s share of the joint-venture. (which was agreed between the Russian and Hungarian companies in March 2006) The country’s transport system had 5 194 km and the construction of an LNG terminal of transmission pipelines as of the end of on the Croatian island of Krk, with a 2005. Distribution networks total more pipeline connection into Hungary. The aim than 79 000 km. The main international of Nabucco, a major gas transit line from Natural Gas Market Review 2007 • Annex A 261

Table 38 Entry capacity of the gas system in Hungary Entry point Capacity (bcm per year) Deliverability (mcm per day) Beregdaróc (from Ukraine) 10.0 29.5 Mosonmagyarróvár (from Austria) 4.4 12.0 Domestic production (7 locations) 3.5 11.5 Storage (5 locations) 47.5 Total 17.9 100.5 Peak demand in 2005 89.0 Transit 12.0 Source: Mol. the Caspian region through the Balkans, 1980. Inspections using advanced methods would be to secure the increasing natural have revealed that the majority of the gas demand of European Union member system is in need of major reconstruction countries and southeast European countries. and in some areas complete replacement. A number of regional gas companies are As a consequence, the transmission tariff examining the possibility to build the line has been amended to create an incentive with a yearly capacity of 30 bcm. for investment by the system operator.

A number of projects aimed at increasing The transmission system is operated by regional networks are being evaluated. Mol’s gas business and regulated by the Mol is interested in establishing a transit Hungarian Energy Offi ce. The price for pipeline serving Romania and negotiations the system use is based on an entry/exit are in progress with Romgaz about a calculation since 2005. Prior to this it was pipeline with a 1.0 - 1.5 bcm per year a fl at rate. capacity, which would need two years to be built at an estimated cost of USD 30 A temporary network and commercial code million. Mol and INA also decided on the was published in 2003, regulating third evaluation of a Croatian transit connection party access (TPA) to the transmission point with a delivery amount of 2 bcm per and distribution network and the storage year and an estimated capital cost of over system, including prices and co-operation USD 100 million. These projects are at a rules. This was followed by a government very early stage of development. decree in 2004 and the Gas Act of 2005.

Following the discovery of natural gas in Under the network code, the natural gas Hungary in the 1960s, a gas transmission transmission company has to publish on network was built up from 1963 to reach a its homepage the available capacity for total length of 5 194 km in 2005. The average the following 12 months in a monthly age of the system is 25 years and half of breakdown at entry and exit points of the the system was built between 1963 and network. Also, the annual maintenance plan Natural Gas Market Review 2007 • Annex A 262

of the interoperable natural gas system of which is household heating demand. has to be published by February 15 each Current facilities are all depleted gas fi elds. year. Spare capacity of the transmission system and storages has to be published In 2006, Mol sold four and leased out 15 months in advance under the code. one of its fi ve storage facilities with a total capacity of 3.4 bcm and a daily The code also provides detailed rules withdrawal capacity of 47.5 mcm to for contracting capacity and describes E.On Ruhrgas International. Third party the scope of basic services provided by access to the underground storage has system operators. It identifi es possible been implemented for the competitive and mandatory contractual relationships gas market, while the regulated tariffs of the new market structure, including for supply of the captive markets now not only commercial agreements, but also contain incentives for new investments those of various forms of cooperation into underground storage. between system users and the operator. Following the supply interruption of Underground storage plays a very January 2006, which cut the country’s gas important role in Hungary considering the supply by up to 20% over several days, high seasonality of demand, the infl exible the Parliament approved a new law, the structure of demand and the need to cover Act XXVI/2006 on Safety Stockpiling of the daily peak during winter, almost half Natural Gas in February 2006. According

Figure 81 Hungary’s transportation and storage system Vienna Uzhgorod Baumgarten BROTHERHOOD Velke S TRANSGA Kapuzany AUSTRIA Bratislava Levice UKRAINE H SLOVAK A Beregdaroc G REP. (24) (12) (32) Szombathely Budapest Debrecen (32) Graz Szazhalombatta (16) Satu Mare TAG (1

4

)

SO HUNGARY

(24)

(24) L ROMANIA (16)

) NABUCCO (56) 0 (2 (20) Gas pipeline Cluj-Napoca Gas pipeline planned or under const. Zagreb Barcs Arad Major gas processing plant Pécs Szeged

) Underground gas storage

0

Sombor (3 Underground gas storage planned Sisak (18) (24) Pipeline diameter (inches) CROATIA Osijek SERBIA Timisoara Gas import route The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Source: The Petroleum Economist Ltd.. Natural Gas Market Review 2007 • Annex A 263

Table 39 Underground gas storage in Hungary Working capacity Equivalent days of national gas Deliverability (mcm per day) (mcm) consumption Pusztaederics 330 2.7 Zsana 1 300 21.0 Algyo-Maros-1 150 2.2 Kardoskút-Pusztaszolos 200 2.4 Hajdúszoboszló 1 400 19.2 Total 3 380 102.8 47.5 Source: Mol

to the act, new underground gas storage The cost of the project is estimated to with a total capacity of 1.2 bcm or more be USD 750 million. The MSZKSZ carried and deliverability of 29 mcm per day has out a tender to select a company for the to be constructed and become operational building and operating of the facility and by 2010. MOL was selected in November 2006. MOL is expected to construct the facility in a The legal framework under which the joint venture with the state. Until then, storage will be managed is similar to that for from October 2006, 150 mcm, then from oil emergency storage, in that it is managed October 2007 until December 2009, 300 by the Hungarian Hydrocarbon Stockpiling mcm security reserve must be stored in Association (MSZKSZ), fi nanced by the gas the existing storages which can only be suppliers. The Hungarian government will used in a crisis situation. have the right to initiate a stock draw. At the moment, the conditions under which this right can be exercised have not been European Union clarifi ed. All gas companies operating in Hungary have to become a member of the Directive 2004/67/EC MSZKSZ. The level of their contribution fee Europe as a whole depends heavily on and how it will be determined is unclear at this time and will depend on the cost outside supply sources in meeting natural of creating and operating the storage gas demand and as noted earlier, the facility. One possible option is for the cost dependence is expected to grow further to be covered by an additional charge on in coming years. Although the gas supply the current regulated fi nal tariffs if a new security issue has attracted particular storage is installed. The possible cost is attention after the Russia - Ukraine gas estimated at 2% of the fi nal tariff by the crisis of January 2006, the EU had put a MSZKSZ. great emphasis on this issue before this time. EU’s framework of security of gas supply is defi ned in EU Council Directives. Natural Gas Market Review 2007 • Annex A 264

Directive 2003/55/EC, which set the market The Gas Co-ordination Group’s draft work opening schedule and entered into force in plan for EU gas supply security seeks to: July 2004, stipulated that these “common Provide a clear view of physical gas rules for the internal market in natural supply security. gas” include obligations (in Article 13) on Member States regarding monitoring of Assess effectiveness of implementation security of supply. of measures. Provide a common understanding of Directive 2004/67/EC, which entered into “major supply disruption” (20% loss of force in May 2006, includes provisions third party gas). “concerning measures to safeguard security of natural gas supply.” The Directive states Defi ne a compensation mechanism. that supplies to household customers must Identify and assess forthcoming chal- be protected under extreme conditions. It lenges. also includes references to storage, long- term contracts, bilateral agreements, The European Council in March 2007 high- incentives for investment and market lighted the need for a “thorough analysis liquidity, as well as defi ning a major supply of the availability and costs of gas storage disruption as losing 20% of third party falicities in the EU” as one of the measures gas. It also sets up emergency procedures to enhance security of supply. and a Gas Co-ordination Group.

This Group, set up to co-ordinate supply security, had its fi rst meeting in January 2006, even before the offi cial entry into force of the Directive itself. The sole topic of the meeting was the Russia-Ukraine gas supply disruption.

The second meeting in October 2006 discussed rules of procedure, a work plan and to bring Russian and Ukrainian gas companies together to share views and information. The January 2007 meeting discussed the gas supply problems be- tween Belarus and Russia. Natural Gas Market Review 2007 • Annex B 265

ANNEX B: CONTRACTUAL GAS FLOWS INVOLVING OECD COUNTRIES

Figure 82 Gas flows based on 2005 IEA data: North America

CANADA 187.2 89.8

9.8 103.5

UNITED 17.9 STATES (LNG) 516.6 622.0

Algeria 2.8 Egypt 2.1 Malaysia 0.2 0.016 10.1 Nigeria 0.2 Oman 0.1 Qatar 0.1 Trinidad 12.4 MEXICO Gas pipelines 43.1 49.5 LNG 43.1 Production Units = Billion cubic metres 49.5 Consumption The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Natural Gas Market Review 2007 • Annex B 266

Figure 83 Gas flows based on 2005 IEA data: Asia Pacific

United States 1.7 JAPAN (LNG) 3.1 87.2 64.6 REP. OF 28.4 (LNG) KOREA (LNG) 0.5 30.4 Algeria 0.1 Brunei 0.8 Brunei 8.6 Egypt 0.3 Egypt 0.2 Indonesia 7.3 Indonesia 19.3 Malaysia 6.1 Malaysia 18.4 Oman 5.7 Oman 1.5 Qatar 8.1 Qatar 9.0 UAE 0.1 Trinidad 0.1 UAE 7.4

1.1 12.5 (LNG) (LNG)

AUSTRALIA 40.3 26.8

LNG 40.3 Production Units = Billion cubic metres 26.8 Consumption The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA. Natural Gas Market Review 2007 • Annex B 267

Figure 84 Gas flows based on 2005 IEA data: Europe

FINLAND 4.4 - 4.4

NORWAY 89.6 5.8 SWEDEN 11.6 - 0.9 15.7 14 0.9 40.2 DENMARK 10.4 5.0

UK RUSSIA 3.5 0.4 2.2 (Transit through Poland in Yamal Pipeline) 92.0 99.2 33.0 2.4 IRELAND NETHERLANDS (Transit through POLAND 6.9 0.6 4.1 4.8 22.9 78.8 49.5 Poland in Yamal 6.1 16.2 3.6 20.5 Pipeline) 2.7 20.2 2.8 GERMANY 30.1 (LNG) ? 0.9 BEL. 19.9 101.0 0.5 - 17.3 ? (LNG) 0.5 LUX. 0.5 2.3 CZECH REP. 21.7 3.2 15.7 UKRAINE 130.3 - 1.4 14.6 0.2 9.5 SLOVAK REP. 76.2 0.5 3.5 9.8 48.2 0.1 6.5 25 12.8 4 AUSTRIA Minimal HUNGARY 2.7 FRANCE SWITZERLAND 1.6 9.6 1.1 3.0 15.0 13.4 (LNG) 1.0 46.0 - 3.4 MOLDOVA 12.4 2.2 0.1 6.0 SLOVENIA BULGARIA 22.3 0.1 2.5 (LNG) 16.2 24.3 CROATIA 5.2 21.7 SERBIA ITALY 0.3 12.0 86.2 ROMANIA (LNG) 0.8 0.1 2.5 FYR 2.1 MACEDONIA

PORTUGAL SPAIN 2.7 - 4.3 0.2 31.9 29.7 TURKEY (IRAN) GREECE 2.5 14 - 2.8 0.9 27.4 4.2 (LNG) 1.7 12.1 Gas pipelines (LNG) LNG 0.4 (LNG) 1.0 3.0 Production ALGERIA 25.2 Units = Billion cubic metres 4.5 LIBYA 15.0 Consumption The boundaries and names shown and the designations used on maps included in this publication do not imply official endorsement or acceptance by the IEA.

Natural Gas Market Review 2007 • Annex C 269

ANNEX C: ABBREVIATIONS

ANWR Arctic National Wildlife Refuge (in Alaska, the United States) ASEAN Association of South-East Asian Nations bbl barrel BBL Balgzand-Bacton Pipeline bcf billion cubic feet bcm billion cubic meters b/d barrels per day boe barrels of oil equivalent CBM Coal bed methane CCGT Combined-cycle gas turbine CHP Combined production of heat and power CNG Compressed natural gas CNOOC Chinese National Offshore Oil Corporation CNPC Chinese National Petroleum Corporation EIA Energy Information Administration, the United States E&P Exploration and production EPC Engineering, procurement and construction EU European Union FERC Federal Energy Regulatory Commission, the United States FSU Former Soviet Union GHG Greenhouse gas GTL Gas-To-Liquids GW Gigawatt (109 watts) GWh Gigawatt hour HDD Heating degree-days IEA International Energy Agency IOC International oil company IPE International Petroleum Exchange, based in the United Kingdom IPP Independent power producer ISO Independent system operator IUK Interconnector UK JCC Japan Crude Cocktail, the average price of crude oil imported into Japan kb/d thousand barrels per day kW kilowatt (103 watts) kWh kilowatt hour LDC Local distribution company LNG Liquefi ed natural gas LPG Liquefi ed petroleum gas (propane, butane) Natural Gas Market Review 2007 • Annex C 270

mb/d million barrels per day MBtu Million British thermal units mcm million cubic meters MENA Middle East and North Africa MJ megajoule Mtoe million tonnes of oil equivalent mtpa million tonnes per annum MW Megawatt (106 watts) MWh Megawatt hour NBP National Balancing Point (a virtual trading point for gas in the United Kingdom) NDRC National Development and Reform Commission, China NEGP North-European Gas Pipeline (current Nord Stream Pipeline) NGL Natural gas liquid NIMBY Not in my back yard NOC National oil company NWS North West Shelf (an Australian LNG venture) NYMEX New York Mercantile Exchange, in the United States OCGT Open-cycle gas turbine OCS Outer continental shelf OECD Organisation for Economic Co-operation and Development Ofgem Offi ce of Gas and Electricity Markets, the United Kingdom OPEC Organisation of Petroleum Exporting Countries PSA (PSC) Production sharing agreement (contract) SPA (SPC) Sale and purchase agreement (contract) TAGP Trans-ASEAN Gas Pipeline tcf trillion cubic feet tcm trillion cubic meters toe tonne of oil equivalent TPA Third-party access TPES Total primary energy supply TWh Terawatt hour USD United States Dollar WAGP West African Gas Pipeline WEO World Energy Outlook (IEA publication) WTI West Texas Intermediate (benchmark crude oil in the United States) Natural Gas Market Review 2007 • Annex D 271

ANNEX D: GLOSSARY

Associated gas Natural gas found mixed with oil in underground hydro-carbon reservoirs, released as a by-product of oil production.

Balancing The requirement to equal supply and demand in a pipeline system over a certain period.

Base gas Gas required in a storage facility to maintain suffi cient pressure (sometimes: cushion gas).

Base-load capacity Capacity of liquefaction plant or regasifi cation terminal that is supposed to be processed in a year.

Base-load power Power generation units used to meet demand around the clock.

Basis differential The difference between spot cash prices at different locations at the same time.

Brownfi eld project Expansion project to an existing plant, or alteration project from a different or mothballed plant.

City gate The point which a local distribution company (LDC) receives gas from a pipeline or transmission system.

Condensate Light hydrocarbons existing as vapour in natural gas reservoirs that condense to liquid at normal temperature and pressure.

Cushion gas See: base gas.

Dry gas Gas that does not contain heavier hydrocarbons, or that has been treated to remove heavier hydrocarbons.

Greenfi eld project Project constructed from the ground up, a brand-new project.

Feedstock gas Gas used as feedstock for petrochemical or fertiliser plants, or used to liquefy into LNG.

Flaring Burning off unused natural gas, typically at an oil producing fi eld where the associated gas cannot be economically utilised. Sometimes gas is fl ared as a safety measure to mitigate overpressure of other gas systems.

Henry Hub Pipeline interconnection in Louisiana, the United States, where a number of pipelines meet, which is the standard delivery point for the NYMEX natural gas contracts in the United States, used as the benchmark price in the United States Gulf Coast for domestic and international gas transactions. Natural Gas Market Review 2007 • Annex D 272

Hub Physical or virtual location where multiple natural gas pipelines interconnect or natural gas is supposed to be delivered between multiple parties.

Indexation Linking the gas price in a contract to published prices or other indicators.

Injection The act of putting gas into a storage facility.

LNGRV (LNG An LNG carrier ship which is equipped with onboard regasifi cation vessel) regasifi cation facilities.

Long-term contract A supply contract of gas deliveries lasting years, typically 20-25 years for LNG and international long-haul pipeline trades to support big investment and 2-5 years for domestic industrial-sector sales in certain countries.

Net-back price The effective wellhead price to the producer of natural gas, the downstream market price less the charge for delivery.

Non-associated gas Natural gas not in contact with crude oil in the reservoir.

Offtake To take a delivery of gas or LNG at a certain point.

Open access Natural gas transportation or LNG regasifi cation service available to all shippers on a non-discriminatory basis.

Open season A procedure conducted by an infrastructure facility (pipeline, storage, or LNG regasifi cation terminal) owner to gauge potential users’ fi nancial interest in the capacity of the facility.

Peaking (or peak- The maximum capacity of power generation, storage withdrawal, shaving) capacity or LNG regasifi cation send-out, during the highest daily, weekly, or seasonal demand period.

S-Curve A pricing mechanism that uses a linkage to an indicator (typically seen in Asian LNG contracts using the JCC oil price as an indicator), where the rates of gas price increase or decrease compared to indicator are slowed outside of a certain indicator range so that both buyers and sellers are protected from moves of the indicator outside a certain range.

Sour gas Natural gas that contains signifi cant hydrogen sulphide content.

Take-or-pay A clause in a gas (or an LNG) supply contract that dictate a minimum quantity of gas (or LNG) be paid for to the seller, irrespective of whether delivery is accepted by the buyer. Natural Gas Market Review 2007 • Annex D 273

Throughput The volume of gas transported through a pipeline, or treated by a treatment facility.

Tolling A fee-based service where the service providing power generator receives fuel from the benefi ciary and delivers electric power to the same benefi ciary in return for the service fee.

Train An LNG ‘train’ consists of the gas processing and liquefaction units to treat and liquefy feedstock gas.

Unbundling Separating different elements of gas services, in particular, transportation/distribution and commodity trading, either on a legal or accounting basis.

Wellhead A commonly used expression of the upstream end of natural gas value chain, derived from the original meaning of the top of a production well in a gas fi eld.

Wet gas Gas that contains heavier hydrocarbons or associated gas that has not been processed yet.

Withdrawal Sending out gas from a gas storage facility.

Working gas Gas expected to be withdrawn from a natural gas storage facility during usual operations.

Natural Gas Market Review 2007 • Annex E 275

ANNEX E: CONVERSION FACTORS

Table 40 Conversion factors for natural gas volume million bcm per Tcf per PJ per TWh per MBtu per Mtoe per To: tonnes per bcf/d year year year year year year year From: multiply by:

bcm per year 1 0.7350 0.09681 0.03534 40.00 11.11 3.7912x107 0.9554

million tonnes per year 1.360 1 0.1317 0.04808 54.40 15.11 5.16x107 1.299

bcf/d 10.33 7.595 1 0.3650 413.2 114.8 3.91x108 9.869

Tcf per year 28.30 20.81 2.740 1 1,132 314.5 1.07x109 27.04

PJ per year 0.02500 0.01838 0.002420 0.0008834 1 0.2778 9.47x105 0.02388

TWh per year 0.09000 0.06615 0.008713 0.003180 3.600 1 3.41x106 0.08598

MBtu per year 2.638x10-8 1.939x10-8 2.554x10-9 9.32x10-10 1.055x10-6 2.93x10-7 1 2.520x10-8

Mtoe per year 1.047 0.7693 0.1013 0.03698 41.87 11.63 3.97x107 1

Note: Based on gas with 40 MJ/m3.

Table 41 Conversion factors for natural gas price From: To: USD /MBtu USD /1 000 m3 USD / tonne USD /MBtu 1 37.912 51.41815 USD /1,000 m3 0.02638 1 1.35625 USD / tonne 0.01945 0.7373 1

Note: Based on gas with 40 MJ/m3.

Natural Gas Market Review 2007 • Annex F 277

ANNEX F: LNG REGASIFICATION TERMINALS

Table 42 LNG regasification terminals Capacity Country Terminal (mtpa) Storage m3 Start Status (bcm per year) Japan Chita Kyodo 10.4 7.6 300 000 1978 Operation Chita 16.6 11.5 640 000 1983 Operation Chita-Midorihama Works 7.3 5.4 200 000 2001 Operation Fukuoka 1.2 0.9 70 000 1993 Operation Futtsu 27.4 20.1 1 110 000 1985 Operation Hatsukaichi 0.8 0.6 170 000 1996 Operation Higashi-Ohgishima 21.1 15.5 540 000 1984 Operation Himeji 6.8 5.0 740 000 1984 Operation Himeji LNG 11.6 8.5 520 000 1979 Operation Joetsu 2012 Proposed Kagoshima 0.3 0.2 86 000 1996 Operation Kawagoe 7.5 5.5 480 000 1997 Operation Kawagoe expansion 360 000 2011 Planned Mizushima 0.8 0.6 160 000 2006 Operation Mizushima expansion 1.4 1.0 160 000 2012 Planned Nagasaki 0.2 0.1 35 000 2003Operation Negishi 16.5 12.1 1 180 000 1969 Operation Niigata 12.2 9.0 720 000 1984 Operation Ohgishima 8.1 6.0 600 000 1998 Operation Oita 6.6 4.9 460 000 1990 Operation Sakai 2.8 2.1 140 000 2006 Operation Sakaide 0.6 0.4 180 000 2010 Planned Senboku I 3.4 2.5 180 000 1972 Operation Senboku II 17.5 12.9 1 585 000 1977 Operation Shin-Minato 0.4 0.3 80 000 1997 Operation Sodegaura 39.9 29.3 2 660 000 1973 Operation Sodeshi 1.2 0.9 177 200 1996 Operation Sodeshi expansion 160 000 2010 Planned Tobata 9.3 6.8 480 000 1977 Operation Wakayama TBD Proposed Yanai 3.3 2.4 480 000 1990 Operation Yokkaichi LNG Centre 9.7 7.1 320 000 1988 Operation Yokkaichi Works 0.9 0.7 160 000 1991 Operation Korea Pyeong-Taek 26.1 19.2 1 000 000 1986 Operation Natural Gas Market Review 2007 • Annex F 278

Table 42 LNG regasification terminals (cont.) Capacity Country Terminal (mtpa) Storage m3 Start Status (bcm per year) Pyongtaek 2 4.3 3.2 280 000 2007 Construction Pyongtaek 2 4.3 3.2 280 000 2008 Construction Pyongtaek 2 4.3 3.2 200 000 2010 Planned Pyongtaek 2 4.3 3.2 200 000 2012 Planned In-Chon 37.9 27.9 2 480 000 1996 Operation In-Chon expansion 12.2 8.9 400 000 2009 Construction Tong-Yeong 15.3 11.2 980 000 2002 Operation Tong-Yeong expansion 420 000 2006 Operation Tong-Yeong expansion 2 6.4 4.7 1 000 000 2009 Construction Gwangyang 2.4 1.8 300 000 2005 Operation Samcheok or Boryeong 1 000 000 2013 Proposed Chinese Taipei Yung-An 24.3 17.9 690 000 1990 Operation Taichung 4.1 3.0 480 000 2009Construction China Guangdong Dapeng 5.0 3.7 480 000 2006 Operation Guangdong Dapeng 2 3.4 2.5 160 000 2008 Construction Fujian 3.5 2.6 320 000 2008Construction Shanghai LNG 4.1 3.0 495 000 2009 Construction Liaoning, Dalian 4.1 3.0 2011 Planned Zhejiang, Ningbo 4.1 3.0 2010+ Planned Hong Kong Black Point or Tai A 3.5 2.6 2011 Planned Shandong, Qingdao 4.1 3.0 n.a. Planned Jiangsu, Rudong 4.8 3.5 2011 Planned Hebei, Tangshan 4.1 3.0 2010+ Planned India Dahej 8.9 6.5 320 000 2004 Operation Hazira 3.7 2.7 320 000 2005 Operation Ratnagiri (Dabhol) 7.5 5.5 480 000 2008 Completed Dahej expansion 8.2 6.0 320 000 2008 Construction Kochi 3.4 2.5 220 000 2010 Planned Singapore Jurong Island 4.1 3.0 300 000 2012 Planned Thailand Map Ta Phut 6.8 5.0 360 000 2011 Planned Pakistan Port Qasim 4.8 3.5 300 000 2009 Planned Mexico (West) Costa Azul 10.3 7.6 320 000 2008 Construction Costa Azul expansion 10.3 7.6 2010+ Planned Manzanillo 5.0 3.7 300 000 2011 Planned Natural Gas Market Review 2007 • Annex F 279

Table 42 LNG regasification terminals (cont.) Capacity Country Terminal (mtpa) Storage m3 Start Status (bcm per year) Canada (West) Kitimat LNG 6.3 4.6 160 000 2014 Planned Chile Quintero 3.4 2.5 320 000 2009 Planned Northern mining region 1.8 1.3 2010 Planned France Fos Tonkin 7.0 5.1 150 000 1972 Operation Montoir de Bretagne 10.0 7.4 360 000 1980 Operation Fos Cavaou 8.3 6.1 330 000 2007 Construction Montoir expansion I 2.5 1.8 - 2011 Planned Montoir expansion II 4.0 2.9 120 000 2014 Planned Bordeaux (Le Verdon) 6.0 4.4 2011 Planned Bordeaux (Le Verdon) 4.0 2.9 TBD Proposed Le Havre (Antifer) 8.0 5.9 2011 Planned Dunkerque 6.0 4.4 2011 Planned Spain Barcelona 13.9 10.2 390 000 1969 Operation Huelva 9.7 7.1 310 000 1988 Operation Cartagena 7.4 5.4 287 000 1989 Operation Bilbao 8.0 5.9 300 000 2003 Operation Sagunto 6.0 4.4 300 000 2006 Operation Barcelona No.6 3.4 2.5 150 000 2006 Operation Huelva No. 4 3.9 2.9 150 000 2006 Operation Mugardos (El Ferrol) 3.6 2.6 300 000 2007 Construction Cartagena expansion 2.5 1.9 2006 Operation Cartagena No. 4 - 150 000 2008 Construction Bilbao No. 3 150 000 2008 Construction Sagunto expansion 2.0 1.5 2008 Construction Sagunto No. 3 150 000 2009 Construction Huelva No. 5 150 000 2009 Construction Barcelona No. 7 150 000 2009 Construction El Musel 7.0 5.1 300 000 2010 Planned Barcelona No. 8 150 000 2010 Planned Cartagena No. 5 150 000 2010 Planned Bilbao No. 4 2.5 1.8 150 000 2010 Planned Sagunto No. 4 150 000 2011 Planned Canary Islands 150 000 2009+ Planned Portugal Sines 5.5 4.0 240 000 2004 Operation Italy Panigaglia 3.5 2.6 100 000 1969 Operation Natural Gas Market Review 2007 • Annex F 280

Table 42 LNG regasification terminals (cont.) Capacity Country Terminal (mtpa) Storage m3 Start Status (bcm per year) Rovigo 8.0 5.9 250 000 2008Construction Livorno offshore 3.0 2.2 137 500 2009 Construction Brindisi 8.0 5.9 320 000 2010+Suspended Panigaglia expansion 4.5 3.3 2010+ Planned Belgium Zeebrugge 4.5 3.3 261 000 1987 Operation Zeebrugge expansion I 4.5 3.3 140 000 2007 Construction Zeebrugge expansion II 9.0 6.6 2011 Planned Netherlands Rotterdam (Gate) 8.0 5.9 360 000 2010 Planned Rotterdam (LionGas) 9.0 6.6 2010 Planned Rotterdam (offshore) Proposed Eemshaven 5.0 3.7 2011 Planned Germany Wilhelmshaven 10.0 7.4 2011 Proposed Poland Swinoujscie 2.5 1.8 2011+ Proposed United Kingdom Isle of Grain 4.9 3.6 200 000 2005 Operation Teesside 4.0 2.9 2007 Operation South Hook I 10.6 7.8 465 000 2008 Construction Dragon LNG 6.0 4.4 336 000 2008 Construction Isle of Grain expansion I 8.7 6.4 370 000 2008 Construction South Hook II 10.6 7.8 310 000 2009 Construction Isle of Grain expansion II 6.7 4.9 200 000 2010+ Planned Dragon LNG expansion 3.0 2.2 168 000 2011 Proposed Turkey Marmara Ereglisi 6.5 4.8 255 000 1994 Operation Aliaga 6.0 4.4 280 000 2006 Operation Greece Revithoussa 1.4 1.0 130 000 2000 Operation Croatia Krk Island 8.0 5.9 2012 Proposed United States (East) Everett 8.3 6.1 155 000 1971 Operation Lake Charles 13.1 9.6 285 000 1982 Operation Lake Charles expansion 6.0 4.4 140 000 2006 Operation Elba Island 15.5 11.4 338 720 1978 Operation Elba Island expansion I 4.2 3.1 160 000 2010 Planned Elba Island expansion II 5.1 3.7 160 000 2012 Planned Cove Point 10.3 7.6 485 000 1978 Operation Cove Point expansion 8.3 6.1 320 000 2008 Construction Gulf Gateway 4.9 3.6 2005 Operation Northeast Gateway 4.1 3.0 2007 Planned Natural Gas Market Review 2007 • Annex F 281

Table 42 LNG regasification terminals (cont.) Capacity Country Terminal (mtpa) Storage m3 Start Status (bcm per year) Cameron 15.5 11.4 480 000 2008 Construction Cameron expansion 11.9 8.7 160 000 2011 Planned Freeport 15.5 11.4 320 000 2008 Construction Sabine Pass 26.9 19.8 480 000 2008 Construction Sabine Pass expansion 14.5 10.7 320 000 2009 Construction Golden Pass 20.7 15.2 800 000 2009 Construction Neptune 5.2 3.8 2009 Planned Ingleside Energy 10.3 7.6 320 000 2010+ Planned Corpus Cristi 26.9 19.8 480 000 2010+ Planned Gulf Landing 10.3 7.6 2010+ Planned Crown Landing 12.4 9.1 360 000 2011 Planned Creole Trail 34.1 25.1 640 000 2011 Planned Port Arthur 15.5 11.4 480 000 2011 Planned Port Arthur expansion 15.5 11.4 480 000 2014 Planned Main Pass Energy Hub 10.3 7.6 2012 Planned Puerto Rico Penuelas 4.0 2.9 160 000 2000 Operation Mexico (East) Altamira 5.2 3.8 450 000 2006 Operation Canada (East) Canaport 10.3 7.6 320 000 2008 Construction Bear Head 10.3 7.6 360 000 2011 Halted Cacouna Energy 5.2 3.8 2010+ Planned Maple LNG 10.3 7.6 480 000 2010+ Planned Rabaska LNG 5.2 3.8 2010+ Planned Dominican Punta Caucedo 2.4 1.8 160 000 2003 Operation Republic Brazil Guanabara Bay 4.8 3.5 2009 Planned Pecem, Northeast 2.0 1.5 2009 Planned Operational total as of March 2007 545.1 400.0 27 299 920 Expected in end 2010 846.0 621.2 40 463 420 Proposed total 1 188.6 873.0 48 781 420

Natural Gas Market Review 2007 • Annex G 283

ANNEX G: LNG LIQUEFACTION PLANTS

Table 43 LNG liquefaction plants Capacity Capacity Region/Country Project Location Status Start (mtpa) (bcm per year) Asia Pacific Indonesia Bontang East Kalimantan 22.3 30.3 Existing 1977 Arun North Smatra 6.8 9.3 Existing 1978 Under Tangguh Bintuni Bay, Papua 7.6 10.3 2008 construction Donggi Central Sulawesi 2.0 2.7 Planned 2012 Malaysia MLNG Bintulu, Sarawak 8.1 11.0 Existing 1983 MLNG Dua Bintulu, Sarawak 7.8 10.6 Existing 1995 MLNG Tiga Bintulu, Sarawak 6.8 9.3 Existing 2003 Brunei Brunei LNG Lumut 7.2 9.8 Existing 1972 Australia North West Shelf 1-4 Burrup Peninsula 11.9 16.2 Existing 1989 Under North West Shelf 5 Burrup Peninsula 4.4 6.0 2008 construction Darwin LNG Point Wickham 3.7 5.0 Existing 2006 Pluto Burrup Peninsula 6.0 8.2 Engineering 2010 Gorgon Barrow Island 10.0 13.6 Engineering 2011 Ichthys Kimberly 6.0 8.2 Engineering 2012 Under Russia Sakhalin II Prigorodnoye 9.6 13.1 2008 construction Alaska Kenai LNG Cook Inlet 1.5 2.0 Existing 1969 Under Peru Peru LNG Pampa Melchorita 4.4 6.0 2010 construction Middle East Qatar Qatargas Ras Laffan 9.9 13.5 Existing 1997 RasGas Ras Laffan 6.6 9.0 Existing 1999 RasGas II (Trains 3-4) Ras Laffan 9.4 12.8 Existing 2004 RasGas II (Train 5) Ras Laffan 4.7 6.4 Existing 2007 Under Qatargas II (Train 4) Ras Laffan 7.8 10.6 2008 construction Under Qatargas II (Train 5) Ras Laffan 7.8 10.6 2008 construction Under Qatargas III (Train 6) Ras Laffan 7.8 10.6 2009 construction Under Qatargas IV (Train 7) Ras Laffan 7.8 10.6 2010 construction Under RasGas III (Train 6) Ras Laffan 7.8 10.6 2008 construction Under RasGas III (Train 7) Ras Laffan 7.8 10.6 2009 construction Oman Oman LNG Qalhat 7.2 9.8 Existing 2000 Natural Gas Market Review 2007 • Annex G 284

Table 43 LNG liquefaction plants (cont.) Capacity Capacity Region/Country Project Location Status Start (mtpa) (bcm per year) Qalhat LNG Qalhat 3.6 4.9 Existing 2005 UAE Adgas Das Island 5.8 7.9 Existing 1977 Under Yemen Yemen LNG 1 Bal Haf 3.4 4.6 2008 construction Under Yemen LNG 2 Bal Haf 3.4 4.6 2009 construction Iran Pars LNG 10.0 13.6 Planned 2011 Persian LNG 8.0 10.9 Planned 2012 Iran LNG Bandar Tombak 9.0 12.2 Planned 2012 Egypt Segas Damietta 4.8 6.5 Existing 2005 Segas Train 2 Damietta 5.3 7.2 Planned 2011 Egyptian LNG 1 Idku 3.6 4.9 Existing 2005 Egyptian LNG 2 Idku 3.6 4.9 Existing 2005 Egyptian LNG 3 Idku 3.6 4.9 Planned 2011 Libya Marsa el Brega Marsa el Brega 0.8 1.0 Existing 1970 Marsa el Brega Marsa el Brega 2.4 3.3 Planned 2010 Algeria Skikda GL1 KII Skikda 3.1 4.3 Existing 1972 Arzew GL4Z Arzew 1.1 1.5 Existing 1964 Arzew GL1Z (Bethouia) Arzew 8.2 11.2 Existing 1978 Arzew GL2Z (Bethouia) Arzew 8.0 10.9 Existing 1981 El Andalus LNG Arzew 4.0 5.4 Engineering 2009 (Gassi Touil) Skikda Skikda 4.5 6.1 Engineering 2010 Nigeria NLNG 1-2 Bonny Island 6.6 9.0 Existing 1999 NLNG Trains 3 Bonny Island 3.3 4.5 Existing 2002 NLNG Plus T4-5 Bonny Island 8.2 11.2 Existing 2006 Under NLNG Train 6 Bonny Island 4.1 5.6 2007 construction NLNG Seven Plus T7 Bonny Island 8.0 10.9 Engineering 2011 Brass LNG Baylesa 10.0 13.6 Engineering 2011 Olokola LNG (OK LNG) Olokola 11.0 15.0 Engineering 2011 Equatorial Under EG LNG Bioko Island 3.4 4.6 2007 Guinea construction EG LNG 2 Bioko Island 4.4 6.0 Planned 2012 Angola Angola LNG Soyo 5.0 6.8 Planned 2011 Under Norway Snøhvit Melkoya Island 4.1 5.6 2007 construction Russia Baltic LNG Ust-Luga 5.3 7.2 Planned 2010 Natural Gas Market Review 2007 • Annex G 285

Table 43 LNG liquefaction plants (cont.) Capacity Capacity Region/Country Project Location Status Start (mtpa) (bcm per year) Shtokman LNG Murmansk 15.0 20.4 Planned 2015 Trinidad Atlantic LNG 1 Point Fortin 3.3 4.5 Existing 1999 Atlantic LNG T2/3 Point Fortin 6.6 9.0 Existing 2002 Atlantic LNG T4 Point Fortin 5.2 7.1 Existing 2005 Train 5 5.2 7.1 Planned 2010 Venezuela Plataforma Deltana 4.7 6.4 Planned 2010+ Total 420.3 571.8 Total existing 189.7 258.1

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