Natural Gas Market Review

2009

Please note that this PDF is subject to specific restrictions that limit its use and distribution. The terms and conditions are available at www.iea.org/about/ copyright.asp

INTERNATIONAL ENE R G Y A GENCY 2009 Natural Gas Market Review

The global economic crisis has not spared the gas sector. Over the past year, we have moved from a tight supply and demand balance with extremely high gas prices to an easing one with plummeting gas prices. Since the last quarter of 2008, demand has been declining dramatically, essentially because of the global recession. Yet significant new volumes of liquefied natural gas will come on stream within the next few years, and the United States’ unconventional gas production has risen rapidly, with global consequences. It remains to be seen how these demand and supply pressures will play out, particularly in the pivotal power sector, in both OECD and non-OECD countries. Meanwhile, the security of gas supplies has once again become a critical issue, in particular in Europe after it experienced its worst supply disruption during the Russian- Ukraine crisis in January 2009. Moreover, the current market climate of weakening demand, lower prices and regulatory uncertainties added to the tough financial environment are likely to jeopardise investments, in particular in capital-intensive projects, further undermining long-term energy security in the most fundamental way when economies recover. The Natural Gas Market Review 2009 looks at these and other major developments and challenges in the different parts of the gas value chain in a selection of IEA countries – the United States, Canada, Spain, Norway, the Netherlands, and Turkey – as well as in non-IEA member countries in the Middle East, North Africa, Southeast Asia, and China.

(61 2009 21 1P1) 978-92-64-06413-3 €100 -:HSTCQE=U[YVXX: NATURAL GAS MARKET REVIEW

2009

INTERNATIONAL ENERGY AGENCY IEA member countries:

Australia INTERNATIONAL ENERGY AGENCY Austria

The International Energy Agency (IEA) is an autonomous body which was established in Belgium November 1974 within the framework of the Organisation for Economic Co-operation and Development (OECD) to implement an international energy programme. Canada It carries out a comprehensive programme of energy co-operation among twenty-eight Czech Republic of the thirty OECD member countries. The basic aims of the IEA are: Denmark „ To maintain and improve systems for coping with oil supply disruptions. „ To promote rational energy policies in a global context through co-operative Finland relations with non-member countries, industry and inter national organisations. France „ To operate a permanent information system on international oil markets. „ To provide data on other aspects of international energy markets. Germany „ To improve the world’s energy supply and demand structure by developing Greece alternative energy sources and increasing the effi ciency of energy use. „ To promote international collaboration on energy technology. Hungary „ To assist in the integration of environmental and energy Ireland policies, including relating to climate change. Italy Japan Korea (Republic of) Luxembourg Netherlands New Zealand Norway

Poland ORGANISATION FOR Portugal ECONOMIC CO-OPERATION AND DEVELOPMENT Slovak Republic Spain The OECD is a unique forum where the governments of thirty democracies work together to address the Sweden economic, social and environmental challenges of globalisation. The OECD is also at the forefront of Switzerland efforts to understand and to help governments respond to new developments and concerns, such as corporate governance, the information Turkey economy and the challenges of an ageing population. The Organisation provides a setting United Kingdom where governments can compare policy experiences, seek answers to common United States problems, identify good practice and work to co-ordinate domestic and The European Commission international policies. also participates in the work of the IEA.

© OECD/IEA, 2009 International Energy Agency (IEA) 9 rue de la Fédération, 75739 Paris Cedex 15, France Please note that this publication is subject to specifi c restrictions that limit its use and distribution. The terms and conditions are available online at www.iea.org/about/copyright.asp Natural Gas Market Review 2009 • Foreword 3

FOREWORD

2008 was a year split almost neatly in two functioning markets. Such markets in the energy world - prices and demand can deliver fl exible supply and demand rose inexorably into early July 2008, only to responses quickly and effi ciently, as we saw see dramatic falls as the depth and spread during the hurricane-related gas shortages of the global recession became apparent. in North America in 2008 and before that The gas industry was not immune from in 2005. But the strong price signals that these pressures, and gas markets have markets deliver also encourage timely and seen arguably greater price falls than oil, adequate investment essential for long- continuing well into 2009. term security of affordable gas supplies. This is particularly important in European As in previous Natural Gas Market Reviews, markets, where although encouraging we remain concerned from a long-term progress was made in a number of areas, perspective about investment throughout market functioning remains weak. the gas value chain, in upstream production, processing, liquefaction, pipeline transport As we have learnt from oil markets, and interconnection, and storage. While greater transparency is an important fi rst 2008 saw some progress in all areas, and step to improved market functioning, as a major expansion of LNG capacity is well as assessing and managing energy underway globally, overall investment emergencies. We will continue to work with continues to be inadequate, and the next market players and member governments, years promise to be especially diffi cult, and co-operatively with the EU and other with falling demand and prices weakening organisations, in the important task of all producers’ cash fl ows, and fi nancing ensuring the market is well supplied with conditions becoming tougher in both timely, accurate and harmonised data. debt and equity markets. Regulatory While this will inevitably entail additional uncertainties continue to slow investment. effort by companies, governments and organisations to collect and disseminate Early 2009 also saw Europe’s biggest gas such data, I believe the time has come crisis. Gas security has been high on the IEA to make the efforts needed to raise the agenda for some years, following Ministers’ quality and timeliness of gas data. instructions in 2005 and 2007, to report more closely on gas market developments Growing interconnections among energy and to bring forward concrete proposals markets make dialogue between IEA on gas security for consideration by IEA member countries and other major member governments. We anticipate that economies more important than ever. Such Ministers will indeed consider a set of dialogue is most benefi cial when grounded principles and an action plan to enhance in areas of mutual interest. In this context gas security at their next meeting in our on-going dialogue with Russia and October 2009. The Russia-Ukraine crisis its largest gas company Gazprom, are I has given added momentum to this work. believe, especially important.

One cornerstone of our efforts on This is the fourth Natural Gas Market gas security is the importance of fully Review. In conjunction with its sister 2009 OECD/IEA, © Natural Gas Market Review 2009 • Foreword 4

publication the Medium-Term Oil Market This review is published under my authority Review, it represents an important part as Executive Director of the International of our response to provide more medium Energy Agency. term analysis of oil and gas markets. As in previous editions, we welcome Nobuo Tanaka feedback. Gas issues will also be featured prominently in World Energy Outlook 2009, to be published in November this year. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Acknowledgements 5

ACKNOWLEDGEMENTS

The Review was prepared by the Energy Jane Barbiere, Madeleine Barry, Muriel Diversifi cation Division (EDD) of the Custodio, Rebecca Gaghen, Delphine International Energy Agency. The Review Grandrieux and Corinne Hayworth provided was designed and managed by Ian essential support to the Review’s production Cronshaw, head of EDD and the analysis and launch. Bertrand Sadin deserves a special was coordinated by Anne-Sophie Corbeau. mention for his continuous patience and heroic efforts in the Review’s preparation Signifi cant contributions were made from for printing. other colleagues in EDD, particularly Hiroshi Hashimoto, Wouter van der Goot, Mari The Review was made possible by assistance Vie Mæland, Nobuyuki Higashi, and also from the Governments of Belgium, Poland, Sara Piskor, François Nguyen, and Nasha and the United Kingdom; and GasTerra, Abu Samah. Contributors from the IEA Japan Bank for International Cooperation, included Tim Gould, Dagmar Graczyk, Isabel Petronas, Polish Oil and Gas Company, Murray, Sang Yoon, Christopher Segar, StatoilHydro and Tokyo Gas. and Brett Jacobs. Valuable comments and feedback were received from within the IEA, including Didier Houssin, and Aad van Bohemen. Timely and comprehensive data from Mieke Reece, Erica Robin and Olivier Lavagne d’Ortigue were fundamental to the Review. We would also like to thank Kieran McNamara, Miika Tommila and Maria Sicilia for their advice and support. 2009 OECD/IEA, © Maps or information for the maps sourced from the Petroleum Economist Limited www.petroleum-economist.com. Satellite derived imagery supplied to Petroleum Economist by NPA Satellite Mapping. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Table of contents 7

TABLE OF CONTENTS

Foreword 3 Acknowledgements 5 Table of contents 7 Executive summary 13

Recent events 17

Gas in an era of global recession 17

The evolution of gas prices 22

Trading developments in Western Europe 28

The 2009 Russia - Ukraine gas dispute 35

Gas Exporting Countries Forum 41

Investments 45

Supply investments in major producing regions 47

Investment in liquefaction capacity 61

Investments in regasification and pipelines 69

Investments in storage 84

The impact of the financial crisis on gas project financing 90

Developments in the LNG markets 95

An era of global projects begins 95

2008 LNG markets : sharp contrast between the first and second halves 96

LNG business outlook : 2009-13 99

Market developments 109

Gas for power 109

Towards greater transparency 115 2009 OECD/IEA, © Natural Gas Market Review 2009 • Table of contents 8

Non-OECD countries and regions 123

China 123 India 128 Southeast Asia 131 West Africa 136 Middle East and North Africa 143

OECD countries and regions 147

North America 147 Norway 153 The Netherlands 157 Spain 162 Turkey 168

Annex 1: Abbreviations 173

Annex 2: Glossary 177

Annex 3: Conversion factors 181 2009 OECD/IEA, © Natural Gas Market Review 2009 • Table of contents 9

List of fi gures

Figure 1 • Demand trends in OECD Europe 18 Figure 2 • Industrial demand trends in the United States 19 Figure 3 • Supply balances in OECD regions 21 Figure 4 • International gas prices 2007-2009 23 Figure 5 • NBP and HH day-ahead prices and differential 25 Figure 6 • Developments on European Continental hubs 29 Figure 7 • Russian volumes lost during the January 2009 disruption 37 Figure 8 • Replacing the missing Russian volumes 40 Figure 9 • Possible future gas demand trends 46 Figure 10 • Gas production and consumption in the ‘Big 3’ 48 Figure 11 • Gazprom’s gas production 50 Figure 12 • LNG liquefaction, existing, planned and under construction 62 Figure 13 • European storage capacities under construction and planned 87 Figure 14 • Expanding size of LNG new build carrier ships 98 Figure 15 • Liquefaction and regasification capacity, existing, under construction and planned 100 Figure 16 • Changes in power generation by fuel source in OECD 110 Figure 17 • OECD capacity expansion 112 Figure 18 • North American production 150 Figure 19 • Average weekly rigs in North America 151 Figure 20 • Annual LNG imports to the United States 152 Figure 21 • Norwegian gas production 2002-2009 154 Figure 22 • Dutch gas balance 1960-2008 161 Figure 23 • Spanish gas consumption 2000-2008 163 Figure 24 • Evolution of Spanish gas supply 165 Figure 25 • Turkish annual gas use 168 Figure 26 • Turkish gas use 2008-09 169 Figure 27 • Turkey’s long-term contracts vs. demand 170 2009 OECD/IEA, © Natural Gas Market Review 2009 • Table of contents 10

List of tables

Table 1 • Traded and physical volumes at European hubs 30 Table 2 • Evolution of the number of gas market areas 33 Table 3 • Summary of responses by European countries 39 Table 4 • Production and capacity additions during 2000-15 by Qatar, Iran and Russia 48 Table 5 • South Pars development phases 57 Table 6 • LNG export projects nearing final investment decisions (FIDs) in 2009 and 2010 66 Table 7 • Australia’s coalbed methane/coal seam methane race 68 Table 8 • Investments in regasification terminals 72-73 Table 9 • Regasification terminals under construction in Europe 74 Table 10 • Pipeline projects in Europe 77-78 Table 11 • LNG regasification terminals in South America 81 Table 12 • World underground gas storage - capacity summary (working capacity) 89 Table 13 • Recent LNG supply problems (force majeure) at a glance 97 Table 14 • At a glance: other new liquefaction projects in 2009 102 Table 15 • Sakhalin II - 25 years in making 103 Table 16 • Data published by Transmission Systems Operators 117-118 Table 17 • Data published by Storage Systems Operators 121 Table 18 • Existing long-term LNG sales and purchase agreements 125 Table 19 • Gas prices in Malaysia (as of March 2009) 134 Table 20 • New power plants in Algeria 2008-12 (planned and under construction) 141 Table 21 • Power plants projects in the Netherlands 159 Table 22 • Conversion factors for natural gas price 181 Table 23 • Conversion factors for natural gas volumes 181

List of maps

Map 1 • European response to the gas dispute between Russia and Ukraine 38 Map 2 • Gas Exporting Countries Forum’s participants 42 Map 3 • Russian gas infrastructure 52 2009 OECD/IEA, © Natural Gas Market Review 2009 • Table of contents 11

Map 4 • Iranian and Qatari gas infrastructure 55 Map 5 • Caspian gas infrastructure 60 Map 6 • Main supply projects to Europe 75 Map 7 • Global LNG projects starting production in 2009 96 Map 8 • Global LNG trade in 2008 97 Map 9 • GSE storage data coverage 120 Map 10 • Chinese gas infrastructure 127 Map 11 • Indian gas infrastructure 131 Map 12 • South East Asian gas infrastructure 132 Map 13 • African gas infrastructure 139 Map 14 • North American gas infrastructure 148 Map 15 • Norwegian gas infrastructure 156 Map 16 • Gas infrastructure in the Netherlands 162 Map 17 • Spanish gas infrastructure 166

List of boxes

Box 1 • The Southern Corridor and the Georgian crisis 79-81 2009 OECD/IEA, © © OECD/IEA, 2009 Natural Gas Market Review 2009 • Executive summary 13

EXECUTIVE SUMMARY

Strong demand in the fi rst half of 2008 year earlier, despite destructive hurricanes reverses dramatically later in the year in the late summer, and has continued to and into 2009 show around 4% increases in the early months of 2009. Growth at these levels The fi rst half of 2008 saw strong gas represents a major turnaround from the demand growth in most IEA regions of up to production declines of about 2% per year 10% in some countries. This began to slow observed earlier in the decade, challenging in mid year, then to reverse dramatically the wisdom that United States production late in 2008, and continue to fall into 2009, would inevitably decline, increasing the as the global recession hit gas hard. The need for large-scale LNG and pipeline industrial sector was especially hit, as cold imports. Indeed LNG imports in 2008, at weather kept domestic and commercial less than 10 bcm, were less than half the heating demand strong. Demand for gas- level of 2007. LNG was thus freed up for fi red power slumped, as industrial power other markets, and over the course of demand fell in line with the economic 2008, some 20 bcm of “Atlantic” LNG was downturn, and as gas-fi red power is shipped to Pacifi c markets, double the generally the most expensive in the mix levels of 2007, in response to the strong of power sources, notwithstanding very demand in those regions in the fi rst half of marked price falls which accompanied 2008. Hence United States unconventional weakening demand. gas production is of global signifi cance. However, low gas prices have reduced the Gas prices peaked in mid 2008 at levels gas rig count by nearly half in April 2009 over USD 13 per MBtu in the United States compared to the year before, and it seems for example, but have since dropped to inevitable that growth in output will slow. around USD 3.50 per MBtu in April 2009. The future of United States gas output British prices have fallen from similar remains one of the major uncertainties in highs to around USD 4 per MBtu. Oil-based global gas markets. prices in Japan and Continental Europe, with their in built time lags, continued to Globally, LNG capacity continued to grow, rise through most of 2008, but with the although various problems restricted fall in oil prices can be expected to decline output, so actual production grew only through 2009 to average around USD 7-8 modestly to 240 bcm in 2008. However, per MBtu in the case of Europe. Plentiful a massive increase in new LNG capacity gas supply is also playing a strong role in is already underway in 2009, and the next markets where gas-on-gas or gas-on-coal three years will see capacity grow to at competition can be seen. least 370 bcm, an astonishing increase, without precedent in the LNG world. Thus, Gas supply grows strongly 2009 and 2010 will test the fl exibility and resilience of the global LNG market. Norway Of particular note is the continuing also continued its export led expansion, growth in unconventional gas production with gas output in 2008 growing by 10% in the United States. Gas production in to almost 100 bcm. Growth will continue 2008 showed a near 8% increase over a into 2009, and is set to rise to beyond 2009 OECD/IEA, © Natural Gas Market Review 2009 • Executive summary 14

120 bcm in coming years, making Norway such approvals adversely, although these the largest IEA gas exporter. projects are to meet medium to long- term demand. Globally there is nearly Investment outlook weakens twice as much regasifi cation capacity operating or well under construction, Falling gas prices and volumes have taken compared to liquefaction capacity. This a heavy toll on all producers’ cash fl ows, imbalance is likely to remain an ongoing adding to the already serious problems in feature of the LNG trade well into the gas investment throughout the value chain medium term. identifi ed in earlier Natural Gas Market Reviews. Large investments continue to The world’s largest producer, Russia, faces be needed to meet growing demand in considerable challenges, both fi nancial the medium to longer term, and to offset and technical. Gazprom, accounting for falling output in many consumer countries. around 80-85% of Russian gas output, For example, UK gas output in 2008 was will see prices for western European two thirds of 2003 levels, and declines at exports fall from USD 12 per MBtu in the end of 2008 and early 2009 were around 2008 to USD 7-8 per MBtu in 2009, and 10%. While some relief can be expected has also seen volumes fall sharply in the from the high engineering, procurement fi rst quarter of 2009. Gazprom has wisely and construction costs that were a feature prioritised its capital expenditure, to focus of hydrocarbon developments from 2004 on upstream in established and new areas to late 2008, fi nancing problems are likely (Yamal), on the pipeline infrastructure to to bedevil all new construction projects support these, as well as the Nord Stream in 2009 and even into 2010, especially for project, linking Russia directly to Germany the long lead time, high capital intensity via the Baltic Sea. Price reform continues projects found in many parts of the gas in Russia, which should drive greater sector. Regulatory uncertainties remain effi ciency in gas use, notably in the power as a barrier to investment, and any rise in sector. gas demand will await economic recovery, likely at best to be sluggish and uncertain, Power sector demand likely to drop further complicating investors’ decision sharply making. While gas demand for power was strong in In the LNG sector, notwithstanding the fi rst half of 2008 in many IEA countries, the massive increases in capacity that again the collapse of industrial output in will be seen in the next few years from the fi nal quarter of 2008 and into 2009 projects under construction, very few saw industrial power demand drop by up new projects have been sanctioned in to 10% in many countries, both in and recent years. Unless 2009 and 2010 see outside the IEA. While this translates into a number of new project approvals, there total electricity demand declines of around will be a dearth of new capacity in the 4%, falls in gas-fi red power are likely to period after 2012. Financing problems, be around double these levels, given the plus uncertain demand growth will impact position of gas in the merit order, as seen 2009 OECD/IEA, © Natural Gas Market Review 2009 • Executive summary 15

in some countries in the early months of to be redirected speedily and effi ciently are 2009. Hence, gas demand from the power not present in some areas. Only one major sector through 2009 is likely to be weak, cross-border movement of gas was seen although the outlook in the medium throughout the crisis, that of gas fl owing term remains strong. Most power plants out of the United Kingdom to Europe, under construction and planned in OECD although the United Kingdom suffered no countries are gas-fi red. Gas power has loss of supply, since it imports no Russian shorter lead times, lower capital cost, a gas. Encouraging progress has been made smaller footprint and the lowest carbon in enhancing market fl exibility in Europe, emissions of any fossil fuel. New gas-fi red such as greater hub trading and other capacity is also being developed in many improvements in market transparency. non-OECD countries, although generally But, clearly more needs to be done urgently coal remains the dominant fuel in the to make Europe’s gas market work better. power sector there. Current investment In the medium to longer term, Europe and fi nancing uncertainty may actually also needs greater investment in more favour gas further, with its smaller unit varied sources and routes for gas supply, size and shorter lead times responding enhanced gas storage, and much more to an uncertain demand recovery path. diversity in its electricity sector, embracing Greater deployment of renewables over renewables, nuclear and coal, with improved the medium term may also enhance the environmental performance. role of gas to balance intermittent sources such as wind. Non-OECD gas use grows fast

Europe’s biggest gas security crisis Many gas producers are consuming more gas in their own domestic markets, notably The beginning of 2009 saw Europe’s most Iran and other Middle Eastern countries. serious gas security crisis, with nearly Iran, as the second biggest gas reserve 7 bcm of gas not delivered to Europe and holder, seems unlikely to be a signifi cant Ukraine over the fi rst three weeks of the exporter before 2015, at the earliest. Other year. While some additional Russian gas gas suppliers such as Qatar are imposing supplies were available through Yamal moratoria on further gas development. and Blue Stream pipelines, as well as some Both China and India are emerging as spot LNG in southern Europe, the bulk of major gas users, although their energy the European response was through rapid mixes seem certain to be dominated by storage drawdown. Countries lacking coal for the foreseeable future. Both adequate storage (chiefl y in eastern and countries will be able to import around southern Europe) suffered supply shortfalls, 30 bcm of LNG within the next few years since the crisis again demonstrated that gas on the basis of regasifi cation terminals cannot fl ow easily across borders in Europe. being built and contracts concluded, and This is because there is a lack of physical both could exceed 100 bcm of annual gas interconnection capacity, capable of consumption in the near to medium term, reversing the fl ow of gas from west to east, bigger than any OECD European or Pacifi c or the market mechanisms that enable gas gas user. 2009 OECD/IEA, © © OECD/IEA, 2009 Natural Gas Market Review 2009 • Recent events 17

RECENT EVENTS

Gas in an era of global Gas demand continued to grow strongly recession by 5% during the fi rst half of 2008. The growth was particularly signifi cant during „ During 2008, natural gas moved from the January-April period but slowed a relatively tight supply and demand afterwards. This was partly driven by a balance to an easing one. This will rebound of European residential demand accelerate during 2009 as new supply as winter 2007-08 was colder than the capacity comes on line. previous one. Furthermore, additional gas-fi red capacity coming on line in many „ Overall there was a 1% annual increase OECD countries supported gas use in the in OECD countries in 2008: gas demand power generation sector. Gas demand in rose strongly in the fi rst half of 2008, the industrial sector was not yet affected but declined over the last quarter and by the economic crisis or higher prices. fell even more rapidly in early 2009. Demand trends changed substantially „ For 2009, we anticipate demand to during the second half of 2008 and in decline, especially in the industrial particular during the last quarter. The sector. Gas demand in the power combined impact of a sharp economic generation sector will be affected downturn and relatively high oil-linked differently in each region depending gas prices in some markets, notably on the relative gas and coal prices. Continental Europe, resulted in a 3.7% decline of gas demand during that period. „ Demand is expected to rebound in the Rising gas procurement prices translated medium term driven by the power into higher energy bills for residential users generation sector. while the recession caused energy costs to represent a higher share of households’ disposable income. This is likely to have resulted in residential users starting their OECD demand trends over 2008 boilers later and lowering the thermostat. and early 2009 Many factories were closed during an extensive period over Christmas and well Gas demand in OECD countries increased into 2009. In particular fertilizer plants by 1% in 2008 from 1 507 bcm to closed down or halved their production. 1 522 bcm. Growth has varied markedly In the United States, industrial demand across regions and countries, from Japan was 5% lower than 2008 during the fourth which was up 4.6% to 100 bcm to OECD quarter but the decline continued to Europe up by 2.8% to the United States accelerate from 4% in November to 15% which increased by less than 1%. This in February 2009. Industrial gas use shows growth has happened despite a high price a similar pattern in Japan, with January and environment and negative economic February 2009 dramatically lower than the growth towards the end of the year. But same period in 2008. Gas use in the power the year 2008 was very much a tale of two generation sector has been also affected: distinct time periods. while coal prices have plummeted from 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 18

around USD 200 per tonne mid-2008 to fi red plants over coal-fi red plants. A colder around USD 60 per tonne in May 2009 winter in 2007-08 drove the increase and CO2 prices have collapsed to around in Dutch demand. On the other hand, EUR 10 per tonne, oil-linked gas prices at demand fell by more than 5% in Australia. around USD 10-11 per MBtu have put gas- Overall, for 2008, given the speed, breath fi red power at a disadvantage in the merit and depth of the recession, gas demand order, especially in Continental Europe. held up reasonably well.

Demand grew during 2008 quite strongly – Demand expectations in the short by over 5% – in a number of countries such and medium term as Japan, Finland, Ireland, the Netherlands, Switzerland and the United Kingdom, each We expect the declining consumption of them for different reasons. Demand was trend to continue well into 2009 as the strong in Japan partly due to continued economic recession spreads and deepens outage of the Kashiwazaki-Kariwa nuclear in OECD countries. The OECD projects power plant while, in the United Kingdom, economies to contract by 4.3% in its growth was due to a combination of 30 member countries in 2009 before a higher residential demand during the fi rst policy-induced recovery gradually builds quarter and a preferential dispatch of gas- momentum through 2010. In January

Figure 1 Demand trends in OECD Europe

180 000

Mcm

160 000

140 000

120 000

100 000

80 000 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2003-2008 range 2007 2008 2009

Key point: Strong growth in the first half, declines in the second half

Source: IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 19

2009, demand declined by 6% in Japan America, -13% in OECD Europe, and stable and 0.5% in the United States. This in OECD Pacifi c). decline accelerated in February to 18% in Japan and 7% in the United States. The Assuming normal weather conditions, relatively low decline in the United States we expect the economic downturn in January is mainly due to higher demand to impact demand across all sectors: in the residential and commercial sectors factories’ closure or the reduction of their due to cold weather while demand in the production will impact their energy – and industrial and power generation sector gas – consumption. The trend observed in has declined substantially compared to the United States is likely to be similar in 2008. In January 2009, only extreme cold other countries. In Spain, demand declined weather in Europe (100 Heating Degree by 17% during the fi rst quarter 2009 days (HDD) colder than normal) and in the (with an impressive 31% decline from United States (35 HDD colder than normal the power sector and 9% decline from and 70 colder than 2008) prevented other sectors including industry), while demand from weakening substantially. In in Turkey, demand fell by 10% during the March 2009, gas demand declined by 7% fi rst quarter – with a 24% decline in the in OECD countries (-3% in OECD North industrial sector.

Figure 2 Industrial demand trends in the United States

20

bcm

18

16

14

12

10 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2002-2007 range 2006 2007 2008 2009

Key point: Dramatic fall at the end of 2008 and early 2009

Source: IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 20

Electricity demand is also likely to be OECD supply trends over 2008 lower in 2009 as it usually follows GDP growth closely. As gas prices will remain All OECD regions are dependent on relatively high in the fi rst part of 2009 in imports, the least dependent being North Continental Europe and OECD Pacifi c, gas- America. Indigenous gas production fi red plants will usually be at the margin in OECD countries increased by 4% or and generally the fi rst to be affected 47 bcm between 2007 and 2008 to reach by lower power demand. Gas demand 1 171 bcm. Almost all this was accounted from the power generation sector will for by the United States with a 42 bcm be less affected in countries with spot increase. OECD imports grew by 2% to prices, which were half oil-linked prices 712 bcm, again showing more than 10% prevailing in Continental Europe and growth in the fi rst four months of the elsewhere in early 2009. As oil-linked gas year but falling later in the year by nearly prices decline over the course of the year, 8%, while exports increased by 7% to we expect gas to be in a better position 352 bcm. Exports are mainly via pipeline to compete against coal in the power (three quarters from Canada, Norway generation sector. Furthermore, around and the Netherlands). Australia, Norway 17 GW of gas-fi red capacity is expected and the United States are the only LNG to be added in 2009 in OECD countries. exporters in the OECD region. Finally, residential users can be expected to pay careful attention to their heating In North America, domestic production bills and reduce their consumption during increased by 36 bcm, falls in Canada the fi rst spring months: although gas offsetting some astonishing gains in the companies have started to pass through United States. Rising unconventional lower procurement costs in early 2009, gas production has quite substantially end-user prices remain relatively high. affected the supply picture so that LNG import requirements have been scaled In the medium term we expect demand to down in 2008 to less than half 2007 levels. rebound as the fundamental drivers behind Pipeline imports were also slightly lower, gas demand growth are still present: new but their relative share of total imports power plants under construction in OECD for this region increased. countries are predominantly gas-fi red. The current diffi cult investment environment OECD Europe’s production increased by is likely to favour gas as gas-fi red plants 13 bcm, but this was essentially due to benefi t from quicker construction times, two countries – Norway and to a lesser are less subject to public resistance than extent the Netherlands. Most other OECD coal and less politically sensitive than European countries saw their domestic nuclear. Furthermore many non-OECD production decline. Norwegian production countries also favour gas: in particular grew by 9 bcm as the recent start in 2007 Middle East countries are replacing their of Ormen Lange and Snøhvit enabled these oil-fi red capacity with new capacity fed two fi elds to add 14 bcm of incremental with domestic gas. production, compensating for the decline of other fi elds. Dutch production – still a 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 21

Figure 3 Supply balances in OECD regions

2 000

bcm

1 500

1 000

500

0

-500 2007 2008 2007 2008 2007 2008 2007 2008 OECD Total OECD North America OECD Pacific OECD Europe

Total exports Stock change Total imports Indigenous production

Key point: All regions import

Source: IEA. source of seasonal swing – refl ects the Australia. Although some LNG producers colder winter in early 2008. Some months from the Atlantic basin increased their in early 2008 showed a 50% increase deliveries to this region signifi cantly over the corresponding month in 2007. totalling more than 20 bcm or 8% of Very few countries are likely to see their global LNG production, Pacifi c and Middle domestic production increasing over the East producers hold the lion’s share of LNG next few years. Imports increased faster imports. Australia exports predominantly than production, in particular imports from to Japan. non-OECD. Exports were predominantly for OECD Europe, but for the fi rst time Supply expectations in the short in history, a European country (Norway) and medium term exported to other OECD regions via LNG. Despite lower demand in the fourth In OECD Pacifi c, domestic production quarter of 2008 and early January 2009, declined by 2 bcm as Australian gas OECD domestic gas production remained production declined. The region remains strong. Production was still on an upward completely dependent on LNG imports, trend in OECD North America despite lower the bulk of which originate from non- prices. It remained stable in the Pacifi c and OECD countries and the rest from declined slightly in OECD Europe. Imports 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 22

have been declining except in OECD Pacifi c. The evolution of gas prices The drop has been particularly sharp in OECD Europe and affected both pipeline „ Gas prices in key liberalised markets and LNG exporters, especially those selling in the United States and the United on still high oil-based prices. Kingdom fell from USD 13-14 per MBtu in mid-2008, to at or below USD 4 per In the short term, we anticipate the most MBtu in April 2009. Unlike oil, where expensive sources of gas to be affected prices have stabilised, prices in these by the collapse of demand. In particular, markets have continued to fall sharply buyers will try to run their contracts at over the early months of 2009. the minimum levels using the embedded fl exibility, opting to reduce their supplies „ Prices in markets linked to oil, such to the minimum allowed in the contract. as Japan and Continental Europe, This will affect both pipeline and LNG were slower to fall from their peaks contracts based on oil prices as the lag time approaching USD 15 per MBtu, as these in the formulas means that the oil-linked prices typically have three- to six- gas prices are still relatively high over the month lags. Over the course of 2009, fi rst half of 2009. Cheaper spot pipeline they are expected to fall to around or LNG based on National Balancing USD 6-7 per MBtu. Point (NBP) or Henry Hub (HH) prices will compete actively against these sources of „ International prices are showing a gas. In spring 2009, spot prices were less degree of convergence, as greater LNG than half oil-linked contract prices. trade links regions more closely.

As new LNG liquefaction terminals are expected to come on line in 2009, the Price convergence and divergence question is how the market will adjust, in a context of declining demand. If they Unsurprisingly, the price story in 2008- follow the previous years’ patterns, some 09 resembles demand, in that it consists terminals may start later than expected. of two distinct periods. All regional gas One major uncertainty for 2009 is prices continued to increase up to mid- around unconventional gas production 2008 to USD 12-13 per MBtu on the back in North America: already the number of of increasing oil prices, and a tightening rigs has halved between October 2008 supply and demand balance. The trend and May 2009. The question is whether completely reversed from the second half unconventional gas production in North of 2008, as spot prices started to steadily America can remain robust at prices below decline fi rst in the United States and later USD 4 per MBtu. in the United Kingdom.

However oil-linked gas prices in Japan continued to increase further to above USD 15 per MBtu bearing the legacy of the above USD 100 oil prices seen up to 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 23

Figure 4 International gas prices 2007-2009

25

20

USD per MBtu 15

10

5

0 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 NBP (monthly average) Henry Hub (monthly average) German border price Japanese LNG Japanese spot LNG

Key point: Gas prices fall, but at different rates in different regions

Source: Bundesamt für Wirtschaft und Ausfuhrkontrolle (BAFA), ICIS Heren, ICE, Trade Statistics of Japan (Ministry of Finance), European Central Bank, Federal Reserve.

July 2008 while Continental European gas through formal linkages or through inter- prices fl attened above USD 12 per MBtu fuel competition in the end-user market. during the second half of 20081. They But the fundamental reason is an easing started to decline only in late 2008 due to of the supply and demand balance on the time lags embedded in the long-term gas markets, as demand weakens while contracts’ formulas. Prices have continued substantial LNG, and in North America, to fall in 2009, with prices in the United unconventional gas supplies, come States and the United Kingdom now in the on stream, leaving some LNG cargos range of USD 3.5-4 per MBtu respectively, struggling to fi nd a home. Increasingly the less than half the price of oil on an energy US and UK markets are starting to be more content basis. closely linked through global LNG markets with a convergence of spot prices on both Part of the fall in prices is due to the sides of the Atlantic. general collapse of energy prices – either

1. The German border price expressed in Euros continued to increase up to November 2008. The German and Japanese prices expressed in Euros and Yen are converted into prices in US Dollars using the exchange rate of the month. This does not refl ect the complexity of the long-term formulas and the lags, but these cannot be adequately quantifi ed as all suppliers’ contract terms differ. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 24

The two main spot markets in the United – of additional LNG supplies. Weakening States and the United Kingdom had been LNG demand in Asia is resulting in an until late 2008 mostly disconnected. oversupply of fl exible short-term LNG in Although prices have been following the the Atlantic basin, free to target either same increasing pattern since September the United States or the United Kingdom 2007 due to the overall rise of all energy (or displace some more expensive pipeline prices, there were only a few periods with gas in Europe). With this additional LNG some convergence – usually during the added to traditional supplies, the United lower demand summer periods. Global Kingdom became very well supplied with gas markets were relatively tight up to gas and the linkage to continental oil- mid-2008 due to increasing demand and linked prices seen in 2007-08 was severed relatively small additional volumes of leading towards a convergence to Henry LNG coming on line. Strong demand for Hub price levels. LNG in Asia – with some Japanese spot prices bidding above oil parity – led to Meanwhile oil-linked prices in Europe and more supply tightness in the Atlantic Japan remained very high in much of 2008 basin. The UK market was quite volatile with falls only seen from late 2008-early with Continental European prices having a 2009, refl ecting the divergence of pricing major infl uence due to increasing import systems within each region and different dependency while the Henry Hub price (HH) lags of price rises and falls relative to oil. was set by the marginal supplier – either unconventional gas or LNG. The spread The price differential has created between HH and NBP averaged USD 2 per signifi cant arbitrage opportunities as LNG MBtu over September 2007-April 2009, regasifi cation is being expanded both above but not signifi cantly higher than in the United States and in the United transport cost differential of LNG from Kingdom – the only really liquid market the Middle East or North Africa. in Europe. During the winter (November 2008-January 2009), the spread between Since late 2008, spot prices have started to European contract prices and the NBP converge, showing similar declining trends or Henry Hub respectively averaged refl ecting the impact on spot prices of USD 4.7 and 7.4 per MBtu. For a 150 000 m3 plentiful LNG supply on international gas cargo, this means a gain of between markets and of increasing global exchange USD 16 and 25 million. This notably resulted of gas between different regions. This has in the Interconnector between the United weighed down on the HH and NBP prices Kingdom and Belgium, fl owing in export leading to a collapse of both prices to mode from the United Kingdom to Europe around or below USD 4 per MBtu in April almost constantly since December 2008. 2009 while the spread between both This completely different pattern from prices halved. Such convergence has been historical trends, was exacerbated by the made possible due to the coincidental Russia-Ukraine crisis; in January 2009, weakening of demand in most LNG- some 0.8 bcm of gas was exported from importing countries combined with the United Kingdom. This has continued the arrival – or expectations of arrivals into 2009 making the United Kingdom a 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 25

Figure 5 NBP and HH day-ahead prices and differential

14 7

12 5

10 3

8 1

NBP <> HH (USD per MBtu) 6 -1

NBP and HH prices (USD per MBtu)

4 -3

2 -5 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 NBP <> HH (right axis) NBP (left axis) Henry Hub (left axis)

Key point: Spot prices start to converge in 2009

Source: ICIS Heren, ICE, European Central Bank. transit country. Furthermore, European with spikes up to USD 14 per MBtu, partly players are now keen to use the fl exibility linked to changing supply fundamentals. in their contracts to import less oil-priced Until mid-2008, NBP prices were mostly contracted gas and buy more spot LNG infl uenced by continental oil-linked gas – as is the case in Spain (see below). prices for two reasons:

Regional analysis „ Competition with European continental markets. With production falling by European prices 8% per year since 2004, the United Kingdom has become increasingly The European markets are more than ever dependent on imports. During the characterized by the duality between oil- winter, oil-linked European prices have linked gas prices on the Continent and been setting a fl oor to winter NBP NBP spot prices in the United Kingdom. prices – unless demand is exceptionally However Continental spot markets such weak as was the case in winter 2007- as Zeebrugge and the Title Transfer 08 or since the end of summer 2008. Facility (TTF) have gained in liquidity and The United Kingdom has become a net are usually tracking NBP prices. importer of gas even during summer. Since the Langeled pipeline came on NBP prices rose from USD 3-5 per MBtu line, Norwegian gas has become more to USD 10.7 per MBtu on average in 2008 important for the United Kingdom’s 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 26

supply and demand balance, but at above prices LNG producers are prepared the same time, it can be dispatched to to accept, bringing a degree of gas-to- Continental markets if NBP prices are gas competition to Europe. Furthermore, too cheap. The same applies to LNG in the extreme volatility of contract prices the Atlantic basin which can equally has broken up the traditional seasonality target Continental Europe or the United of NBP prices. Since late 2006, winter Kingdom markets. prices have always been lower or equal to the following summer prices meaning „ Storage refi lling. The United Kingdom a more expensive refi lling. In early 2008, needed to refi ll its 4 bcm storage during storage players kept gas in store and summer mostly with Continental gas started injections earlier. While during fl owing through the Interconnector winter 2007-08 they were able to resell between the United Kingdom and gas in store at higher prices on the United Belgium. This required NBP prices Kingdom market, some of the stored gas during the winter to be at a premium was shipped to Continental markets and over expectations about the next sold at advantageous contract prices summer continental gas price to during winter 2008-09. This year, players provide the incentive to withdraw gas will be able to refi ll depleted storage at from storage. lower prices.

Up to end-2008, NBP prices have been In Continental Europe, links to oil in contract supported by still increasing oil-linked prices prevail despite increased hub trading. European gas prices, production diffi culties Contract prices increased from an average as well as uncertainties about Norwegian of USD 7 per MBtu in 2007 to around USD 13 and LNG supply. But as supply confi dence per MBtu in August 2008 before starting to increased with the arrival of LNG cargoes come down signifi cantly in late 2008. They to the expanded Isle of Grain terminal and are expected to go down further in 2009 to demand weakened further, they came reach USD 6-7 per MBtu by mid-2009 and down sharply to USD 7 per MBtu after the then stabilise, in line with oil prices observed Russia-Ukraine crisis and USD 4 per MBtu in the fi rst months of 2009. in April 2009. Continental spot prices on the Dutch Two radical changes have happened over hub (TTF) and Zeebrugge are now closely the past year on the United Kingdom linked to the NBP. Zeebrugge moves are market: through the expansion of its tracking almost exactly the moves on NBP; regasifi cation capacity from 8 to 34 bcm some disparities exist with TTF refl ecting coupled with ample global LNG supply, different supply and demand dynamics as the United Kingdom has become a transit well as some transport constraints. One market for LNG – and probably Norwegian important question is how the prices on gas as well – to the Continent. This will the other hubs – PEG, EGT and PSV2 – will continue as long as oil-linked prices remain

2. PEG, Point d’échange de gaz (France) ; EGT: E.ON Gas Transport (Germany) and PSV: Punto di Scambio Virtuale (Italy). 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 27

evolve as supply in these markets remains as a well-balanced and effi cient gas market dominated by long-term contracts. prevented a price hike. Prices fell to USD 7 per MBtu in October and to less than USD 4 Spain is a perfect example of this European per MBtu in April 2009 for the fi rst time price duality: on one side, most established since September 2006 on plummeting players buy pipeline gas as well as some industrial demand. Furthermore storage LNG under long-term contracts with an levels are relatively high in the United oil-price indexation. But Spain is now States compared with the previous years more exposed to global LNG markets and the injection period started in early through its 58 bcm regasifi cation capacity April with storage levels more than 12 bcm – compared to 14 bcm of pipeline. Even higher than 2008. This factor, added to given its 11% growth through 2008, depressed demand and the fact that the Spain is only a 40 bcm market, so most of United States is often considered as the these terminals are underutilised making residual market for LNG, could push prices it possible to use the spare capacity to further down until they reach a fl oor at import spot LNG at international prices. which signifi cant switching occurs in the Since early 2009, Spanish LNG prices have power generation sector, unconventional been at a discount to the NBP, rather than or other domestic gas production is a premium to it, refl ecting a 20% drop of reduced, or, (least likely) if LNG producers demand during the fi rst quarter. There are decide to shut in or postpone new limits in the amount that companies can liquefaction trains. source on the hubs because of minimum take-or-pay commitments under long- Asian prices term contracted gas. Some companies already face diffi culties in meeting their In the Asian Pacifi c region, markets have commitments. On the back of higher seen a signifi cant growth in LNG spot and contract gas prices, those companies with short-term trading over the past year. A ability to import LNG have been increasing large portion of those cargoes are priced their short-term purchases of LNG and differently from those under long-term reducing contracted delivery of pipeline contracts. A signifi cant spread between gas, anticipating much lower contracted prices for short-term and spot cargoes prices later in the year. (USD 15 - 25 per MBtu) and long-term import prices has been observed. Even North American prices among long-term contracted volumes, there were signifi cant divergences in In North America, prices rose in 2008 based prices from USD 7.5 to USD 13 per MBtu also on strong demand, lower inventories, on average by source in 2008. Long-term and cold weather, from around USD 7 oil-linked contract prices have started per MBtu to peak at USD 13.50 per MBtu to come down on the back of declining in late June 2008. Then prices collapsed, oil prices but only from December 2008. falling further and faster than oil. Even the Similarly to European prices they are September 2008 hurricanes in the Gulf of expected to come down to around USD 6-7 Mexico didn’t increase prices signifi cantly, per MBtu over 2009. Furthermore demand 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 28

for LNG cargoes is likely to be much lower In 2008 traded volumes on Western this year. In January 2009 there were no European hubs increased by an impressive Japanese imports from Algeria or Egypt. 57% to 188 bcm and physical volumes by Many Japanese companies have been an estimated 63% to 66 bcm – around using the downward quantity tolerance 10% of OECD Europe’s gas demand. So (usually 10%) or even tried to negotiate clearly progress is being made in the down their contractual obligations for this creation of liquid trading hubs to support year. This is likely to put pressure on LNG the development of a more competitive producers and therefore weigh down on European gas market. LNG spot prices which may re-align with the Atlantic ones – taking the transport Remarkable, besides the growth of the differential into account. established trading hubs such as the National Balancing Point (NBP), Title Transfer Facility (TTF) and Zeebrugge, Trading developments is the rapid development of the other in Western Europe Western European hubs, especially the German hubs. Four factors have played a „ Overall traded volumes of gas increased role in this development: markedly on Western European markets in 2008, compared to 2007. „ Simplifi cation of transport systems. In Germany and in France the reduction in „ Greater regulatory activity was critical the number of entry-exit zones (market in opening up cross-border activity. areas) improved the ease in which gas can be moved between markets. The „ Progress was uneven, being especially result is clearly visible in Germany with marked in Germany and Belgium, but volumes rapidly approaching those of weaker in Italy and Austria. the TTF and Zeebrugge hubs (4-5 bcm traded per month). Further reduction „ Improvements in hub trading are in market areas expected in Germany important because they improve price is likely to result in increased hub discovery, ensuring competitively volumes. priced gas, but also improve energy security by allowing gas to move more „ Simplifi cation of balancing rules. In freely to areas where gas supply might Germany, a new model came into effect be disrupted. They also give producers from 1 October 2008 and developments confi dence that they can access and in other countries are progressing. market new production volumes. In the Netherlands, a new balancing model is planned from September 2010. „ Greater fl exibility provided by this The balancing would be more market- growth is essential in responding to based and more closely tied to the TTF, supply interruptions, such as January reducing the risks and costs associated 2009. with imbalances, similar to the model implemented in other European markets. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 29

Figure 6 Developments on European Continental Hubs

+57% 200

bcm

150 +35%

+45% +63% 100

+41% +60% 50

0 2003 2004 2005 2006 2007 2008 2003 2004 2005 2006 2007 2008 Traded volume Physical volume TTF ('03) Zeebrugge ('00) EGT ('06) PEG's ('04) CEGH ('05) PSV ('03) BEB ('04)

Key point: Strong growth continues, giving more flexibility to Europe

Source: Gas Transport Services, Huberator, GRTgaz, TIGF, CEGH, E.ON Gas Transport, Snam, Gasunie Deutschland. Note: Volume weighted average over all continental hubs. Some of the churn ratios were based on an assessment.

„ Trading platform developments. Most such as EUCABO3 and trac-x. In order to of the hub areas are supported by improve access to cross-border capacity an electronic gas exchange platform in the short term, the Dutch TSO GTS where standard products can be traded, (Gas Transport Services) started its or are in the process of establishing EUCABO platform aiming to improve such an exchange (for example in access to cross-border capacity and Italy and Austria). The range of traded enable market participants to take products is often expanded in countries advantage of price arbitrage between with an already established exchange. markets. Providing reference prices is important to improve liquidity. Despite this progress, improving the interaction between market zones remains „ Access to cross-border capacity. There a major challenge that needs to be tackled are some promising developments fully by regulators and governments.

3. EUCABO or European Capacity Booking is a platform developed by the Dutch TSO Gas Transport Services and the German Gasunie Deutschland (GUD) to contract cross border day-ahead capacities between the two transmission systems for both H-gas and L-gas. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 30

In particular, access to cross-border with a record churn factor of 14.4, the NBP capacity is a complex problem that is not remains by far the most liquid trading hub easily nor simply solved, and demands in Europe. close consultation between the involved stakeholders. Some positive steps have The strong decline in domestic pro- been made but a more comprehensive duction and hence increase in import solution has not been found yet. Work on dependency, combined with a relative this subject is one of the main priorities of low storage capacity makes the United the Gas Regional Initiative (GRI) promoted Kingdom dependent on price and demand by the European Regulators’ Group for developments in Continental Europe and Electricity and Gas (ERGEG). As the events on international gas markets. The presence of January 2009 demonstrated again, the of suffi cient import capacity without long- diffi culty of moving gas across borders term contracts does not guarantee the reduces Europe’s gas security quite availability of gas; although for the short markedly. to medium term, international markets appear well supplied, the United Kingdom United Kingdom market will remain relatively volatile.

In 2008 for the fi rst time in the history of Netherlands the NBP the physical volumes remained stable – at 66.6 bcm. However traded Volumes have increased rapidly on the TTF volumes increased by 6% to 961 bcm; over the past two years: traded volumes

Table 1 Traded and physical volumes at European hubs

NBP Zeebrugge TTF PSV PEG’s BEB CEGH EGT bcm per year (‘96) (‘00) (‘03) (‘03) (‘04) (‘04) (‘05) (‘06) Traded volume 2003 611.0 38.6 2.3 0.1 2004 551.9 41.1 6.2 1.1 0.3 0.0 2005 500.1 41.7 11.6 2.6 4.0 0.4 0.8 2006 615.2 45.1 19.1 7.1 7.0 1.2 8.9 0.2 2007 902.6 40.2 27.3 11.5 11.1 4.8 17.7 6.6 2008 960.8 45.4 60.2 15.6 16.5 9.7 14.9 25.3 Physical volume 2003 52.5 10.2 1.3 n/a 2004 53.2 10.6 2.3 n/a n/a n/a 2005 53.7 8.4 3.8 n/a n/a n/a n/a 2006 60.6 8.6 5.9 n/a n/a n/a n/a 0.1 2007 66.8 7.9 7.4 6.8 n/a n/a 6.9 4.1 2008 66.6 9.1 18.7 7.7 n/a n/a 5.2 14.4

Source: Gas Transport Services, Huberator, GRTgaz, TIGF, CEGH, E.ON Gas Transport, Snam, Gasunie Deutschland. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 31

increased in 2008 by 120% to 60 bcm and operation of the Interconnector between the physical volumes by 152% to 18.7 bcm. the United Kingdom and Belgium. In parallel, the number of active players on the TTF rose from 40 to 60 in 2008. Belgium However, the churn rate in 2008 decreased from 3.7 to 3.2. This downward trend in re- In 2007 the Zeebrugge hub was the only trading started around September 2008 trading hub in Western Europe which and continues to fall in the fi rst months showed a decline in traded and physical of 2009 to even below 3, similar to levels volumes, and some even questioned the seen in 2004. This might be caused by need of the hub so close to the NBP and the tightened credit market resulting in the TTF. However 2008 saw a remarkable lower credit lines and reduced activity of reversal: traded volumes were up by 13% fi nancial players but also to the diffi cult to 45.4 bcm and the physical volumes access to cross-border capacity as most were up by 14% to 9.1 bcm. The increase is contracted under long-term supply was especially large during the fourth contracts. quarter of 2008 and fi rst quarter of 2009 with respective increases by 37% and In its ambition to create a gas roundabout, 45% compared to the same period the (see section on the Netherlands), the year before. The following elements have creation of a liquid open market is contributed to this development: essential. Efforts for improvement are therefore ongoing. Around mid-2009, „ The introduction by Huberator of the quality conversion is expected to be made full ZEE Platform Service in February available as a system service, creating 2008 which offers unlimited transfer of a single market for natural gas in the capacity between the four entry points Netherlands by eliminating the existence of the Zeebrugge area, a service which of a L-gas and H-gas system4 . A positive was limited before. The Full ZEE Platform impact on liquidity is expected since Service removed this barrier between market players will no longer have to worry the four entry points. Zeebrugge LNG about the availability of quality conversion. terminal’s capacity doubled in April Furthermore the discussions between the 2008. Since July 2008, shippers have BBL Company and Ofgem on the offering the possibility of re-loading LNG at of interruptible reverse fl ow services are Zeebrugge; this option has already ongoing. After a fi rst rejection by Ofgem been used at least six times. of the proposed tariff methodology, the BBL Company announced that it expects a „ Fluxys started to offer interruptible decision to be taken before summer 2009. transit services and thereby increased The possibility of interruptible reverse the available transit capacity. fl ow could improve liquidity on the TTF by enabling traders to optimise between „ New operating rules on the Inter- the NBP and TTF prices, similar to the connector came into practice reducing

4. L = low calorifi c, H = high calorifi c 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 32

the number of fl ow transitions between On the whole, traded volumes in 2008 Belgium and the United Kingdom. rose by an impressive 203% to 35 bcm and physical volumes rose by an estimated In order to further improve the liquidity of 201% to 19 bcm, putting the German hubs the Zeebrugge hub, Fluxys, the network close to Zeebrugge and TTF in absolute, if operator, has substantial investment not relative size. plans to increase the East-West and the North-South transport capacities. Other measures are expected to improve However, issues surrounding gas quality liquidity and lower the entry barriers for specifi cations between the continent and new suppliers to small consumers. The the United Kingdom need to be addressed trac-x platform which was established in in the near future. 2005 for secondary trading of transmission capacity has increased trading possibilities. Germany Meanwhile, the EEX announced that it is considering the introduction of an At the beginning of 2007 the German intraday pricing window to establish a gas market was fragmented and still reference price. consisted of 19 market areas, making gas transportation across Germany diffi cult. In The expected further reduction of market order to stimulate hub trading this number areas in Germany is likely to provide a further was reduced to 14 on October 2007 under boost for market liquidity. The H-gas areas pressure from the German regulator. – Wingas Transport, ONTRAS-VNG and GUD Together with the introduction of an – plan to merge in October 2009. The two entry-and-exit system, this simplifi cation other L-gas areas of RWE Transportnetz boosted the physical and traded volumes on Gas and E.ON Gastransport are expected the EGT-VP and the BEB-VP5 ; the two most to merge or join Aequamus, while another liquid trading hubs in Germany. Further transmission operator – either Gaz de mergers of market areas were expected France Deutschland or Gasversorgung to take place in October 2008 but most Süddeutschland/ENI Deutschland – could were postponed. Only E.ON Gas Transport join NetConnect Germany. If all these and Bayerngas merged their H-gas zones mergers happen, this would reduce the forming a new company, NetConnect number of market areas in Germany to four Germany. Although the German regulator H-gas and one L-gas areas. had hoped to see greater simplifi cation of the transport system, this reduction to 12 France zones combined to a new regulated daily balancing model (Gabigas) signifi cantly The traded volumes on the France Points boosted trading in October 2008. Finally, d’Echange de Gaz (PEGs) continued to the three L-gas market areas of GUD, increase by 48% to 16.5 bcm. Since EGMT and EWE Netz merged in April 2009 October 2008, the volumes have increased creating a new company called Aequamus. at a more rapid pace than in previous

5. E.ON Gas Transport Virtual Point and BEB Virtual Point. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 33

Table 2 Evolution of the number of gas market areas October October 2006 April 2007 October 2007 October 2008 April 2009 2009** 19 zones 18 zones 14 zones 12 zones 10 zones 7 zones ONTRAS ONTRAS ONTRAS ONTRAS ONTRAS BEB BEB BEB GUD* GUD* Wingas I Wingas I Wingas I GASPOOL Wingas II Wingas II Wingas II Wingas Wingas Wingas III Wingas III Wingas III EGT Nord EGT Nord

EGT Mitte EGT Mitte EGT NetConnect NetConnect NetConnect H-Gas EGT Süd EGT Süd Germany Germany Germany Bayernnets Bayernnets Bayernnets GdF DT GdF DT GdF DT GdF DT GdF DT GdF DT GVS-ENI GVS-ENI GVS-ENI GVS-ENI GVS-ENI GVS-ENI RWE Nord RWE RWE RWE RWE RWE RWE Sud Gas-Union Gas-Union Gas-Union BEB BEB BEB GUD* Erdgas Munster Erdgas Munster Erdgas Munster Erdgas Munster Aequamus Aequamus L-Gas EWE EWE EWE EWE RWE West RWE West RWE West RWE West RWE West L-Gas 2 EGT EGT EGT EGT EGT

Source: IEA analysis, based on public sources. Notes: * Gasunie bought BEB’s network end 2007. ** In Italic, expected mergers by October 2009. years. Almost the whole of this growth futures exchange, which contributed to is due to increasing volumes on PEG Nord greater trading on the exchange but also and to a lesser extent on PEG Est. The other increased the liquidity on the OTC markets trading hubs show a relatively stable fl at by providing more price transparency. development pattern. On 1 January 2009 the three Northern Several positive developments support market areas (North, West and East) the growth of trading. The number of of GRTgaz merged into one Northern active shippers on the French network is market area. This has increased entry and increasing steadily. On 1 December 2008, exit possibilities, especially to the South, Powernext started an electronic spot and and also resulting in greater arbitrage 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 34

opportunities with neighbouring countries. agreement based on the Austrian hub. However the Southern market areas in These discussions fi nally led to an France remain relatively isolated and agreement being signed in February 2009 dominated by the incumbents Total and with an expected implementation in GDF SUEZ who own most of the capacity about six months. This should improve in the Fos LNG terminal. liquidity at the hub and simplify operations. In addition, in cooperation In the short term several elements are with the Wiener Börse, the CEGH aims expected to contribute to an improvement to offer an electronic gas exchange for in market liquidity such as the start of Fos spot products from September 2009 and Cavaou LNG terminal in 2009 providing other futures products at some later more entry capacity in the south to other stage. players, additional capacity between market areas and change of allocation rules, Italy and additional gas-fi red capacity coming on line: Poweo’s Pont sur Chambre starting this In Italy traded volumes rose by 36% in summer and 5.4 GW planned by 2013. 2008 to 15.6 bcm and physical volumes also rose by 14% to 7.7 bcm. Measures taken In the longer term, the interconnection by the Italian regulator AEEG such as the between the TIGF zone and the Spanish compulsory gas releases by ENI and the market could further boost trading with a selling obligation by Italian gas producers link to the Iberian market. on the Punto di Scambio Virtuale (PSV), are likely to have contributed to PSV volume Austria increases. The AEEG determined that from 1 October 2008 market participants who Unlike most other Western European gas conclude new non-EU entry contracts are hubs, the traded volumes on the Central obliged to auction a certain volume (at European Gas Hub (CEGH) decreased in least 15% or 30% depending on the total 2008 by 16% to 14.9 bcm and the physical contracted volume) as month and season volumes by 25% to 5.2 bcm despite the products on the PSV. However the fi rst sixth gas release by EconGas. However the auction was quite unsuccessful and almost churn rate increased slightly from 2.6 to 3. none of the auctioned gas lots were sold. Since the CEGH depends almost entirely on The reason was that the decision taken Russian gas volumes the hub was heavily well before the auction to base minimum affected by the January dispute between prices on oil-linked import prices which Ukraine and Russia, and traded and physical were much higher than market prices volumes were down more than 40% when the auction took place resulted in compared to the previous month. bids under the minimum prices. Despite the AEEG decision to determine prices in For nearly two years, discussions have a time frame closer to the auction, this been ongoing between the hub and the did not prove successful during the last fi ve bordering transmission operators on summer auction. the signing of an operational balancing 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 35

The major stumbling block for the arrangements (notably in Eastern development of the PSV remains the Europe) were much more heavily diffi culty in obtaining entry capacity affected. since most is booked under long-term agreements. The major capacity expansions that are planned to come in operation The lead-up to the 2008/2009 from 2009 onwards could increase the dispute liquidity on the PSV by providing market participants easier excess to the market. Russian gas imports account for about one Also the proposed gas exchange, intended quarter of Europe’s gas needs. About 80% to be operated by GME (current operator comes via pipeline transiting Ukraine; of the electricity exchange), could boost most of the balance coming via Belarus the liquidity on the PSV, but no start-up into Poland. Finland and Turkey receive gas date has been announced. directly from Russia. Ukraine imports gas from Russia and Turkmenistan via Russia, accounting for three quarters of its gas The 2009 Russia – Ukraine gas needs. dispute The gas crisis between Ukraine and Russia „ Interruption of Russian gas fl ows has a long history, which dates back to transiting Ukraine in January 2009 at the break-up of the former Soviet Union a time of very high demand triggered in 1991. At that time, Ukraine stopped Europe’s biggest gas crisis, indeed the buying gas directly from Gazprom, and worst gas crisis in IEA history. instead purchased it from Ukrgazprom, a jointly-owned intermediary. Although „ Europe responded with a mixture of various interruptions, resulting from non- storage draws, demand side measures, payment, occurred almost immediately, plus extra supply was obtained from a more long lasting agreement was other pipeline routes from Russia, reached after Leonid Kuchma came to other producers and LNG. power in 19946. However, as described in more depth in the Natural Gas Market „ Most responses were at a national Review 2006, after the Orange revolution level. Except for fl ows from the United a dispute between the pro-western Kingdom, cross-border fl ows within Yushchenko government and Russia Europe were very small and slow to emerged over the price for gas. In 2008, a arrive. recurring feature of recent years, Ukraine’s inability or unwillingness to pay for its gas „ Hence countries poorly equipped on time, resulted in progressive debt and with storage and other emergency penalties accumulation. In February 2008,

6. Gazprom as a Predictable Partner: Another Reading of the Russian-Ukrainian and Russian-Belarusian Energy Crises, Jérôme Guillet, March 2007, Russia/NIS Center, IFRI. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 36

the Ukrainian debt supposedly amounted Negotiations were blocked on this last to over USD 1.5 billion for 2007 supplies. point, because the transit was already After numerous contradictory statements settled in a separate contract which from both parties, Gazprom briefl y halved Gazprom claimed was valid until 2010. supplies in March 2008, and supplies only Another major stumbling block was the returned to normal levels when Naftogaz size of the outstanding Ukrainian debt, agreed to repay the debt. 2008 prices rose and the additional fi nes for late payments to USD 180 per mcm in Ukraine. While a that were demanded by Russia. considerable increase on 2005 prices (USD 50 per mcm), this was still only about half The 2008-09 dispute of Western European prices. Starting on 1 January 2009, some 110 In early October 2008, Prime Ministers Mcm per day of Ukrainian supply was Tymoshenko and Vladimir Putin signed a interrupted, along with small volumes memorandum that stipulated that Ukraine to countries further west. On 5 January, would pay a market price within three supplies were further reduced, and all years after gradual rises, and that supply transit through the Ukrainian network intermediaries like RosUkrEnergo would was halted on 7 January and from that day be removed. Another condition was that some 300-350 Mcm per day of transit gas Ukraine would pay all outstanding debts was disrupted. This came at a time of very and penalties before the end of the year. high peak gas demand in Western and This seemed to provide some hope of a Central Europe, with the coldest weather negotiated settlement for late 2008. in two decades, but this was somewhat offset by sharply weakening industrial and In the last months of 2008, talks between commercial energy and power demand. Naftogaz and Gazprom were ongoing, When fl ows were restored on 20 January, but fi nal agreement appeared elusive, some 5 bcm of transit gas supplies had not foundering on both price escalation been delivered over a two-week period, and debt issues. Rapidly deteriorating plus around 2 bcm of Ukrainian supplies. economic circumstances in Ukraine (and indeed in Russia), and the prospect of a rapid By comparison, the gas supply disruptions fall in Gazprom’s cash fl ow and revenues in the United States in 2005 due to hardened the negotiating position of both hurricanes led to peak supply disruptions sides. However, both parties emphasised of 250-300 Mcm per day (in the week that European customers would receive following Katrina), totalling about 10 bcm undisrupted deliveries. over two months (although production did not return to normal until 2006). Both parties failed to reach agreement Furthermore, disruptions in the United before the New Year. Gazprom wanted States did not occur at a time of peak to raise the price from USD 180 per mcm demand. Gazprom’s lost gas-sale revenues to USD 250 per mcm. Ukraine said it was amounted to roughly USD 2 billion as of 20 prepared to pay a price of USD 201 per January, although some (indeed most) of mcm and wanted to raise the transit fees. this may be recouped at a later date. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 37

Figure 7 Russian volumes lost during the January 2009 disruption

1 200

Mcm 1 000

800

600

400

200

0

Italy France Greece Poland Slovakia Turkey Austria* Bulgaria Hungary Romania Slovenia Czech Rep. Germany Key point: Volumes missing amounted to 5 bcm

Source: IEA. Note: Austria estimated.

How Europe dealt with the dispute Moldova and Serbia). However, most other countries were able to substitute The cut-off of Russian gas supplies affected the Russian gas lost (at least in the short countries differently, although fortunately term) through a variety of mechanisms, for most countries, Western European including increased supply from other storage was effectively full as of the countries, stock drawdown, voluntary beginning of December 2008. Surprisingly and involuntary demand reductions in on an aggregated level, Europe was able to industry and consumer sectors, and fuel cope with the supply disruption relatively switching in the power sector. Diversion well. However the biggest problem of gas from relatively well-off areas to appeared to be moving gas to the places poorly supplied regions was slow and where it was most needed. The countries limited in the fi rst half of January, (e.g. that were affected most had no access a few Mcm per day) but appears to have to LNG, did not have suffi cient storage grown in scope and volume as the dispute (or had storage in the wrong places) continued. These arrangements were and lacked effi cient interconnections generally commercial ones, with some with neighbouring countries (among governments intervening to initiate these these are Bulgaria, Romania, Slovakia, commercial arrangements. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 38

Especially in Western Europe the fl exible in that country. IEA data shows exports and rapid functioning of a traded market in January up 0.73 bcm with LNG imports proved its importance. Within a very up by 0.25 bcm. Although the access to short period, price signals on the different suffi cient border capacity was challenging hubs directed gas fl ows from west to and could have posed diffi culties, gas east were the gas was most needed. reached surrounding Western European The Interconnector between the United markets, including Belgium, Germany, and Kingdom and Belgium, and fl ows in the BBL France, and may well have reached Italy pipeline between the United Kingdom and and Austria, at least indirectly. However, the Netherlands were reduced/reversed, beyond the German borders, especially in contrary to what was expected in a normal the South Eastern part of Europe, these winter. The net impact of these fl ows out of market mechanisms were generally the United Kingdom may have been as high unavailable because of the lack of proper as 0.8 bcm, mostly coming out of storage market structures. Here it took weeks, and

Map 1 European response to the gas dispute between Russia and Ukraine

Timeline 7 Jan. (immediate) 10 Jan. 16 Jan. 18 Jan. Existing import facility Yamal increase

BBL NLD - GBR reduced

Interconnector GBR - BEL reversed

Reverse flow Czech to Slovakia

Hungary increase to Increase Germany - Croatia Serbia and Bosnia

Blue Stream increase

Increasing Croatian production share off-take

Reverse flow from Additional spot LNG Greece to Bulgaria to Greece and Turkey

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. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 39

Table 3 Summary of responses by European countries Italy Czech Turkey France Greece Poland Austria Slovakia Bulgaria Slovenia Republic Hungary Germany

Alternative Russian supplies 3 8 3 8 3 8883 883 Supplies (increase existing) 3 8 3333888833 Supplies (reverse flow) 8 3 88888883 88 LNG 8883 8 3 888883 Domestic production 8888883 88888 Storage 333338 33338 3

Source: IEA. sometimes even government intervention, Another important mechanism in the to direct gas fl ows to the areas of greatest response was storage drawdown, although need. estimating the extent of this is diffi cult, since stocks would have been under heavy The confl ict highlighted again that the fi rst pressure because of the very cold weather. and most important defence against supply For example, in France, demand was up disruptions is a well functioning market 15% in January because of the very cold that is able to respond quickly, preferably weather. Germany had a similar increase. within hours rather than days, to changing January in OECD Europe was overall market circumstances, and is based on 100 HDDs colder than normal. Nonetheless, demand and supply fundamentals. Beyond some exceptionally large stock draws can that, there is an urgent need to diversify be seen in Italy, Germany and France, in and expand gas supply sources, and each case more than 1 bcm higher than the improve both the physical interconnection previous January. In Austria, 1 724 Mcm of countries in Europe (including the were withdrawn during January compared ability to move gas in the reverse direction to around 600 Mcm the previous years. In to normal trade fl ows) and the market Italy, storage draw appears to have been mechanisms that could underpin a speedy the major response, accounting for around movement of gas supplies as demand and 1.2 bcm of extra supply. Germany was able supply change. This need is particularly to benefi t from increased fl ows through marked in Eastern European countries. the Yamal pipeline coming from Russia None of this is new; both the European through Belarus and Poland. In the case Commission and the IEA have made these of Greece and Turkey, spot LNG supplies observations repeatedly in recent years. made up about 400 Mcm of extra supply, Yet we have learnt from this experience, and Turkey was able to source some especially on possible fl exibilities between 100 Mcm of extra supply from Russia via neighbouring countries. Blue Stream under the Black Sea. In most major economies of Western Europe, 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 40

all demand was able to be met without 2009), moving to 100% in 2010, and which interruptions to users, either industrial is to be adjusted on a quarterly basis. The or domestic. However, in Central and parties agreed on deliveries to Ukraine for Eastern Europe this was not the case, 2009 of some 40 bcm, moving to 52 bcm with industrial supplies interrupted in from 2010 onwards (within the contract several countries and households as well. period). Interruption in some cases was planned, and part of contractual arrangements; in In a new transit agreement signed on other cases it was unplanned. Responses the same day, transit fees appear to have of affected countries are summarised in remained at 2008 levels in 2009. Thereafter, Table 3, with cross border fl ows shown in transit fees are set to rise upon expiration Map 1. With the exception of UK-Belgium, of the existing agreement (2010), in these cross-border fl ows were quite small. line with infl ation and gas supply prices The need for Eastern European countries (USD 2.60 per mcm per 100 km), still to diversify gas supply sources is seen in well below EU levels (USD 4-5 per mcm recent moves (April-May 2009) for Poland per 100 km). Intermediaries (namely to import Qatari LNG and Bulgaria to buy RosUkrEnergo) will be removed. Indeed, LNG, possibly importing via Greece. moving to 100% of the EU price, with a higher transit price, will make them Replacing the missing essentially irrelevant. Figure 8 Russian volumes Based on the 10-year supply agreement, Others' storage Gazprom is allowed to halt gas deliveries Netherlands Italy to Ukraine if a new situation of non- Norway storage payment arises, thus representing a risk for new gas supply cut-offs. On 19 February, LNG Naftogaz released a statement in which Other Russian Germany it indicated that it might have problems routes storage making future payment to Gazprom for the gas, declaring that “this situation in United Kingdom Austria storage terms of paying Gazprom could worsen storage (IUK) because of the catastrophic rise in debts of regional utility companies”. According Key point: Storage the key response to the Naftogaz statement, the total

Source: IEA estimates. amount of outstanding debt stood at USD 570 million. A potential new dispute shall, if not solved within 30 days, be The Russia-Ukraine settlement settled in accordance with the Charter of the Arbitration Institute of the Chamber The main components of the deal were of Commerce of Stockholm, in Sweden. a 10-year agreement by Ukraine to pay Notwithstanding the ongoing diffi culties 80% of the netback EU price (around of debt collection in Ukraine, and the USD 360 per mcm in the fi rst quarter of sharply deteriorating economic situation, 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 41

Ukraine’s April gas payment was made in Gas Exporting Countries full at the beginning of May. However the Forum fi nancial situation of Naftogaz remains an unstable element to the new deal. „ After seven years’ existence as an informal grouping, a ministerial The parties have also agreed to sign a long- meeting of the Gas Exporting Countries term gas supply contract7 which will give Forum (GECF) decided in December 2008 Gazprom the right to deliver gas directly to transform the Forum into a fully- to Ukrainian industries, which alone fl edged international organisation. account for 25% of annual gas imports and represent the most profi table share of „ Eleven countries, including the world’s the market. largest gas reserve holders Russia, Qatar and Iran, signed an agreement Outstanding issues in Moscow creating the GECF and confi rming its statute. After the resumption of the Russian gas deliveries to Europe and the signing „ It is too early to predict the likely of the new 10-Year Transit and Supply direction of the GECF or its infl uence Contracts between Gazprom and over gas markets. There are big Naftogaz (resulting in the elimination of structural differences between oil the trader intermediary RosUkrEnergo and gas markets, and, although from the transit through Ukraine), one tagged as a potential ‘Gas OPEC’, of the key outstanding issues remains the organisation as it stands is not RosUkrEnergo’s unfulfi lled contractual recognisable as a cartel. obligations from cross-border trade via Ukraine. This intermediary concluded The signatory states8 of the GECF contracts for deliveries of a total amount together hold around two-thirds of global of 7 bcm per year with companies in gas reserves. They accounted for 36% of Poland, Hungary and Romania. The fate global gas production in 2007 but 47% of RosUkrEnergo will be decided in of exports. According to projections accordance with Swiss law, though it from the IEA World Energy Outlook 2008 seems to be already clear that, having lost Reference Scenario, their share of global its sources of gas in Russia, Central Asia gas production will rise to 42% by 2030. and Kazakhstan, RosUkrEnergo will not be able to honour its contractual obligations. The list of signatories to the Moscow Other issues include the relatively low agreement suggests a shift in the GECF level of transit tariffs after 2010. centre of gravity towards Europe and the Atlantic LNG market. Nine of the eleven signatories – all except Venezuela and Bolivia – are actual or realistic future

7. From 1 January 2009 to 31 December 2019 8. Algeria, Bolivia, Egypt, Equatorial Guinea, Iran, Libya, Nigeria, Qatar, Russia, Trinidad & Tobago, Venezuela. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 42

Map 2 Gas Exporting Countries Forum’s participants

Europe pipeline

Atlantic LNG Pacific LNG

Observers Signatory states Participants at previous GECF meetings

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. suppliers to the European gas market. environmentally conscious development, None of the three Pacifi c LNG suppliers use and conservation of natural gas that had been represented at previous resources for the benefi t of their meetings (Brunei, Indonesia and Malaysia) peoples.” was present in Moscow. Caspian countries apart from Russia and Iran were also under- GECF member countries have agreed represented; Kazakhstan, a marginal net to promote these objectives through exporter, was the only presence from this “exchange of experience, views, region and attended as an observer. information, and coordination” in areas such as exploration, the supply-demand Despite being tagged as a potential ‘Gas balance, gas technologies, the structure OPEC’ the role of the GECF is still loosely and development of gas markets, defi ned, refl ecting a variety of views and transportation. As it stands, the among participating states as to its organisation is not recognisable as an purpose. The Forum’s founding documents OPEC-style cartel: the words “price” steer clear of contentious issues, and and “pricing” are not mentioned in the the stated objectives of the Forum are organisation’s statute. expressed in very general terms: to “support the sovereign rights of member The deterioration in gas market conditions countries over their natural gas resources since mid-2008 undoubtedly played its and their abilities to independently plan part in helping gas exporters fi nd common and manage the sustainable, effi cient and cause. Shared concerns about price levels 2009 OECD/IEA, © Natural Gas Market Review 2009 • Recent events 43

and the possibility of “oversupply” may short-term market manipulation, the now be exacerbated by the large number GECF could look to coordinate medium- of new LNG projects coming on stream in term investment plans among its member 2009-12. However, it will be diffi cult for countries. The latter objective would appear GECF members to act to improve their to coincide with the view of Gazprom market position in the short term. With CEO Alexei Miller, who characterised the the current structure of gas markets, primary task of the Forum as “to jointly producers’ market power is limited de analyze and form the global gas balance, facto by the predominance of long-term as well as consider the issues with regard gas supply contracts. Although wary of to production volumes so as to avoid concluding new export contracts at times oversupply of gas to the market.” of low prices, there are few benefi ts to holding back incremental supplies from For the moment, though, it is too early to the market as the high costs of LNG make predictions about the likely direction infrastructure and storage create strong of the GECF: on the one hand, it could incentives to generate cash fl ow as soon become a vehicle for debate, information- as possible. sharing and dialogue with transit and importing countries; on the other, it could A more likely focus for GECF deliberations look at some point to exert greater control is the changing structure and supply of over the gas market through actions that gas markets over a ten- or fi fteen-year could constrain supplies. The “gas troika” horizon, i.e. towards 2020 and beyond. of Russia, Iran and Qatar is likely to have Algerian Oil Minister Chakib Khelil a strong infl uence over the path that the emphasised this point when commenting Forum will follow only from a political point on the differences between the Forum and of view as Iran is not going to become a OPEC: “OPEC looks at today, what happens signifi cant gas exporter for many years; on the market and makes the decision. this group has agreed to meet regularly The Forum ... it’s more forward looking. It following an October 2008 meeting in cannot control the volumes and price for Tehran, and, along with Algeria, forms the the next ten years because it’s locked into political core of the GECF. long-term contracts and also the price of gas is locked into oil.” In defi ning a direction for the Forum, producers will have to be wary of the fact Over this period, gas production is likely that gas – unlike oil – can more easily be to become more concentrated in a smaller substituted by other fuels, making the scope number of reserve-holding countries for a response by consumers to cartel-like and national oil and gas companies. The behaviour much larger in the gas sector structure of gas markets is also set to than in the case of oil. In this sense, there are change, becoming more interlinked risks associated with pursuit of a vision of by trade in LNG and less tied to oil the GECF as a potential market manipulator; markets. While the imperative to keep instead of increased revenues and infl uence, gas competitive with other fuels would producers may eventually end up simply still provide a formidable obstacle to any with a constrained market for their exports. 2009 OECD/IEA, © © OECD/IEA, 2009 Natural Gas Market Review 2009 • Investments 45

INVESTMENTS

Introduction generation sector and the development of gas grids. Some exporting countries „ Investments are needed in all parts such as Oman will turn into net importers of the gas value chain to meet future within a few years. demand needs. In order to meet future demand needs „ Given the uncertainties on demand and across the world, each part of the gas the current economic conditions, there value chain must be developed in a timely is a risk that some investments might manner: upstream reserves that would be postponed. This could potentially feed both domestic and export markets; lead to a tight market as gas demand the liquefaction plants and regasifi cation has the potential to rebound quickly terminals if the reserves are developed as while investments on the supply side LNG plays or the long-distance pipelines are constrained by long lead times. and fi nally the storage infrastructure to make sure that not only annual but „ Capital intensive projects expected also seasonal and short-term demand to make FIDs in 2009-10 will be the variations are met. However, the recent most affected by the current market fi nancial crisis seems to have aggravated conditions. and reinforced pre-existing uncertainties which were already hampering gas investments:

World gas demand is expected to increase Uncertainties about future demand and by over half by 2030 according to the import requirements. Producing countries Reference Scenario of the World Energy as well as sponsors of major new supply Outlook 2008. Despite the maturity of projects are increasingly worried about their markets, OECD countries are still the future. This is not only about the expected to see demand increasing. As length of the current crisis – or how their domestic production is expected to long gas demand might stay depressed decline simultaneously, they will become – but also about future demand paths. increasingly import dependent and are Will demand recover at a slower growth already looking at building new pipeline rate if the recent high price environment and LNG terminal infrastructure for and concerns about climate change lead their supply needs. But demand will also to more energy effi ciency and non-CO2 be growing in non-OECD countries, in emitting technologies? Will demand particular in countries such as China and recover with the same business-as-usual India – which are expected to show the path and will gas remain the fuel of choice? highest gas demand growth rates – but Or will the slowdown of investments in also in producing countries in the Middle the power generation sector translate East or North Africa. These latter countries into more gas-fi red plants having to be tend to look increasingly at their own built when electricity demand recovers markets, which are growing rapidly due translating into demand rebounding more to an increased use of gas in the power quickly than expected? 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 46

Figure 9 Possible future gas demand trends

bcm

2000 2009 2020

Key point: Demand: a key uncertainty for future investments

Source: IEA.

Regulatory uncertainties. Investors seek a will reassess priorities. The companies with stable regulatory framework whether they the strongest balance sheets may prefer are investing into regasifi cation, pipeline or to absorb existing and smaller companies storage infrastructure. Lengthy planning rather than investing in new projects. process coupled with heterogeneous regulatory systems for pipelines crossing The danger about investments not being several countries are discouraging. made on time is the asymmetry between construction times on the demand and on Financial uncertainties. Companies and the the supply side, even not taking into account infrastructure projects they support will be the permitting process and the search for affected by the fi nancial crisis as they look partners and for funds which increases with for more certainty before making the fi nal the complexity and the size of the project. investment decisions. Large-scale, long Only a couple of years are needed to build lead time projects are especially vulnerable new gas-fi red power plants or new intra- in the current economic climate. In some regional gas grid connections. But it would cases, the completion of a project might require as long as four to fi ve years for new require government backing. greenfi eld gas developments (depending on location); four years are now necessary A question of choice. Companies involved to build a liquefaction terminal. Most in many projects either on the same part transnational major pipelines can be built of the gas value chain or in various parts within three years, but it would take more 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 47

time depending on the onshore/offshore Most producing countries face major requirements and the diffi culty of the terrain. challenges concerning the development Major new LNG plants can take years to come of future resources. Even prior to the to fruition – Pluto trying to prove otherwise. current fi nancial crisis, gas development Due to the lag times in the development of was slowing: high costs affected remote new gas supplies, demand could return before gas deposit development, producer adequate capacity has been added, leading governments’ policies moved to potentially to a tighter market. “reserve” gas for local use rather than export, technical problems plus “Not in My Backyard” (NIMBY) and regulatory Supply investments in major issues all contributed to slowed gas producing regions development. While surprisingly few project delays or cancellations have been „ The slow pace of upstream gas formally announced, the current fi nancial development has been identifi ed in environment is likely to have consequences previous Natural Gas Market Reviews on how quickly new fi nal investments as a concern, prior to the current decisions (FIDs) are made and what fi nancial crisis. priorities are chosen. Most producers are likely to see demand falling in their core „ Current global economic developments export markets this year, have markedly will sharply lower producer cash weaker cash fl ows and face much tougher fl ows, while making demand growth fi nancing conditions. Demand uncertainty more uncertain, slowing upstream has become a major concern – when will development further. gas demand recover and at what pace is one side of the problem; political messages „ For Russia, the world’s largest gas from markets concerning diversifi cation reserve holder, the new production area of import sources, the scale of their of Yamal will be crucial to maintaining import requirements is another, more or expanding production and exports; subtle but of concern to producers. With other major new fi elds, like Shtokman, the globalisation of gas markets, each now look unlikely before 2015. producer’s decision will be infl uenced by the others’. „ Qatar is dramatically expanding its gas exports, but its self-imposed moratorium Russia, Qatar and Iran are the three most looks set to limit new growth in output important reserve holders in the world. until 2015, or even later. Together they represent more than half of total proven gas reserves, but so far they „ Iran is a very large gas producer and account for only 27% of world production user, but production increments look and consume 19%. These countries are set to meet growing domestic demand. very different: Signifi cant exports by pipeline or LNG before 2015 look unlikely. „ Russia and Iran are respectively the second and third largest gas consumers 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 48

Figure 10 Gas production and consumption in the “Big 3”

700

bcm 600

500 Incremental production 2000-07 Russia: 68 bcm 400 Qatar: 32 bcm Iran: 48 bcm 300

200

100

0 1990 2000 2007 1990 2000 2007 1990 2000 2007 Russia Qatar Iran Production Demand

Key point: Promising potential in Qatar and Iran based on proven reserves

Source: Natural Gas Information 2008, IEA.

Table 4 Production and capacity additions during 2000-15 by Qatar, Iran and Russia

Qatar Iran Russia

Production 2000-07 32 bcm 48 bcm (South Pars 1-5) 68 bcm (NPT) 146 bcm (South Pars 1-14) 781-845 bcm (incremental Production 175 bcm 80 bcm (South Pars 15-24) production from Bovanenkovo, target 2015 Kharasavey) 21 bcm (Bidboland-II)

Capacity (post 2008: under construction and planned) 2000-07 19 bcm (LNG) 20 bcm (EuRoPol) 2008-11 64 bcm (mega trains) 40 bcm (Sakhalin 2, Nord Stream) 80 bcm (LNG) 85 bcm (Shtokman, Nord 2012-15 120 bcm (pipes) Stream, South Stream)

Source: IEA. Note: Capacity additions post-2012 are planned only. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 49

in the world. Iran gas demand almost based on three super-giant gas fi elds in doubled over the 2000-07 period. Qatar Western Siberia: Urengoy, Medvezhye, demand amounts to only 20 bcm. and Yamburg. But their production has been declining rapidly at around 20 bcm „ Russia and Qatar are net exporters, per year. In order to meet both domestic while Iranian production struggles to demand and export commitments, meet demand. Gazprom has been relying on three factors: increasing imports of Central „ Qatar is predominantly an LNG exporter, Asian gas; incremental production from while both Russia and Iran are currently the independents reaching over 100 bcm predominantly pipeline exporters which in 2008; and the development of new fi elds plan to get increasingly involved in the – in particular in the Nadym Pur Taz (NPT) LNG business. region. This last item enabled Gazprom to keep a relatively stable production over the One aspect of the signifi cant gas past fi ve years, despite the steady decline production increase in Iran and Qatar is of the three super-giants. Several fi elds the target for condensate, GTL and LPG such as Kharvutinskaya, Yety-Purovskoye, production. This could have a potentially Petsovoyea or South Russkoye have been big impact on oil markets. In particular, commissioned over the 2003-08 period the huge LPG expansion should have while production of existing developments a significant effect on the global such as Zapolyarnoye (which started LPG markets, especially in Asia, with producing in 2001) has been further secondary impact on the gas markets as increased; these fi elds would represent a LPG is competing with gas in Asia. peak production of over 150 bcm.

Russia But this strategy is reaching its limits. In particular, Central Asian imports have Russia has the largest proven gas reserves become more expensive – Turkmen gas in the world – around 45 tcm. However prices have increased from USD 50 to 300 there are increasing worries about per mcm between 2005 and early 2009, whether Russia will be able to meet both refl ecting Turkmen demands for pricing rising domestic demand as well as export based on Russian netbacks from European obligations. On the Russian side, producers sales. Independents remain effectively worry about the security of demand: how excluded from the export market by will the market recover from the current Gazprom’s monopoly on export sales. crisis and what will be the impact of Facing these issues, Gazprom is developing climate change and other major policy new gas fi elds which will be more developments. technically challenging, more remote and more expensive to develop than the fi rst Gazprom is the largest gas utility in the generation of Russian gas. However, over world producing 551 bcm in 2008 or about the past fi ve years Gazprom has also been 85% of total Russian gas output. Until focusing on investments in the European recently, it had developed its business market – either in new pipelines avoiding 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 50

Figure 11 Gazprom’s gas production

700

bcm 600

500 Others Zapolyarnoye

400 Yamburg Cenoman 300

200 Urengoy Cenoman 100

Medvezhye 0

1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008

Key point: New fields are critical

Source: Gazprom.

transit risks such as Nord Stream or gas control of various parts of the value chain storage facilities such as Haidach. It has down to domestic and foreign consumers, also been active within Russia acquiring it raises questions in the minds of controlling stakes in companies: the consumers as to whether these activities attempt to acquire coal producer SUEK will not compromise the very signifi cant failed, but Gazprom became active in new investment needed upstream to the power sector and acquired some of ensure adequate and timely natural gas RAO UES assets so that the generation supplies. The focus is therefore on the capacity controlled by Gazprom increased next generation of gas fi elds: in the West, from 12.7 GW in 2007 to 35.4 GW in 20081. on the Yamal peninsula and Shtokman, In April 2009, Gazprom bought ENI’s 20% and in the East at Kovytka, Sakhalin and stake in Gazprom Neft for USD 4.2 billion. Chayandinskoye. Although these activities may make sound corporate sense, as Gazprom positions Unfortunately, the necessity of making itself to benefi t from increasing domestic huge investments coincides with the electricity prices and seeks to gain more fi nancial crisis and an expected major

1. Source: Gazprom Investor day, February 2009. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 51

drop in revenues in 2009 for Gazprom on RUB 920 billion announced in December the back of lower oil and gas prices and 2008 to RUB 827 billion in April 2009 as they lower offtake from European buyers and expect to save money by cutting capex domestic users. Average prices for gas and renegotiating contractor charges. It exports to Europe are likely to decline is not clear what would happen to the from USD 12 per MBtu in 2008 to USD 8 previous investments plans published per MBtu in 2009. Russian production has late 2008 which envisaged an increase been declining since the last quarter of in annual production to 876-981 bcm 2008, with a year-on-year decline reaching in 20302, up from 665 bcm in 2008. 15% during the fi rst quarter of 2009. This Total exports were expected to rise to has been essentially due to plummeting 415-440 bcm and domestic demand to demand both in Russia and in Europe, but 550-613 bcm. Total investments would the fact is that most of the decline has amount to USD 545 and 645 billion over been attributed to Gazprom’s subsidiaries, 2007-30. Although Gazprom has not whose production declined by 18%. There announced any change in the development are many uncertainties on the Russian of the different projects, all the production gas demand outlook in 2009. It declined targets look very ambitious, not only substantially during the last quarter of because the technological challenges are 2008 (by 15.0% in November and 10.3% often higher compared to the previous in December), and the decline continued generation of supergiant gas fi elds, but at 8.4% in January 2009. Nearly half of also because of questions about Gazprom’s Russian power is gas-fi red, and more ability to focus on all projects simultaneously than half of Russian gas demand comes while the company still has a heavy debt. from this sector, so the sharp drop in Although debt levels were reduced during power use is also likely to heavily impact 2008, most debt is in US dollars or euros, gas demand. An additional complicating and the rouble has depreciated heavily factor is that the planned increases of against these currencies. residential and industrial tariffs, which could further reduce demand by improving The possible deceleration refl ected by effi ciency, notably in the power sector, recent announcements does not mean a may be postponed due to the economic cancellation of any of the large upstream downturn. At the same time, the fall in projects, but the output is likely to be export prices may make price reform more lower than what has been announced feasible. Wholesale prices were scheduled until recently. Therefore Gazprom may to increase by 25% over the course of be tempted to reduce investments and 2009, with further increases in 2010, with reassess priorities, especially in the light obvious benefi ts to producers’ cash fl ows. of falling demand and uncertainties about future needs of export markets. Gazprom Gazprom’s board has already revised has already indicated clear priorities down their planned investment from on both production and transport. On

2. Outlook for the natural gas industry, IFP, December 2008. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 52

Map 3 Demand trends in OECD Europe

Producing region Existing gas pipeline UK Prospective region NORWAY Planned/proposed gas pipeline Selected gas field SWEDEN Shtokmanovskoye Existing LNG export plant NETH. Under const. LNG export plant DEN. FINLAND Export to GER. Finland EST. Yamal Peninsula CZ. POL. Kharasavey Bovanenkovo REP.Export to St. Petersburg East Europe LITH.LAT. Komi Vankor Minsk S. Russkoye Siberia SLO. REP. Yamburg Ukhta Zapolyarnoye HUNG. BEL. Northern Lights Yakutsk UKR. Medvezhye ROM. Moscow Urengoy MOL. Kiev Sakhalin Chisinàu RUSSIA Lena- Surgut Export to Tunguska Komsomolsk Odessa Petrovsk Europe Yurubcheno- Volga- West Chayandiskoye Urals Siberia Tokhomo Khabarovsk Tyumen Kovykta Orenburg Krasnoyarsk North Volgograd Omsk Tomsk Caucasus Kemerovo Daqing Novosibirsk Novokuznetsk GEORGIA Irkutsk Harbin TURKEY Tbilisi Aqtaù Astana ARM. CHINA JAPAN AZER.Baku KAZAKHSTAN Ulan-Bator NORTH SYRIA KOREA MONGOLIA Shah-deniz TURKMENISTAN REP. OF IRAQ IGAT Nabit-DagUZBEKISTAN Beijing KOREA (from Iran) Almaty 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. production, priority is being given to The Yamal Peninsula Zapolyarnoye (Valanginian deposits), Bovanenkovo (Yamal), Urengoy, and The Yamal Peninsula is critical to replace Shtokman. On transport, top priority is declining production in Western Siberia. being given to Nord Stream, followed Put simply, no bridging solution can by Pochinki-Gryazovets (linking the two replace these volumes that Gazprom major export systems) and the Yamal expects to reach 310-360 bcm by 2030. pipeline delivery system. Gazprom has a very ambitious plan for the Yamal Peninsula with the development of Another solution would be to work on two fi elds Bovanenkovo and Kharasavey. reducing Russian energy demand: more By 2011, Yamal is expected to produce effi cient gas turbines could easily save 8 bcm per year from the Bovanenkovo fi eld. 20 bcm per year while better insulation Gazprom expects to produce 115 bcm to in the residential and commercial sector be increased to 140 bcm in the long term. could save another 70 bcm per year3. But Kharasavey would start in 2014 bringing the promised price rises, which would help the combined production to 180 bcm – drive these savings, may be especially one-third of Gazprom’s production today. diffi cult to pursue, given the economic and social impacts of the current recession.

3. Source: Gazprom. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 53

The challenges to develop the Yamal attractiveness of the LNG business and Peninsula are above all logistical: the changing diplomatic relationships with construction material needs to be European and the American governments transported there and pipelines have to respectively have been the major drivers be built, notably a 1 100 km gas pipeline behind these changes of directions. between Bovanenkovo and Ukhta to transport the gas back to the unifi ed According to the current plans, the fi eld’s gas supply system (UGSS). Drilling and output will be almost evenly split between other equipment material will be mainly pipeline and LNG and developed in three transported by railroad, and not by sea or phases of 24 bcm each; the LNG share of by river which can be used only for one- the project will reach 40 bcm (30 Mtpa). A third of the year. Gas pipelines have to be fourth phase bringing total production to built in permanent permafrost conditions; 95 bcm is possible. During the fi rst phase, even though this particular environment the fi eld will be developed by the Shtokman has been studied for decades, recent Development Company (Gazprom 51%, warmer conditions have to be taken into Total 25% and StatoilHydro 24%). The gas account. Such challenges are susceptible would be transported to Murmansk, and to causing delays for the project then either by pipeline to Europe through timeline. The most diffi cult section is the the Nord Stream pipeline or by LNG to underwater crossing of Baidarata bay the Atlantic region. No fi nal investment where the danger of icebergs requires decision (FID) has yet been taken. If FID trenched pipelines. In 2008, Gazprom is made soon, Gazprom expects fi rst gas made a signifi cant investment of around in 2014 – a timeframe now considered as USD 4 billion on the Bovanenkovo fi eld very ambitious by most observers (see the and so far has laid 37.7 km of the pipeline LNG section for more details). across the bay. Nevertheless, given these added diffi culties and the sheer scale Developments in the East: Kovykta of the project, the time frame of 2011 and Chayandinskoye production start-up looks ambitious. Developments in the Far East region Shtokman are even more challenging due to the absence of export infrastructure – apart Shtokman is probably one of the most from Sakhalin 2 – and of gas pipe export challenging gas projects to develop due to agreements. Eastern Siberian gas may the diffi cult arctic conditions. Discovered have missed a window of opportunity in in 1988, the fi eld is estimated to contain Asian markets and now faces competition 3.8 tcm of gas. It represents the fi rst major from other domestic production, LNG offshore development for the Russian and Turkmen gas. Contracts with these gas industry. Over the past decade, the markets will be diffi cult to conclude in the Shtokman project has moved from a short term due to pricing and policy issues pipeline project to an LNG project and back in China and competition from other LNG to a project based on a mix of pipelines sources in Japan and South Korea. and LNG. Domestic politics, the increasing 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 54

The Kovykta fi eld is located in the Northern proven gas reserves with 26 tcm as of part of the Irkutsk region in Eastern Siberia end 2007. Its production gains have been close to China and Korea. Reserves are close the fi fth largest in the 21st century after to 2 tcm. Since 1992, it had been developed Russia, Iran, China and Norway. Qatar by RUSIA Petroleum in which TNK-BP had a has very ambitious export plans with majority shareholding. The development of LNG export capacity to increase from the fi eld had two main objectives: supply to 52 bcm early 2009 to 105 bcm by 2011 the small regional market – up to 4 bcm for with the addition of fi ve LNG trains of industries and CHP – and future exports to 10.5 bcm each. These export projects have China and South Korea – up to 20 bcm to been or are being developed through a China by 2014 and 10 bcm to South Korea by partnership between Qatar Petroleum 2011. Although Eastern markets were more and foreign partners (ExxonMobil, Shell logical, a Western route was not entirely or ConocoPhillips). Although all the excluded. Exports to China and Korea liquefaction facilities may start operations failed due to disagreements on pricing by 2011, the maximum capacity is likely to and the sheer size of the development. be reached only in 2013 as Qatar has been But in 2007, after the repeated warnings facing project implementation delays. of license cancellation by Russia’s Ministry Meanwhile domestic demand has almost of Natural Resources, Gazprom and TNK-BP doubled between 2000 and 2007 to reach signed an agreement to sell TNK-BP’s 63% 20 bcm. There is a strong potential growth stake to Gazprom. So far the deal has not in the power generation, desalination and been completed and may now be a lesser industry sectors. Therefore Qatar is likely priority. to maintain a desire to balance exports (pipeline and LNG) and domestic market Gazprom also acquired a development needs, but also export products – GTL, license for the giant Chayandinskoye fi eld LNG or pipeline gas to the UAE as well as (1.2 tcm reserves) in the eastern republic a variety of export markets. Originally, a of Sakha. The development plan calls for a wellhead gas production of 238 bcm4 per gas pipeline to deliver supplies from the year including 175 bcm of dry gas was fi eld eastward, scheduled to come on line planned from projects approved before by 2016. The line would run from Yakutia the moratorium. to Khabarovsk and Vladivostok along the Pacifi c Coast. The main uncertainty for the country’s future production is due to the moratorium Qatar on new export projects imposed in 2005. The objective for Qatar is to study the Qatar is one of the leading performers effect of the existing project production on in terms of new gas development in North Field reservoirs. There are concerns the world. Qatar ranks third in terms of about the pressure and the effect that

4. Including 700 000 – 800 000 b/d of condensate, 14 Mtpa of LPG, and 250 000 b/d of GTL production. Dry gas production is estimated to be 175 bcm per year (including LNG, pipeline exports, and domestic use). 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 55

further development would have on the it is understandable that the Qatari fi eld structure. Originally taken for three authorities have put the sustainability of years, the moratorium was extended to the productive life of the North Field as 2010 later and there is no certainty about a key national priority. As in some other when it would be lifted. The moratorium is producing countries such as Norway, likely to stay in place until all the planned sustaining production for a long time trains currently under construction have in order to create a legacy for future been brought fully onstream which would generations is particularly important. If be in 2013 or a little later according to the study proves satisfactory for the fi eld’s recent declarations of Saad al Kaabi, Qatar life, there could be a debottlenecking of the Petroleum gas development manager. existing facilities, an increase of pipeline Furthermore the study on the North Field capacity or an expansion of GTL facilities. is now expected to be completed only by Alternatives could include exploration at 2012. different depths in the North Field area.

Given the scale of the reserves of the Furthermore Qatar may reassign gas North Field and its strategic importance, production to domestic users – a pattern

Map 4 Iranian and Qatari gas infrastructure Caspian Sea Existing gas pipeline Rasht TURKMENISTAN Neka Planned/under const. Kord Kui gas pipeline Tehran Gas production area Gas field LNG export plant Qom Under const./ planned Arak LNG export plant Planned LNG IRAN import terminal AFGHANISTAN

IRAQ Yazd

SAUDI Kerman Rafsanjan KUWAIT ARABIA Kuwait Mina al Ahmadi PAKISTAN IRAN South Pars OMAN Assluyeh North Field Bandar Tombok Doha South Pars North Field QATAR Al Manamah (9) Ras Laffan Abu Dhabi BAHRAIN (5) U.A.E. QATAR Doha 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: Petroleum Economist, IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 56

that is being seen in other Middle East and industry and domestic consumers in the African countries such as Egypt or Libya. North East. The balance is particularly For example, the Barzan project between tight during peak winter periods. During ExxonMobil and Qatar Petroleum has the winter of 2007-08, Turkmen gas been reassigned to serve domestic users. supplies of up to 23 Mcm per day were cut However this project has been delayed by until April 2008 which had a ripple effect up to one year due to high current costs. on exports to Turkey. The project sponsors announced they would use this delay to source gas from a The development and marketing of gas new structure in Qatar’s North Field. on the world market is central in the government’s 20-year strategic plan. Iran Nevertheless, the continuous delays in the development projects undertaken and the Industry observers tend to think Iran has weight of fi nancial sanctions raise doubts been lagging behind Qatar in developing about whether the country will be able gas reserves from the same geographical to reach that goal. The government has structure (North Field in Qatar and South envisaged a production of 292 bcm per Pars in Iran). However, since 2000, the year in 20105, a huge increase in output incremental production capacity at South from 146 bcm per year6 today. Pars has been larger than that of North Field. South Pars Phases 1-5, totalling Whereas a massive expansion of LNG 45 bcm per year, compares with Qatar’s production (+64 bcm per year from 2009- incremental production over the same 13) is underway at Qatar’s North Field, period of 28 bcm per year. incremental production at South Pars is currently limited to another 45 bcm in But the medium-term developments Phases 6-10 from 2008-10 and up to 20% appear more challenging due to the or 9 bcm of incremental production from diffi cult equation between the use of the existing Phases. Commissioning of gas for domestic industry, power, oilfi eld Phases 6-8 sour gas production started in reinjection and export projects on one summer 2008 and the 504 km IGAT-5 sour- side and production and imports on the gas pipeline from the Assaluyeh processing other. Currently Iran is – marginally – a complex to the giant Aghajari oil fi eld net importer of gas. While the country was opened soon after. Phases 9-10 were has exported about 4.5-6 bcm per year offi cially inaugurated in March 2009 and to Turkey since 2003, Iran has been is expected to ramp up production toward importing about 6.5-8 bcm per year from the end of the year. Turkmenistan – principally to supply

5. Commercial gas production excluding reinjection is expected to be 195 bcm, according to the National Iranian Gas Company (NIGC). 6. Including volumes reinjected into oil fi elds. Commercial production was 107 bcm in 2007, according to Natural Gas Information 2008, IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 57

Table 5 South Pars development phases

Upstream partners Target Gas production* Phase Note (awarded) Actual Condensate Petropars (NIOC 2001 9 bcm 1 subsidiary) Nov-04 40 000 b/d Sep-97 Total; Gazprom; Petronas 2001 18 bcm 2/3 Sep-97 2002 80 000 b/d

4/5 ENI; Petropars; Naftiran 2004 18 bcm

Jul-00 Apr-05 80 000 b/d Sour gas 6/7/8 Petropars; StatoilHydro 2004 27 bcm** Oct-02 2008-09 120 000 b/d Reinjection Iran’s Oil Industries Engineering and Construction Company (OIEC) and Iranian 2007 18 bcm 9/10 Offshore Engineering and Construction Company (IOEC), plus South Korea’s LG Sep-02 2009 80 000 b/d Capacity added 45 bcm 2002-07 200 000 b/d Capacity added 45 bcm 2008-10 200 000 b/d

11 Total, Petronas Pars LNG

12 Petropars Iran LNG

13/14 Shell, Repsol Persian LNG Ghararagah Khatam- 15/16 ol-Anbia (Iranian Revolutionary Guard) Pars Oil and Gas Co. 17/18 (POGC); National Iranian Drilling Co. (NIDC) 19-21 To be awarded

22-24 To be awarded

Source: South Pars Gas Complex Company, media reports. Note: *bcm per year. **Initially sour gas. To be switched to sweet gas in two years. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 58

The slow pace and impasse of project fi eld for their LNG development. Other development for the South Pars Phases foreign companies, including the Chinese, assigned to LNG projects and new upstream have held intermittent talks on LNG awards since 2004, due to changes in development of other fi elds7. In addition, political priorities and international prolonged negotiations for gas deliveries isolation, means that production growth is to the Iran-Pakistan-India (IPI) pipeline likely to slow signifi cantly for the fi rst part mean that this project is unlikely to be of the next decade, with later increments operational at least until 2013 or beyond. dependent on a resurgence in awards in the next couple of years. The use of domestic Caspian region contractors with low levels of expertise, inspired by political rather than economic The Caspian region8 holds signifi cant motives, also explains delays. proven reserves of 7.6 tcm; albeit lower than the three countries described above, Additional development plans will continue they promise to grow substantially as to be constrained by international new discoveries are confi rmed – notably sanctions and western pressure. Iran in Turkmenistan. The region’s central has signed up to extensive long-term geographical position gives it the unique commitments to supply LNG, but without capability to supply pipeline gas to Russia, western participation in the installation Europe, Asia and the Middle East. So far of the LNG trains, these are now most gas is mainly exported to Russia; however unlikely to be met before 2015. competition for access to Caspian gas supplies has been intensifying over the These upstream problems, added to a past year. Total production reached rapidly increasing domestic demand, are 172 bcm in 2008 from 161.5 bcm in 2007. likely to mean further delays to planned This compares to a domestic consumption capital intensive gas export initiatives. In of around 90 bcm, with power generation, this respect, short-distance pipelines or industry and the residential sector all increments through existing infrastructure taking a signifi cant share of demand. are likely to be the fi rst solution chosen for any surplus gas. Turkmenistan is the main gas producer and exporter in the Caspian region and In mid-2008, Iran offi cially postponed two fi gures for 2008 put annual gas production of its three LNG developments focused on at 70.4 bcm, down from 72.3 bcm in 2007, South Pars for the 2010-13 period leaving compared to domestic demand of around only the LNG project wholly-owned by 20 bcm. Turkmenistan has announced NIOC in place. Partners Shell and Total may its intention to bring production to switch to later phases of the South Pars over 75.8 bcm in 2009, with an intensive

7. In March 2009, Iran’s Oil Minister said that Iran signed a deal with China National Offshore Oil Corp. (CNOOC) to develop the North Pars gas fi eld as an LNG export project. 8. Although Russia and Iran are also Caspian littoral states, the ‘Caspian region’ is used here to cover Azerbaijan, Kazakhstan, Turkmenistan and Uzbekistan. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 59

program of drilling to bring a new fi eld Russia and China are well placed; China on stream at Gurrukbil-Garabil near the National Petroleum Corporation (CNPC) Dauletabad fi eld that is the main source has been drilling exploration wells at of current gas output. Among the other the South Yolotan fi eld since 2007 and gas producers, production was up slightly continuing work on a gas pipeline link in Uzbekistan and there were more from the Turkmenistan sector of the Amu substantial increases in both Azerbaijan Darya basin (where it has a production and Kazakhstan: in Azerbaijan, phase I sharing agreement (PSA)) eastwards to of the offshore Shah Deniz fi eld pushed China. Iran is also in the picture following annual output up to 16.3 bcm (up from the signature of a memorandum 11 bcm in 2007); in Kazakhstan, total gas of gas cooperation with Turkmenistan production reached 33 bcm, of which during a meeting of Presidents 17.5 bcm was commercial or “sales” gas. Berdymukhammedov and Ahmadinejad in February 2009. Interest from IOCs has A major upstream development in 2008 been held back by the continued insistence was the international audit conducted on on the Turkmen side that their role in gas reserves at two fi elds in Turkmenistan. onshore gas development is limited to Provisional fi ndings were announced in service contracts9. Turkmenistan’s export October and, while more appraisal work commitments to Russia, China and Iran is necessary, the results were impressive. are well above current production levels, The best estimate of gas-initially-in-place and this, along with increasing interest at the vast South Yolotan-Osman fi eld (this from other potential buyers, calls for is now considered a single structure) was production to increase. 6 tcm of gas, within a range from 4 tcm to a high of 14 tcm; the best estimate Alongside the above-ground risks affecting for the nearby Yashlar fi eld was 0.7 tcm. gas production in Turkmenistan, there These fi gures suggest that Turkmenistan are likely to be signifi cant development is destined to join the small world elite challenges with the next generation of gas of gas reserve-holders, with reserves far production, since it is deep, high pressure greater than the 2.7-2.8 tcm currently and high temperature (HPHT), and sour. listed as proven. The Turkmenistan side expects fi rst gas from South Yolotan-Osman already in Confi rmation of these major onshore 2011, with successive development phases reserves has intensifi ed competition of 10 bcm per year after this date up to for exploration and development rights a total of 40 bcm for the initial phase; in Turkmenistan and a succession of given declines in existing fi elds, the South governmental and commercial delegations Yolotan-Osman development is essential have received varying degrees of to Turkmenistan’s ambitions to increase encouragement from the Turkmen side. gas production (the offi cial forecast sees

9. Investment opportunities in the Turkmenistan sector of the Caspian Sea remain open, as witnessed by a memorandum of understanding concluded by the Turkmenistan authorities with Germany’s RWE in April 2009 that could lead to

development rights for an offshore block. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 60

Map 5 Caspian gas infrastructure

Minsk BELARUS Orenburg To Russia Astana Kiev Orsk Karachaganak UKRAINE Krasny Oktyabr Ce nt ra Atasu l A sia - C MOLDOVA e n Severny Ustyurt KAZAKHSTAN Atyrau t Odessa re RUSSIA ROMANIA Novorossiisk Caspian Zapadny Lunnan Constanta Ustyurt To China Sea Caspian Shymkent Almaty BULGARIA GEORGIA Coastal UZBEKISTAN SCP Bishkek Burgas Black Sea Supsa Tbilisi expansion pipeline Tekesu KYRGYZSTAN Batumi AZERBAIJAN Shagyr Istanbul Erevan Tashkent Ankara Samsun Erzerum ARMENIA Baku Turkmenbashi AZER. Trans- Kirikale Caspian TURKMENISTAN TAJIKISTAN Izmir TURKEY Tabriz options Ashgabat Dushanbe IGAT -9 Mary CHINA Dauletabad Ceyhan Neka Donmez TA Tehran PI op IGAT -7 tio n 2 CYPRUS SYRIA AFGHANISTAN LEBANON Islamabad Bagdad IRAN Kabul Mediterranean Sea TA PI o IRAQ Esfahan pti ISRAEL on 1 To India JORDAN Quetta KUWAIT EGYPT New-Dehli NEPAL Iran-P akis Katmandou tan PAKISTAN -India Existing gas pipeline SAUDI Planned/additional gas ARABIA QATAR INDIA transportation capacity OMAN Only major trunk lines (mostly trans-national) are shown. 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: Petroleum Economist, IEA. production of 250 bcm by 2030), and to While the new price offered to sustain multiple export routes. Turkmenistan and Uzbekistan seems to be considerably more than the one offered in Russia remains the main export market 2008, it is not yet possible to examine how for all the East Caspian gas producers, i.e. a “European” netback price is calculated, Turkmenistan, Uzbekistan and Kazakhstan, nor to predict how – and how fast – these and a major change in the politics and export prices will react to declining economics of East Caspian gas was the European border prices in 2009. Moreover, move from January 2009 to a “European” as well as transmitting prices to Central netback price for export along this route Asia in 2009, Gazprom has been faced with (see Box 1). Gazprom had previously used lower demand for its own gas exports its near monopoly over export routes to and this has also been felt by Gazprom’s claim a slice of the exporters’ resource suppliers in the Caspian. It is not clear how rent, but since 2006 has been forced to much fl exibility there is in the existing give ground, at least in part in order to contractual arrangements, but Gazprom deter the development of alternative has been interested in limiting its take routes to market. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 61

from the region as long as European gas Investment in liquefaction demand remains weak. capacity As of late 2009 or early 2010, Turkmenistan „ Project delays (implementation and will no longer be as reliant on export decision making) are common in the routes to Russia with the scheduled LNG liquefaction sector due to skilled opening of a large-volume export route to labour shortages and higher material China in addition to the existing smaller- and engineering costs, as well as market capacity link to Iran. The policy of pursuing uncertainty. multiple export options has brought dividends in recent years and increased „ Only fi ve projects have advanced to Turkmenistan’s leverage with potential FIDs since mid-2005. and actual buyers of gas. This policy also appears to be the driver behind Ashgabat’s „ While engineering, procurement and proposal for a domestic East-West pipeline construction (EPC) prices may come bringing gas from new production areas down somewhat, more reductions around South Yolotan-Osman westwards seem likely, and this may take more towards the Caspian coast (rather than time to assess, causing some additional linking to the existing main lines of the delays in decision making. Central-Asia Centre system to Russia and/ or the new Turkmenistan-China pipeline). „ There are signs of changing contracting, The domestic pipeline could still serve business models and corporate as an export route to Russia through a structures of LNG liquefaction projects, connection to the Caspian Coastal Pipeline refl ecting more diffi cult resources and (although this is yet to be built), but it higher risks. opens up the possibility of additional deliveries to Iran as well as – potentially – to a future Trans-Caspian line. With regard to liquefaction, the next big questions are on where the next generation of LNG projects are coming from after 2012 and what the potential of slippage of new projects is. After only three FIDs in 2007 (Pluto LNG in Australia, the Skikda replacement train in Algeria, and Angola LNG), there was only one in 2008 (Gassi Touil). Several projects did not reach FIDs in 2008, as previously targeted (e.g. Gorgon and Ichthys, Australia, Nigeria LNG Seven Plus, Brass LNG, and a Flex LNG project, Nigeria). Thus expansion post- 2012 already looks slower than previously thought, as recently as in 2008. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 62

Figure 12 LNG liquefaction, existing, planned and under construction

900

bcm 800

700

600

500

400

300

200

100

0 Existing Construction - Need FID - Others - start in 2009-13 to start by 2014-15 start unknown Africa Asia Eurasia Europe Middle East North America South America

Key point: A vast expansion, but FID needed soon for new projects

Source: IEA.

As of May 2009, there is 303 bcm of could be taken on the other projects or that existing liquefaction capacity, 35% of other projects could not start by 2014-15. which is in Asia, 25% in Africa and 26% in the Middle East. 103 bcm – one-third of the Increasing challenges existing capacity – is under construction and expected to start between mid-2009 With increasing indications of project and 2013, with the majority located in delays (implementation delays and decision Qatar (see section on Qatar in Development making delays) across the industry, the in the LNG markets). Uncertainty concerns expansion of the liquefaction sector seems investment in other projects – a total of 445 unlikely to be implemented as planned for bcm which are currently at various stages of the following reasons: planning development. In this section, we will focus on the challenges faced by some „ uncertainty over material and LNG projects in particular, representing engineering costs a total of around 80 bcm. These are the projects which we believe are most likely to „ skilled labour shortages reach FID within the next two years, which should enable them to start operating by „ more market uncertainty, particularly 2014-15. This does not mean that no FID lack of long-term sales commitment. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 63

Completion times have escalated. In 2005 recognised by LNG project sponsors only and 2006, plants such as Darwin LNG or in 2006. While steel and other prices have Qalhat LNG were completed in less than fallen sharply since late 2008 and into three years. The projects starting exports 2009, the translation of these falls into in 2009 are taking more time. It is, for actual project cost reductions has yet to example, already more than 50 months be seen, and decision making could be since the EPC contract was awarded for delayed further while project sponsors the fi rst of Qatar’s mega-trains. wait to see the extent of reductions. Furthermore, the next generation of gas A tight EPC market reserves is expected to be more diffi cult and complicated, so that environmental The tight EPC market which persisted concerns concerning CO2 and sour until late 2008 has not only resulted in components of feedgas streams are also increasing costs but also project delays. adding pressures. While capital costs of liquefaction plants had plummeted from USD 600 per tonne Finally, the escalation of EPC costs has per year of installed capacity to USD 200 affected the nature of contracting. Before over the ten years to 2005, they increased the cost increase, EPC contracts for LNG back to around USD 1 000 or even more for plants were awarded on a “lump-sum new plants seeking FID10 in recent years. turn-key” (LSTK) basis. The potential cost There are uncertainties on the evolution increases after the contract was awarded of costs for planned projects and for the were traditionally borne by the contractor, ones under construction. Some industry although part of these increases could experts argue that costs will come be passed onto the clients depending on down as materials’ costs are going down the contract clauses. However, the higher and contractors will compete against than anticipated cost increases resulted each other as the current generation of in some EPC contractors offering higher projects is completed, and fewer new ones contracting prices for future projects. emerge, but the timing and extent of cost falls remains unknown. Others argue that While the LSTK approach is more diffi cult, EPC costs will come down only after the it remains the preferred approach for beginning of 2010, because contractors the majority of contractors to keep still have backlogs. discipline in their project implementation with some fl exibility added (“open book One major factor has been sharp material estimation”, “re-inverse & lead items”, cost escalation in the middle of the or “modular construction”). While these decade, affecting steel, cement, and other changes reduce risks for contractors, they raw materials. The current wave of cost may discourage project promoters from escalation started around the beginning making commitments due to additional of 2005, although the issue was widely risks of cost increases.

10. It should be also noted that USD per tonne fi gures are highly dependent on site specifi c factors. Some cited fi gures include

jetties and some utility facility costs, while others do not. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 64

Limited human resources same time, EPC contractors are likely to have diffi culties fi nding the necessary Another challenge is limited human skilled workforce even if they use resources, not only in terms of skilled subcontractors. labour force – engineers, experts in complex project management – but also More diffi cult projects in the future in terms of engineering companies. Such an issue is common to the whole E&P Yet another factor is rather simple to industry, not specifi cally to LNG projects. describe: projects are becoming more The existing workforce working in the diffi cult. There are much bigger, more E&P industry has been stretched as they diffi cult, and more remote projects face new, technically challenging projects. – complex technically and engineering- Skilled labour forces in subcontracting wise. Project sponsor companies are more are also scarce for construction and diversifi ed, which requires EPC contractors commissioning during the latter stages of to educate sponsors. In other words, a project. there is lack of human resources in the project sponsor side. Not only national oil A small number of companies dominate and gas companies (NOCs), but some of recently completed LNG plants (grouped big international oil and gas companies according to the proprietary liquefaction (IOCs) may need additional skilled human process used). These companies are JGC resources. Corporation and Chiyoda Corporation, both of Japan; KBR, Bechtel as well as Project ownership structures sometimes Foster Wheeler and Chicago Bridge and make projects diffi cult. If the project Iron of the United States; Snamprogretti is integrated with the upstream of Italy; and Technip of France. development, it is generally simpler. If the upstream venture has a separate Over the past few years, the existing and organisation or sponsors, more co- increasing shortfall of skilled engineers ordination is required. If the feedgas is has often been discussed within the supplied by third parties, transactions global geoscience and engineering and transfers of feedgas tend to be community. This does not mean that the more complicated. The same feedgas few engineering companies can easily sources may sometimes have to supply to expand their employee bases. Firstly, alternative markets (often quickly growing future opportunities are uncertain. domestic markets). Clear frameworks are Furthermore, there may be a limit to the needed to make decision making easier. number of projects (including refi neries and petrochemical complexes, as well A possible solution is smaller-scale LNG as LNG) that can be undertaken globally projects, including those using fl oating simultaneously. EPC companies need liquefaction vessels. There are many to have both their workforce and the technical barriers to overcome for such material arriving on the site at the same fl oating LNG (FLNG), notably differing gas time. If projects are undertaken at the composition and associated liquid contents 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 65

at relatively small gas fi elds targeted to a sponsor with an already established for those projects, preventing easy market portfolio (for example Algeria). application of standardised liquefaction Firm sales commitments are increasingly facilities. Having said that, established more important to decision making. players in the LNG industry have expressed interest in this new segment and at least PNG LNG, Papua New Guinea a few projects may advance. In particular, the Canadian shipping company, Teekay, Competitive front-end engineering and and Merrill Lynch agreed in March 2009 design (FEED) works are underway on to convert an 87 500 m3 LNG carrier, the ExxonMobil-led PNG LNG project. In Arctic Spirit, currently transporting LNG addition to ExxonMobil’s 41.5%, other from Alaska, to Tokyo, into a fl oating shareholders in the venture include Papua liquefaction vessel and use it at a pier near New Guinea’s Oil Search (34%), Australia’s Kitimat, British Columbia. The FLNG vessel Santos (17.7%), Japan’s Nippon Oil (5.4%), would produce 680 Mcm (500 000 tonnes the state-owned Mineral Resources per year) of LNG, and could commence Development Company (MRDC) (1.2%) and operations in 2012. This would make Eda oil (0.2%). These shares will change Canada the fourth LNG exporting country when the Papua New Guinea government among the OECD members. exercises its option to purchase a 19.4% stake in the project. The next generation of LNG supply – a critical question in 2009 The project has submitted an and 2010 environmental impact statement (EIS) to the Department of Environment and With the challenges and uncertainties Conservation. In addition to a liquefaction described above, the current fi nancial plant to be located 20 km northwest of the crisis is making it even more diffi cult for capital Port Moresby, the project involves these large capital intensive projects to the development of gas fi elds in the move forward. Currently more than 10 Highlands region along with a processing projects in the world are looking to start plant, and a pipeline which will run 311 km operations in 2014 or 2015. But if sponsors from the processing plant to the coast and want to capture this potential market 400 km offshore to the liquefaction plant window, FIDs need to be made in 2009 or site. 2010. This section looks in detail at the challenges faced by these projects. Project PNG LNG will have a capacity of about sponsors must recalculate their project 8.6 bcm (6.3 million tonnes per year (Mtpa)). economics at much lower energy prices. An FID is scheduled by the end of 2009 LNG buyers are more hesitant to make with start-up in late 2013 or early 2014. long-term offtake commitments due to Before reaching the FID, the venture will the uncertainty of their market demand. have to line up marketing arrangements. Only a few liquefaction projects have In April 2009 Oil Search claimed that a been concluded without long-term sales “major Asian customer” has agreed to buy contracts and they were only possible due 2.7 bcm (2 Mtpa). 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 66

Table 6 LNG export projects nearing final investment decisions (FIDs) in 2009 and 2010

Production target Project (sponsors), capacity, FEED FID target

PNG LNG, Papua New Guinea (ExxonMobil, others) Late 2013 or early 2014 8.6 bcm per year (2 trains) End 2009 Competitive FEED underway (JGC/KBR, Bechtel) Ichthys, Northern Australia (Inpex, Total) Late 2014 or early 2015 10.9 bcm per year (2 Trains) End 2009 or early 2010 FEED awarded January 2009 to Chiyoda, JGC and KBR, Gorgon, Western Australia (Chevron, Shell, ExxonMobil) 2014 20.4 bcm per year (3 Trains) End 2009 FEED underway on 3 train basis by KBR and JGC Shtokman, Russia (Gazprom, Total, StatoilHydro) Early 2010 2014 10.2 bcm per year (1 or 2 Trains) (delayed) FEED underway by Technip Donggi-Senoro LNG, Central Sulawesi, Indonesia 2013 (Mitsubishi, Pertamina, Medco) 2009 2.7 bcm per year (1 Train) Nigeria LNG Train 7, Nigeria (NNPC, Shell, Total, ENI) 2014 First half 2010 10.9 bcm per year Brass LNG, Nigeria (NNPC, 2014 ConocoPhillips, ENI, Total) First half 2010 13.6 bcm per year 2014 or 2015 One of the proposed CBM-to-LNG projects in Australia 2010

Source: IEA, company information.

Ichthys, Australia move the potential site from Western Australia. Now the FID is scheduled by In early 2008, the operator Inpex indicated early 2010 with the fi rst shipment of LNG that it wanted to make the project’s FID in late 2014 or early 2015. late 2008 or early 2009, while offi cial start- up was scheduled for late 2012. But it was The project will initially produce 10.9 bcm only in January 2009 that Inpex awarded (8 Mtpa) of LNG, 1.6 Mtpa of LPG, and a FEED contract based on a liquefaction 100 000 b/d of condensate. The project plant in Darwin in the Northern Territory, is estimated to cost over USD 20 billion. Australia, to a consortium grouping Obviously reducing the cost is one of the Chiyoda, JGC and KBR, after deciding to primary purposes of the work in 2009. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 67

Feedgas will come from the Ichthys fi eld in (4.2 Mtpa) for Japanese utilities from the Browse Basin offshore Western Australia Chevron; and 2.7 bcm (2 Mtpa) each by via a 850 km subsea pipeline to Darwin. A Shell and ExxonMobil for PetroChina. Shell separate FEED contract for the project’s is also expected to bring some volumes to offshore facilities has yet to be awarded. its Mexican and Indian terminals.

Inpex said in December 2008 that it could Other projects in Western Australia sell part of its stake in the project to and Northern Territory Japanese utilities. Inpex currently holds 76% while Total holds the remaining 24%. There are several other LNG project The project will be the fi rst to be operated proposals in Australia. Chevron intends to by the Japanese company and its primary go ahead with Wheatstone as a stand-alone marketing target is Japan. LNG plant at Onslow. Recent drilling on the Iago fi eld was successful and Chevron Gorgon, Australia is considering a multi-train project. The target for start-up of the fi rst two trains In Northwest Australia, the three partners is 2015. In addition to a second train at in Gorgon LNG – Chevron, Shell, and the Pluto project, Woodside is leading two ExxonMobil – hope to complete FEED on other projects in Australia – Browse LNG in an enlarged phase one conducted by the Western Australia and Greater Sunrise (via a KBR/JGC joint venture in 2009 and make fl oating or Darwin onshore plant). A second a FID soon after. The operator Chevron train at Darwin LNG also has been mooted. admits that Gorgon would be a very costly project and that Chevron was continuing The Western Australian state government to do what it could to reduce costs. selected a site in December 2008 for an LNG hub in the Kimberley region to receive gas The project currently has government from the offshore Browse basin – James approval to build two trains of 6.8 bcm Price Point, 60 km from Broome, as it could (5 Mtpa) capacity each on Barrow Island, meet environmental requirements and and is seeking permission to build a third. accommodate several projects. It also had The project’s costs are currently estimated no settlements within 20 km. to be more than USD 20 billion. Chevron has emphasised that construction costs CBM-to-LNG projects in Queensland would fall in the current economic crisis. Meanwhile, four projects in Queensland Chevron expected to sign further initial on the east coast of Australia have either agreements for the sale of its share of entered or about to launch the FEED stage. Gorgon’s output before it takes FID. All are based on the state’s coalbed methane Chevron holds 50% of Gorgon’s equity, (CBM) reserves and the three largest ones with Shell and Exxon each holding 25%. are backed by well established industry The partners have already signed up players (BG, Petronas, and ConocoPhillips). with buyers in Japan and China for some Some form of project consolidation of the output from the project: 5.7 bcm looks inevitable. Players recognise other 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 68

Table 7 Australia’s coalbed methane/coal seam methane race

Production target Project (sponsors), capacity, FEED FID target

Curtis LNG (BG, Queensland Gas Co) 2014 9.5 bcm = 7 Mtpa End 2009 FEED underway by Bechtel Gladstone LNG (Santos, Petronas) 2014 4.8 bcm = 3.5 Mtpa Mid-2010 FEED underway by Bechtel Australia Pacific LNG (ConocoPhillips, Origin) Late 2010 (T1) 2015 9.5 bcm = 7 Mtpa Early 2011 (T2) FEED expected in 2009 likely by Bechtel Gladstone LNG (LNGL, Golar LNG, Arrow Energy) 2012 Late 2009 2.0 bcm = 1.5 Mtpa Shell, Arrow Energy 4.8 bcm = 3.5 Mtpa Southern Cross LNG (LNG Impel (Galveston LNG)) 1.4 bcm = 1 Mtpa

Source: IEA, company information. challenges of CBM-based projects: access Mitusbishi (51%), state-owned Pertamina to land (the number of wells required (29%), and the privately owned Indonesian would be larger); water disposal; heating company Medco Energi (20%). In January value (5%-7% less than traditional Asia 2009, the liquefaction venture signed 15-year Pacifi c LNG); and management of longer contracts with Pertamina and Medco Energi and slower ramp up of gas production. for the feedgas gas supply to the plant. The start of LNG production could come as early Donggi-Senoro LNG, Central Sulawesi, as 2013 if a FID comes in early 2009. Japan’s Indonesia electric power companies11 may agree to take all of the output from the project. The relatively small size of Donggi- Senoro LNG project of 2.7 bcm (2 Mtpa) NLNG Seven Plus and Brass LNG Nigeria in Central Sulawesi, Indonesia, may give some advantages to the sponsors in terms Both fi nal investment decisions on Nigeria of marketing and fi nance – the operator LNG Train 7 (NLNG Seven Plus) and Brass

11. These could include Chubu and Kansai, who already import a lot of LNG from Indonesia. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 69

LNG slipped from 2008 into 2009. Both in 2014. The joint venture plans to invest projects have been proposed for many around USD 15 billion in total for the years, but face delays mainly due to fi rst phase of the project. Construction security concerns in the Niger Delta and is expected to begin in 2010, with fi rst uncertainty over the government’s policy pipeline gas in 2013. LNG production (see section on Nigeria). Still the partners is planned at a rate of around 10.2 bcm hope that NLNG Seven Plus and Brass LNG (7.5 Mtpa) from 2014. While the Shtokman will make FIDs by the fi rst half of 2010. Development Company is controlled by Gazprom (51%) and its partners are Total Prospects for NLNG Seven Plus have (25%) and StatoilHydro (24%), all the improved now that a new inlet gas price for hydrocarbons will be owned and marketed the entire NLNG complex has been agreed by Gazprom. Thus a question remains with state-owned Nigerian National regarding how Total and StatoilHydro Petroleum Corporation (NNPC). A super- book any reserves from the project. mega train of 10.9 bcm (8 Mtpa) – even larger than the Qatari mega trains – is envisaged for this project. The partners of Investments in regasifi cation NLNG include NNPC (49%), Shell (25.6%), and pipelines Total (15%) and ENI (10.4%). „ Growing demand expected in all Brass LNG has also secured marketing markets means that increased agreements with global portfolio players investment in infrastructure, notably including BG, GDF SUEZ, BP, ConocoPhillips, long-distance pipelines and/or LNG and ENI for more than three years and terminals, is needed, in particular in partners are eager to start the project as regions with falling production such as soon as possible. Total replaced Chevron Europe. in 2006 to join the project, which plans to have capacity of 13.6 bcm (10 Mtpa) from „ While current economic conditions will two trains. The ownership of the project slow demand growth, the lead times is NNPC (49%), ConocoPhillips (17%), ENI for these investments are generally (17%) and Total (17%). The project awarded long, and a number of projects are Bechtel the FEED contract in November pushing ahead, while others are likely 2004 and the construction contract in to languish or be cancelled outright. June 2007. „ Rising costs, regulatory issues, Shtokman, Russia geopolitical risks and NIMBY issues all add to the problems created by the Front-end engineering design works for current fi nancial crisis; innovation may the offshore elements, liquefaction plant, offer one means to overcome these and pipelines are due to be completed by barriers through, for example, small mid-2009. Although the FID has slipped scale or fl oating LNG regasifi cation into 2010, the partners maintain that the vessels. project should see the fi rst LNG shipment 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 70

New supply infrastructure will be needed Costs. Pipelines are capital intensive to face increasing demand – be it the projects with high upfront costs requiring increasing gas import dependency of investments of several billion Euros (see OECD countries or growing needs from table 10). A regasifi cation terminal project non-OECD markets such as China or would typically cost EUR 0.4-1.1 billion India. These markets are increasingly (USD 0.5-1.5 billion) for a 7-11 bcm competing for the same gas resources (5-8 Mtpa) terminal. Offshore regasifi cation – be it transported by LNG or by pipeline. has even lower capital costs12 . From the Until recently regional or long-distance buyer’s point of view, costs to deliver pipelines were the traditional way to gas to the market by pipeline have to transport gas to markets, but LNG has be compared with those of liquefaction, been gaining momentum with an increase shipping and regasifi cation together. An of LNG global trade from 169 bcm to investor will base its choice also on its LNG 233 bcm between 2003 and 2007 while strategy – integrated approach, arbitrage total international imports increased from or stand-alone investment – and may 807 to 899 bcm. Many gas producers now choose to invest in regasifi cation only hesitate between the LNG and the pipeline – this would be the case of GATE or Isle exporting options – betting sometimes of Grain where companies other than the on both as we have seen in Russia or Iran project sponsors have taken long-term as they wish to diversify demand, transit capacity commitments. and pricing risks. LNG and pipelines are therefore competing against each other in Transit and policy issues. Pipelines can particular in OECD Europe and, to a lesser be affected by political issues as seen extent, in North America, but both have during the Russia-Ukraine crisis, but can been also considered in China, India, and also benefi t from inter-governmental Latin America. backing to improve or strengthen political relationships. The Arab pipeline between While both options ultimately depend Egypt, Jordan, Lebanon and Syria or the on upstream developments, utilisation Dolphin gas project between Qatar, of LNG regasifi cation also depends on the UAE, and Oman are such examples. the future developments of liquefaction Furthermore, project sponsors would – the perspective of under-utilisation seek long-term visibility on regulatory of terminals may deter investments rules – a multinational pipeline would in regasifi cation if the investor is not see regulatory diffi culties increasing with pursuing arbitrage or an integrated LNG the number of countries crossed, unless supply chain strategy. Both supply options harmonisation can be achieved. have differing strengths and weaknesses for project sponsors and the buyers: Flexibility. Pipelines tend to be dedicated to a market or a region which limits supply

12. The most recent example is Nynashamn in Sweden by AGA Gas (0.4-0.5 bcm) per year. The project cost is said to be around USD 33 million. While capital costs are lower due to lower capacity, this would not be obvious per ton of LNG. Another disadvantage is the fact that special tankers may need to be ordered for these terminals. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 71

fl exibility, but also opportunities for the to the current economic environment, supplier to divert gas to other markets. subsequent uncertainties related to LNG terminals bring more fl exibility to timing of new fi eld developments offshore the market, but this could be seen either Norway, and uncertainties on demand. as an advantage or a disadvantage from Another question will be how projects will a security of supply point of view: if LNG be fi nanced. Financing terms are generally markets are tight, consumers would have expected to be tougher, and political risks to pay a premium to attract LNG supplies, and sales agreements will come under but it can be a way to attract gas quickly intense scrutiny. For any lender, the key to meet shortfalls as Greece and Turkey is the cash fl ow generated by the project did in January 2009. itself. Depending on the project, this might be based on long-term sales and Construction times. Most LNG terminals purchase agreements or income based can be built within two to three years, expectations on tariffs and annual booking while for a pipeline the duration depends of the infrastructure. Flexible marketing on the length and the complexity of the arrangements may not be viewed as ground (or the water depth if it is offshore). advantages, as they do not necessarily However, the past years have seen many guarantee stable cash fl ows. emerging economies adopting LNG as an easy fi x for their energy shortages, while Regasifi cation developments innovative solutions such as onboard in the world regasifi cation and fl oating storage are helping countries to develop regasifi cation Looking at regasifi cation investments capacity quicker13. worldwide, around 210 bcm of capacity are currently under construction and NIMBY/safety perceptions. Both LNG and expected to start by 2012 – with around pipelines are subject to opposition from one-third in the United States and 25% local population, although the perception for Asia and Europe respectively. This will of problems appears to be more acute with increase global regasifi cation capacity by LNG tankers. around one-third, but this also means that regasifi cation capacity will still be at least In a context of tougher fi nancial conditions, double that of liquefaction capacity. capital intensive projects may have more diffi culties attracting fi nancing, especially The uncertainties lie around how much of when added to uncertainties on demand, the 531 bcm capacity currently planned upstream developments or regulation. will actually move forward. This will The Skanled pipeline project between depend fi rst of all on future developments Norway, Sweden, Denmark and (potentially) of liquefaction capacity, of regional/ Poland was suspended in April 2009 due national import requirements but also

13. There are already six operating onboard regasifi cation LNG receiving terminals in the world. At least one more is expected to open in 2009. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 72

Table 8 Investments in regasification terminals

Operation Construction Planned/proposed TOTAL Region Country (bcm) (bcm) (bcm) (bcm)

Asia China 8.5 22.4 27.5 58 Chinese Taipei 28.4 28 India 21.8 7.5 19.0 48 Indonesia 6.3 6 Japan 243.8 0.6 11.4 256 Korea 90.3 18.6 11.3 120 Pakistan 4.8 5 Philippines 1.9 2 Singapore 4.1 4 Thailand 6.8 7 Asia total 393 56 86 535 Europe Albania 8.0 8 Belgium 9.0 9.0 18 Croatia 10.0 10 Cyprus 0.7 1 France 17.0 8.3 35.5 61 Germany 14.0 14 Greece 5.2 5 Ireland 4.1 4 Italy 3.5 11.8 75.5 91 Lithuania 2.0 2 Netherlands 12.0 26.5 39 Poland 2.5 3 Portugal 5.5 2.5 8 Romania 5.0 5 Spain 57.9 8.1 8.7 75 Turkey 12.5 13 United Kingdom 28.6 16.6 41.3 87 Sweden 0.3 0 Europe total 139 57 245 442 Middle East-Africa Dubai 4.1 4 Kuwait 3.0 3 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 73

Table 8 Investments in regasification terminals (continued)

Operation Construction Planned/proposed TOTAL Region Country (bcm) (bcm) (bcm) (bcm)

South Africa 1.9 2 Middle East-Africa total 3 6 9 North America Canada (East) 10.3 20.7 31 Canada (West) 5.2 5 Dominican Republic 2.4 2 Mexico (East) 5.2 5 Mexico (West) 10.3 5.0 20.6 36 Puerto Rico 4.0 4 United States (East) 106.6 68.3 145.1 320 North America total 129 84 192 404 South Amercia Argentina 1.5 2 Brazil 6.8 2.2 9 Chile 5.2 5 South America total 8 5 2 16 Grand total 669 205 531 1 405

Source: IEA, company information. on regional dynamics. Developments in Supply infrastructure North America will be infl uenced mainly developments in Europe by unconventional gas production, in and Eurasia Europe or Northern Asia14 by pipeline developments – in particular from Russia In the World Energy Outlook 2008, the and the Caspian region (see below), in Reference scenario estimated OECD Latin America, Middle East and South Asia Europe’s gas import needs to reach by intraregional pipelines from producing 477 bcm by 2030, with a particularly sharp countries/subregions to demand centres. increase (50%) between 2006 and 2015. While the current economic conditions The following sections focus on Europe are moderating demand markedly, and Latin America. Further discussion on investments in both new pipeline and pipeline developments in South Asia and LNG terminals will remain essential. There Middle East regions can be found in the are currently over 200 bcm of planned sections covering those regions. pipeline capacity targeting Europe (see

14. China, India, Korea, Japan. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 74

Table 9 Regasification terminals under construction in Europe

Country Terminal Start up Capacity (bcm)

United Kingdom Dragon Q3 2009 6 South Hook Expansion 2009-10 10.5 Italy Adriatic LNG (Rovigo) Q3 2009 8 Livorno 2011 3.8 France Fos Cavaou Summer 2009 8.25 Netherlands GATE 2011 12 Spain Musel 2011 6.8

Source: IEA, company information. table 10) and 300 bcm of LNG planned Transmed pipeline by 3 bcm and the 8 bcm regasifi cation capacity. Obviously, not Medgaz pipeline linking Algeria directly to all this supply capacity will be built, as Spain, expected by mid-2009. this would add to an existing 400 bcm of pipelines and 139 bcm of LNG regasifi cation Most other pipeline and regasifi cation capacity15. But which project comes online projects remain at various phases of the will also depend on developments on planning stage and are subject to delays, interconnectors between the different uncertainties about costs, fi nancing and markets as the pattern of fl ows will evolve future demand as well as local opposition as domestic production declines in the to construction. Competition between North. This is particularly important for pipelines and LNG terminals will remain the infrastructure targeting Spain (see particularly tough over the coming years. chapter on Spain) or Italy. As can be seen on Map 6, most LNG terminals are located in Western Europe Only 57 bcm of regasifi cation terminals where import requirements are expected are actually under construction – most of to be the highest, while the political will them have experienced repeated delays to diversify supply might play in favour of up to two years such as Rovigo in Italy, of LNG terminals in Croatia or Poland. Fos Cavaou in France or the two Welsh Meanwhile, most additional pipeline terminals South Hook (started operation projects are expected to come from the in March 2009) and Dragon. East as additional North African capacity aiming at Spain and Italy will face either Among the pipelines under construction a lack of interconnections to the wider are the expansion of the Trans Tunisian European market or the need to convert Pipeline Company’s (TTPC) section of the Italy into a transit country.

15. Annual utilization rates typically vary between 70 and 90% for pipelines and between 50% and 90% for regasifi cation

terminals. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 75

Map 6 Main supply projects to Europe Main existing gas pipeline Planned/proposed gas pipeline Production area Existing LNG terminal Planned/proposed terminal

SKANLED AM STRE D R O N

NA BUC Caspian CO Coastal SOUTH- pipeline Turkmenistan- STREAM China pipeline TAP GALSI NABUCCO Trans- East-West pipeline ITGI Caspian MEDGAZ Arab gas pipeline options T API o Turkmenistan- ptio Iran pipeline n 2

TAPI op tion1

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.

Nord Stream pipeline now estimated at almost EUR 7.4 billion. The sheer size of the pipeline (one-tenth Nord Stream is the pipeline linking of the European gas consumption or one- Vyborg in Russia to Greifswald in third of current Russian exports to Europe) Germany. Consisting of two strings of has the potential to change markedly the 27.5 bcm each and bypassing any transit fl ow patterns in North-East Europe and country, the fi rst string is expected to be result in lower utilisation of the existing commissioned end-2011 with the second pipelines through Slovakia or Poland – starting in 2012. Project shareholders which depend on transit through either are Gazprom (51%), E.ON Ruhrgas and Ukraine or Belarus. Interconnections Wintershall holding (20% each) and to the market have been planned with Gasunie (9%). However, E.ON Ruhrgas the construction of NEL to North-West had been discussing selling 4.5% to GDF Germany and OPAL to the Czech-German SUEZ. Costs have increased substantially border. The main challenge in 2009 is to compared to the fi rst estimates and are get the fi nal environmental permits from 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 76

the countries whose territorial waters and/ supply source has been one of the major or the Exclusive Economic Zones (EEZs) are issues along with the diffi culty of having crossed: Finland, Sweden, Denmark, and different national regulatory regimes. Germany. Possible supply sources include Azerbaijan, Iran, Turkmenistan, Kazakhstan, Iraq, Galsi pipeline Egypt or Russia. As discussed in the Middle East section, Iran and Egypt are unlikely to Originally planned to start in 2008, the Galsi be major contributors as pipeline export pipeline linking Algeria to Italy through projects face competition from high Sardinia got the go-ahead at the signing domestic gas demand and LNG exports, of an inter-governmental agreement by while Russia supports the competing South Rome and Algiers at the end of 2007. Galsi Stream project. The most likely source in would be owned by Sonatrach (41.6%), the short term would be the second phase Edison (20.8%), Enel (15.6%) and Hera of Shah Deniz fi eld in Azerbaijan expected Trading (10.4%), the rest being held by the to provide between 8 and 16 bcm by Sardinian authorities. Although a FID was 2014-15, but there is tough competition expected mid-2009, it has been postponed between several pipelines to get this gas to mid-2010 which would further delay – Nabucco, South Stream, and possibly the pipeline from the 2012 expected start. ITGI, TAP and, less likely, White Stream. Galsi had suffered from cost increases The project received support from the as well as diffi cult discussions about European Commission, which proposed the route. EUR 120 million funding has the Caspian Development Corporation as been committed to the project, as part a way to have a coordinated approach to of the EU stimulus plan. According to buy Caspian gas, and agreed to commit the agreement of October 2008, Snam EUR 200 million funding as part of the would be responsible for the 520 km-long European Commission stimulus plan Italian section and Galsi for the rest. The announced in April 2009. The Budapest pipeline also depends on developments conference on Nabucco in January 2009 set of upstream and transport infrastructure the goal of signing the Intergovernmental within Algeria as well as the competition Agreement (IGA) and the Project Support from 86 bcm of LNG liquefaction capacity Agreements (PSAs) by June 2009. This planned/under construction. would enable the project to move forward on fi nancing: the EIB has already Nabucco announced that they would fi nance 25% of the project – around EUR 2 billion, with The consortium behind the 31 bcm pipeline the rest likely to be coming from the EBRD (RWE, OMV, BOTAS, MOL, Transgaz, and as well as other commercial banks and Bulgargaz) is expected to take a FID in credit export agencies. 2009, but the project has been postponed several times since its conception and is South Stream now expected to start construction in 2011 with fi rst gas in 2014. The absence of The 31 bcm pipeline linking Russia to an upstream player and a clearly identifi ed Bulgaria has been gaining momentum 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 77 Gazprom Gazprom OMV, RWE OMV, (50% each) BASF, E.ON BASF, (20% each), Gazprom + Gazprom Gasunie (9%) Shareholders Radon-Ishizumi DEPA in Greece DEPA country partner Transgaz, MOL, Transgaz, Pipeline Systems Gazprom (51%), Gazprom in Turkey, û in Turkey, BOTA Engineering (PSE) , Bulgargaz, û , Bulgargaz, BOTA 8 4 ENI Gazprom, 0.3 7.9 0.42.5 Edison, DEPA 1.50.2 EGL, StatoilHydro BH EGL, Plinacro, 0.6 DEPA/Desfa 15-20 Euros) cost (bn Estimated 8 8 8 31 10 16 16 10 8-9 27.5 27.5 11.5 (bcm/y) capacity Maximum 300 215 400 600 505 3 296 15.5 3 296 8 Length (km) Max 2 200 2 100 1 400/1 238 offshore depth (m) Greece Austria) Turkey-Greece Greece-Albania Bulgaria -Austria Serbia (10 Bcm/y) Romania, Hungary) Compression (Turkey - Compression (Turkey Under Adriatic Sea to Italy 820 115 Ionian Adriatic Pipe (5 Bcm) Ankara to Austria (Bulgaria, Under Black Sea to Bulgaria 2 200 900 Georgia - Crimea Ukraine Georgia Romania/Georgia - Romania Romania/Georgia Under Baltic Sea to Germany 200 1 200 2019 2007 2014 2015 2019 2024 2011 2007-12 End 2015 to Ankara Georgia/Iran End 2012 Under Adriatic Sea to Italy TAP ITGI (GUEU) Pipeline Completion Transit/portion Nabucco White Stream South Stream 2015 Nord Stream 1Nord End 2011 Nord Stream 2Nord 2012 Pipeline projects in Europe South Stream exp na Table 10 Table Russia Source Caspian/Russia 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 78 TTPC ENI (75%) Hera: 10.4% Cepsa (20%), Shareholders Iberdrola (20%), Iberdrola SUEZ (12% each) Endesa and GDF Sonatrach (36%), Sonatrach 41.6%, 15.6%, Sfirs 11.6%, Edison 20.8%, Enel 0.9 Euros) cost (bn Estimated 82 8 3 (bcm/y) capacity Maximum 300 640 Length (km) Max 2160 210 offshore depth (m) Spain Algeria Sardinia Sardinia-Italy 1 300 250 Algeria -Tunisia n/a n/a 3.3 Algeria-Sardinia 2 800 280 Under Mediterranean Sea to 2012 Galsi Medgaz 2009 Pipeline Completion Transit/portion Transmed 2009 Pipeline projects in Europe (continued) Green Stream exp 2012 Under Mediterranean Sea Table 10 Table Source Algeria Libya Source: : IEA, sponsors’ information. project 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 79

Box 1 The southern corridor and the Georgian crisis

Despite the apparent logic of a direct link between the gas-rich Caspian region and Middle East and the large and lucrative European market, the southern corridor for gas supply to Europe through Turkey has been slow to develop. Events in 2008-09 provided a good illustration both of the potential benefi ts of such a gas corridor in terms of Eurasian gas market diversity, and of the reasons why progress has been hard to come by. The South Caucasus gas pipeline linking Baku in Azerbaijan to the Turkish grid in Erzurum, via Georgia, has been in operation since the end of 2006, bringing up to 7 bcm per year from the offshore Shah Deniz fi eld in Azerbaijan to the Georgian and Turkish markets, with small volumes of gas re-exported from Turkey to Greece through the Turkey-Greece-Interconnector commissioned in November 2007. There are a number of other pipeline proposals that would greatly expand gas trade along the southern corridor, including the Nabucco project from Turkey through south- east Europe to Austria and two pipeline projects that would reach Italy across the Adriatic/Ionian Sea. International focus on the South Caucasus was sharpened abruptly by the confl ict in August 2008 between Russia and Georgia. Even though the actual disruption to gas transit fl ows through Georgia was minimal – a precautionary suspension of supply for two days from 12-14 August – the confl ict was seen as having a broader impact on energy security16. Almost all current gas exports from the East Caspian go through Russia, and increased perceptions of political risk in the South Caucasus – alongside an increase in the perceived costs of disagreement with Russia – were seen as hindering the prospects for a new westward export route. There is some evidence of this effect, for example in the reduced incidence of public support for trans-Caspian gas trade since August 2008 from major East Caspian producers such as Turkmenistan. However, the challenges facing the corridor are by no means limited to regional geopolitics; perhaps more signifi cant are the generic diffi culties involved in putting together any long-distance multi-country pipeline routes: how can the (often competing) interests of many different parties along a complex gas supply chain be aligned? All the proposed pipeline routes along the southern corridor involve multiple jurisdictions, and include countries inside and outside the European Union. Securing agreement on uniform, stable conditions for natural gas transmission along the route has been complicated by concerns about security of gas supply in key transit countries, most notably in Turkey where gas demand has risen rapidly in recent years.

16. The European Council noted on 1 September 2008 how “recent events illustrate the need for Europe to intensify its

efforts with regard to the security of energy supplies”. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 80

Box 1 The southern corridor and the Georgian crisis (continued)

The challenge remains to address Turkish concerns about future gas supply without creating obstacles to transit that could impede the development of the corridor. Without transparent and effi cient means of transmitting market signals back up the value chain, the attractions of European sales can look opaque to producers. This commercial challenge was reinforced with the move by Gazprom towards “European” netback pricing for East Caspian gas export from January 2009. Although the nature of the pricing formula used for this gas trade is not clear, the announcement implies parity with the price paid on the European market for Russian natural gas, minus the costs of transportation and storage – and a Gazprom margin – back to the relevant delivery point in Central Asia. The availability of a “European price” via Russia might not be sustained if the option of a southern corridor starts to fade, but for the moment it has eroded one of the route’s major attractions for Caspian producers. This shift in Gazprom’s pricing strategy has also allowed Russia to enter the picture as a potential export route and market for Azerbaijan. The infrastructure for Russia- Azerbaijan gas trade already exists, since Russia was a supplier to Azerbaijan until 2007. These imports have been displaced by growing Azerbaijan gas production, and both Russia and Iran are competing with westward routes for incremental Azerbaijani output (see section on Caspian gas production). Gazprom signed a memorandum of understanding with SOCAR in March 2009 regarding the possibility of gas sales and purchase, including swap agreements. However, if Gazprom hoped that its offer of a higher export price would delay the development of all new pipeline routes out of the Caspian then it reckoned without the determination of China to open up a new export route to the east. The Turkmenistan- China pipeline runs from south-east Turkmenistan via Uzbekistan and Kazakhstan, and construction began in 2007-08 on the different sections. Gas deliveries are scheduled to begin in the last quarter of 2009, although it may take some years before deliveries to China approach full design capacity of 40 bcm per year. The Turkmenistan-China pipeline and a PSA for the China National Petroleum Corporation on the east bank of the Amu Darya river showed that rapid progress is possible in developing a gas relationship with Turkmenistan. Key elements of the Chinese approach were the long-term commitment to gas purchases as well as underwriting the construction of transportation infrastructure up to the delivery point in Turkmenistan. Up until now, Europe’s multiple states and competing private companies have not been well positioned to match China’s determined pragmatic approach. However, Europe is now examining options for a more concerted response: the European 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 81

Box 1 The southern corridor and the Georgian crisis (continued)

Commission’s Strategic Energy Review from November 2008 fl oated the idea of a consolidated gas purchasing mechanism for gas east of Baku, provisionally called a Caspian Development Corporation. Alongside clear conditions for gas marketing and transit west of Baku, such a mechanism could help to make Europe a more compelling competitor for East Caspian gas.

over the fi rst half of 2009 through postponed to 2015. Among the issues the signature of intergovernmental faced by the pipeline are the ramping agreements with different European costs, some opposition from the European countries – Bulgaria, Hungary, Serbia, Commission eager to diversify supply, and Greece. Negotiations are underway and fi nding supply – no dedicated supply with Austria and Slovenia. The pipeline source has been identifi ed although it is consists of three main parts: the offshore likely to come from the Caspian region part to Bulgaria which would cost over and therefore compete with Nabucco. EUR 4 billion and be built by Gazprom- Also the multi-national approach means ENI, and two subsections amounting to that all countries have to fi nd fi nancing for EUR 15-20 billion. The offshore pipeline the project to move forward. would cross Bulgaria East-West and then divide into the two parts, one going to Supply infrastructure Greece and the other to Serbia, Hungary, developments in South America Austria and possibly Slovenia. Gazprom is likely to take a majority stake in Emerging markets are increasingly looking the offshore section. An expansion to at LNG to fi ll gas demand despite the 47 bcm has been announced. Originally region’s abundant resources. This is the planned for 2013, the pipeline has been case in Latin America, but also in the

Table 11 LNG regasification terminals in South America

Country Terminal Start up Capacity (bcm)

Argentina Bahía Blanca GasPort (South) May 2008 1.5 Pecém FSRU (North) January 2009 2 Brazil Guanabara Bay (Rio de Janeiro) March 2009 4.8 Tergas, Rio Grande 2013 2.2 Quintero (Central) (BG) June 2009 3.4 Chile Mejillones (North) (GDF SUEZ) 2010 1.8

Source: IEA, company information. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 82

Middle East, China and India (see separate commissioning the country’s second chapters on China and India). Latin America LNG import facility at Guanabara Bay is a net exporting region with 146 bcm (4.8 bcm) in March 2009, with commercial produced and 129 bcm consumed in 2007. operations expected in May. The Golar Excluding Trinidad and Tobago, the main Spirit fl oating storage and regasifi cation consumers are Argentina, Venezuela and unit (FSRU) is being used after completing Brazil representing 80% of demand but commissioning of the Pecém terminal in representing only 75% of total production. the northeast Brazilian state of Ceará. The Only Bolivia is a net exporter, whereas Golar Winter, which is being converted to Argentina’s surplus has been fading an FSRU in Keppel’s Singapore shipyard, since 2000 due to a lack of incentive is to be used at the Guanabara Bay from in upstream investments as prices to May. Another 2.2 bcm terminal is proposed domestic producers have been historically by Gas Energy to start by 2013. As the low. Historically, the region has relied on country focuses on developing domestic production from Argentina and Bolivia and resources, expansions of existing pipelines developed a network of pipelines between or new pipelines are unlikely to be the fi rst countries. Regional disputes, a surge in priority. resource nationalism and frequent supply shortages have resulted in three countries Argentina – Argentina, Brazil and Chile – looking at LNG to diversify their supply sources Argentina has been suffering from supply and address these shortages instead of shortages since 2004 and became a net relying on neighbouring countries. In these importer in 2008. Supplies have been aspects, developments in Latin America imported from Bolivia, but uncertainties on mirror those globally. the development of Bolivian gas production and competition from Brazil for these Although there are still a number of resources have led Argentina to look at active pipeline projects in South America, other possibilities. Regasifi cation facilities many have been abandoned over the past are therefore seen as temporary measures years. The Gran Gasoducto del Sur linking to bridge gas shortages over the next most Latin American countries17 between several years until Argentina can increase Venezuela and Argentina was put on hold its domestic gas production. State-owned in 2007 for example. Enarsa has an onshore terminal plan at Bahía Blanca with Petróleos de Venezuela, Brazil S.A. (PDVSA). Repsol’s Argentine affi liate YPF is planning to import LNG again While Brazil’s signifi cant gas resources are through onboard regasifi cation vessels under development, the country continues from May through September 2009. to import gas both by pipeline through Enarsa will continue buying regasifi ed the Gasbol pipeline from Bolivia and LNG at international prices while reselling more recently by LNG. Petrobras started it to large users at below market rates

17. Venezuela, Brazil, Argentina, Bolivia, Paraguay and Uruguay. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 83

– USD 2-2.50 per MBtu for industrial to pursue the fast-track construction customers. The government plans to option, which was announced by state- increase domestic prices by as much as owned ENAP in 2006. The terminal could 30%, which would have a positive impact be later expanded to 7 bcm. GNL Quintero on the upstream sector, in agreement with has a contract to buy up to 2.3 bcm of LNG the Gas Plus Plan, which will allow domestic from BG Group’s global portfolio. natural gas production from new fi elds to sell at higher prices than existing output. The country’s second import terminal, GNL Despite uncertainties on Bolivia, there Mejillones is also expected to open by the are still discussions on additional supplies end of 2009. This terminal located in the from Bolivia under the 2006 agreement country’s northern electric power system and importing more gas from Bolivia (SING) is an urgent priority for the mining through the GNEA pipeline (North-eastern sector. The SING system is much more Argentina Gas Pipeline). The pipeline dependent on gas for lack of short-term consists of a small section in Bolivia (17 km alternatives. Gas imports from Argentina named the YABOG/GASYRG—GNEA remain below contracted levels, and there Connector), a fi rst Argentinean phase are no interconnections between the two (97 km from the border to Mosconi) and a power grids. GNL Mejillones is expected second Argentinean phase (from Mosconi to supply 1.8 bcm to four existing power to Coronda). According to Enarsa the plants totalling 1 100 MW. GDF SUEZ is basic engineering and the environmental expected to provide about 0.8 bcm of LNG analysis report on the GNEA pipeline have for the fi rst three years from its global been completed in November 2008. The portfolio, including Yemen LNG. total capacity amounts to 10.1 bcm per year and the total investment costs are The issue for the development of LNG estimated at USD 1.8 billion. imports is the cost of LNG relative to other sources of power generation, in particular Chile coal. Chilean gas consumers may agree to pay a premium for supply security, Chile imports most of its gas from given the risk involved in Argentinian gas Argentina through the GASANDES imports. pipeline and Gasoducto del Pacifi co but supply cuts have led the country to look at other supply sources. The GNL Quintero receiving terminal in central Chile plans to open its fast-track phase in June 2009. This will involve discharging directly from the ship into the onshore vaporizers with only a very small 10 000 m3 storage tank available as buffer. Two larger 160 000 m3 tanks will be operational in the second quarter of 2010. Looming gas and energy supply problems forced the government 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 84

Investments in storage France or northern Italy. However, countries have different geological „ Gas storage is an essential part of the potential: some such as Latvia have gas value chain, helping to meet large a high potential but limited needs, seasonal and daily swings in demand, others such as Belgium, Japan or Finland and providing security of supply against almost completely lack (additional) potential. unanticipated supply interruptions. Unfortunately storage remains a supply tool with a limited geographical range. „ But gas storage is expensive, typically fi ve to ten times more so Uncertainties than oil on an energy basis, and faces diffi cult regulatory, cost and market A company looking at storage investments uncertainties. will compare the costs of a newly built facility to a long-term capacity booking „ While Europe as a whole appears to to a storage operator based on its needs have adequate storage capacity, it is in terms of space and deliverability not uniformly available across markets, over a long period, which requires some and more must be done to encourage predictability. Investments in storage necessary investment, especially as gas are therefore challenging for the reasons production falls in many IEA countries. which can be categorised as follows: regulation, demand and costs.

While attention tends to focus on major Regulatory challenges supply projects such as pipeline and LNG terminals, investments in storage facilities New storage projects, in particular depleted are also crucial to meet seasonal, daily or fi elds or aquifers, can have very long extreme variations of gas demand and construction times – from three up to ten ensure adequate supplies to all users. They years, not taking into account getting the are also a key element for security of gas necessary authorisations. In that respect, supplies. The recent Russia-Ukraine crisis each country has specifi c processes highlighted the importance of storage regarding new storage facilities which, in which enabled many countries to face some cases, require only the approval of unexpected supply disruptions and cold the competent national authority, but in weather with limited/no interruptions other cases also of different authorities or of major consumers. On the other hand, local councils. Having to deal with several the absence of storage in South Eastern stakeholders, results in increasing lead European countries resulted in residential times – when the projects are not refused. users and district heating being cut, This has been notably the case in the United while some of these countries managed Kingdom where planning application for to get gas from other countries’ storage Caythorpe and Welton facilities has been facilities. Geological structures are the most refused by local councils. Delays of up to four promising basis for storage facilities, such years due to disagreements on planning as the depleted gas fi elds of south west have been seen in the United Kingdom. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 85

There is a wide disparity in terms of tariffs embedded in long-term contracts or and access. Tariffs can be either regulated or domestic production. Flexibility from negotiated – with sometimes the regulator domestic production provided by fi elds comparing negotiated tariffs with a such as Morecambe in the United regional benchmark, as is the case in Austria. Kingdom or Groningen in the Netherlands Seasonal storage will tend to be cheaper is likely to decline in OECD countries, as on a volume basis and short-range storage production declines in general. However, cheaper on a deliverability basis. Regulatory the combination of worries about climate frameworks changing periodically can change, recent price spikes and focus on create uncertainty for project sponsors and energy effi ciency may very well result in users. Furthermore, companies building lower winter peak demand. Furthermore, in storage may not want to be restricted in some countries with a high wind potential, terms of access and some have asked for gas-fi red plants will be increasingly used third-party access exemptions, notably as reserve for wind generation requiring in the United Kingdom. However, in case a rapid start and short-range fl exibility. a partial exemption is granted, it should Due to the uncertainties on how much be clear how anti-hoarding mechanisms additional wind will be built and due to the would be applied to the exempted capacity. specifi c wind seasonal patterns of each Finally, access to storage can be imposed region, these requirements are relatively due to the allocation of rights based on diffi cult to assess. customers’ portfolio as is the case in France, Spain or Italy. Costs uncertainties

Market needs uncertainties The cost uncertainties are mainly on cushion gas and cost recovery. A 500 Mcm The diffi culty consists in assessing what depleted fi eld would need on average type of storage a specifi c market needs: 500 Mcm of cushion gas. Based on 2008 seasonal storage – usually depleted fi eld prices, this would cost over EUR 150 million, or aquifer with lower withdrawal rates but 35% more than the previous year. This higher working capacity – in order to meet would be more expensive for aquifers but seasonal variations between winter and twice what is required for salt caverns. summer, or short-range storage – usually This represents a higher risk for depleted salt caverns with a very high withdrawal fi elds or aquifers due to very long lead rate – to meet peak demand such as from times (over three years) and uncertainties power generators or be used for trading on future prices at which the gas will be opportunities. Most of the fl exibility bought. Companies may therefore seek to need – the difference between winter conclude a partnership with a major supplier and summer demand – comes from the providing cushion gas below market prices. residential sector. The need for fl exibility Existing producing fi elds with remaining and therefore for seasonal storage gas also diminish these uncertainties. can therefore be mostly derived from expectations on future residential gas Uncertainties on cost recovery will depend demand and by deducting the fl exibility on two factors: the type of use of storage – 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 86

seasonal or not and whether the tariffs and trading places in Continental Europe (see the access are regulated or not. Seasonal section on liquidity development) means storage is often valued based on the that storage valuation in non-regulated intrinsic value – by looking at the spread markets is likely to be increasingly between future winter and summer prices, infl uenced by these hubs – which still need with the risk that the coming on line of to develop in terms of liquidity. These last new storage facilities reduces this spread. factors may lead to an increased focus on For salt caverns the extrinsic value is as, salt caverns which can be developed by or even more, important than the intrinsic phases with much shorter lead times and value, depending on the market liquidity. are therefore much less capital intensive While regulation can to some extent than big depleted fi elds or aquifers. On the mitigate risks on demand and on rate of positive side, expectations of lower prices returns, the latter have to be well adapted means that facilities under construction to all types of storage. Market-based prices can hope to have access to cheaper cushion can potentially result in higher return in gas. particular for short-range storage taking opportunity of market volatility, but Europe contain higher risks. Such considerations might lead to underinvestment in more There is currently 82 bcm of working seasonal storage. storage capacity operating in Europe18 representing a deliverability of 1 510 Mcm Under the current fi nancial conditions, per day19 . Two-thirds are depleted oil or and with the existing challenges described gas fi elds (55.5 bcm), the rest are aquifers above, investors may postpone their FIDs (16.4 bcm) and salt caverns (10.1 bcm). on storage or reassess their priorities in Some countries such as France, Germany, favour of other parts of the gas value or Austria have adequate storage capacity chain. Typical capital costs for a 100 Mcm with the ratio between the working storage storage facility will vary between capacity and their gas demand higher than USD 30-100 million depending on the type 20%. Austria is the highest with a ratio of storage, with salt caverns usually more of 50%. However many countries such as expensive. There has not been any real Spain, Turkey, and the United Kingdom improvement on the regulatory issues, in have very low ratios at around 5%, while particular to simplify the planning process some in particular in South Eastern Europe or give better regulatory clarity on the or Northern Europe have almost no storage longer term. Furthermore, recent market capacity at all. The United Kingdom can still evolution seems to have complicated the rely on domestic production to provide assessments of market needs even further fl exibility, but production is already a due to the growing share of renewables third lower than 2003, and the decline is and potential impact of energy effi ciency expected to continue. Spain complements or climate change. The development of underground storage with LNG storage.

18. Europe includes OECD Europe as well as Eastern European non-OECD countries. 19. There is 76 bcm in OECD Europe with a deliverability of 1475 Mcm/d. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 87

Figure 13 European storage capacities under construction and planned

80

bcm 70

60

50

40

30

20

10

0 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 Western Europe - under construction Western Europe - planned Eastern Europe - under construction Eastern Europe - planned

Key point: Planned projects need move to construction stage

Source: IEA, regulators, project sponsors’ information.

There are currently 13.8 bcm under these projects would move quickly from construction in Europe, and again the the planning stage to construction in the majority of them (9.6 bcm) are depleted current economic circumstances. Again fi elds. Most are located in countries depleted fi elds dominate the picture with where there is already suffi cient storage 49.3 bcm planned, but there is a higher such as Italy or Germany, but there are share of salt caverns (15.8 bcm) compared also signifi cant additions in Spain and in to the existing split. This is likely to be the United Kingdom. Around 7.9 bcm are the result of the combination of two expected to be operational by 2010 but factors – the perception of increasing due to the current economic diffi culties, need for short-term fl exibility as well some projects may slip to 2011 or 2012. as the development of hubs prompting However a large number of projects companies to capture the value of (71.6 bcm) are still currently in the fl exibility, as 11.8 bcm are located in the planning stage – although this includes United Kingdom and Germany. Figure 13 projects committed which may just be shows the development of storage delayed and projects whose viability is capacity under construction and planned more problematic due to the reasons over the next decade. It has to be noted discussed above. It is unlikely that many of that around 11 bcm of planned capacity 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 88

has no starting date; furthermore it that the majority of the projects under is likely that the storage planned for construction are expected to come on 2010-11 will be delayed. Finally the quite line by 2012. In the United States as well, signifi cant jump in 2015 is more the around 3 bcm of projects expected to result of three signifi cant depleted fi eld come on line between 2008 and 2012 have projects representing over 12 bcm than an been cancelled or are on hold. In Canada, investment surge. Such large projects are facilities in Western Canada are usually also the most likely victims of investment owned by transmission operators or diffi culties and demand uncertainties. producers while in Eastern Canada, they are owned by LDCs and serve to balance Other OECD countries the need for substantial fl exibility: during the core of the winter season, residential Underground storage capacity in other and commercial demand is typically fi ve to OECD countries amounts to 139 bcm and six times higher than during the summer is mainly located in the United States, (on a monthly basis). There are very few which holds around 117 bcm of storage, new projects, but the country can also around 18% of demand. Other countries count on fl exible production. This is also with storage are Canada (20.7 bcm) and the case for Australia, where nothing has Australia (1.3 bcm). New Zealand does been planned beyond the small existing not have any storage, while Japan and capacity. Korea have LNG storage. Depleted fi elds represent the majority of these projects Non-OECD countries with 123 bcm due to the history of oil and gas production in the three countries. In Storage is also planned in other non-OECD the United States, storage capacity countries, although accurate information is owned by interstate and intrastate is not available. Many developments are transmission operators, local distribution planned in the Caspian region where a lot companies (LDCs) and independent storage of potential exists due to the presence of providers. The transmission system depleted fi elds. The dynamics behind the operators (TSOs) use part of the storage construction of new storage projects in for transmission system management and these countries is different from OECD lease the rest. The deregulation of storage, countries. Companies are usually state- added to the growth of power generation owned, often belong to the national and the presence of a liquid hub, has been (main) producer so that issues such the driver behind the development of salt as regulation or cushion gas are less caverns. The large majority of the 28 bcm important. Investments in new storage capacity under construction or planned is are often done in parallel with expanding salt caverns (17.5 bcm) as market players gas export capacity but may be affected hope to take advantage of price changes by lower cash fl ows in the next couple of and arbitrage opportunities. The average years if companies have to choose between size of storage projects is therefore investing in production and storage. much lower than in Europe at 240 Mcm compared with Europe (580 Mcm) so 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 89

Table 12 World underground gas storage* - capacity summary (working capacity)

Existing (bcm) Construction/planned (bcm)

Europe OECD Europe 76 70 Non-OECD Europe 3 14 Total Europe 82 84 Former Soviet Union Russia 60 na Ukraine 34 na Caspian Region 12 8 Total former Soviet Union 106 8 North America Canada 21 0 United States 117 28 Total North America 138 28 Middle East Iran 0 5 South America Argentina 0 0 Asia Pacific Australia 1 0 China 2 3 Total World 330 123

Source: IEA, regulators, project sponsors information. Note: *Does not include “underground” LNG storage, or aboveground LNG storage.

For example, Kaztransgaz, has announced Iran is currently trying to develop plans to upgrade and renovate Akyrtobe storage capacity as the recent winters and Poltoratskoe. In Uzbekistan, there are have highlighted the need for additional plans to develop Gazli and Khodjaabad measures to meet peak demand. Three and add 1.3 bcm of capacity. In Azerbaijan, facilities are planned representing 5.4 bcm. the two existing storage facilities could be upgraded to reach a total capacity of 8 bcm compared to the existing 1 bcm. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 90

The impact of the fi nancial in the mid-1990s to 55-75 bp in the mid- crisis on gas project fi nancing 2000s which enabled project sponsors to reduce their debts despite increasing „ Project fi nancing is becoming more EPC costs. International banks could fi nd important for the long-term future of few opportunities to fi nance upstream the gas industry, due to the continuing oil developments as most investments in high capital intensity of most gas upstream exploration and development supply and infrastructure projects. were (and remain) based on Production Sharing Contracts (PSC), in which investors „ As many projects are still waiting for usually use equity. Both IOCs and NOCs investment, demand for fi nance is had enough money at that time due to expected to be high in the next couple increasing oil prices. of years. The specifi city of the natural gas business „ However, there is a general reluctance in is that it generally requires long-term lending, and fewer fi nancial institutions investments of multi-billions of dollars involved in the energy sector, in the in upstream and supply infrastructure wake of the global fi nancial crisis, such as production facilities (increasingly which will translate into higher costs in more diffi cult regions and locations), and lowered availability of project liquefaction, pipelines, and regasifi cation fi nance from commercial banks. terminals. These segments of the supply chain are usually out of the scope of „ Export credit agencies (ECAs) are PSC, and project sponsors (or sometime expected to have a more important buyers) have to fi nd external funding role. sources. Project fi nance, i.e. non-recourse or limited-recourse base fi nance was commonly used for fi nancing these gas Before the crisis: the expansion of supply and infrastructure projects for project fi nance in gas projects several reasons. Generally, the natural gas business is composed of long-term and Before the fi nancial crisis, particularly in relatively stable value chains. Thus lenders the early 2000s, it was relatively easy for (banks) can structure their repayment natural gas projects’ sponsors to access security primary on this value chain. funding thanks to strong energy demand, high oil and gas prices, and abundant For lenders (banks), project fi nance lending liquidity in the global money market. is an attractive business if it is “well- International banks were quite aggressive structured” (see below), because generally in seeking to fi nance these projects, so the margin and the interest rate are rather that competition among banks reduced high compared with simple lending such as margins and the interest rate of lending. corporate fi nance, refl ecting the banks’ risk For example, banks’ eagerness to lend taking, while these risks can be mitigated to LNG projects led to squeezed lending by the structuring of securities. margins from around 150 basis points (bp) 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 91

Most project sponsors prefer non- receiving terminal projects in the United recourse or limited recourse borrowing States, Spain, Portugal, the United because it is off-balance sheet and their Kingdom, Canada, China, and India. Pipeline fi nancial obligations can be reduced. In the project promoters, including Nord Stream, case of NOCs, the off-balance borrowing Nabucco, and Galsi, have been all advised means that it does not affect the national by commercial banks and also approached budget and the offi cial external debt of by ECAs. Project fi nance has been used in the country. the gas storage sector in the United States and Europe as well. As more gas storage The core security of project fi nance is the projects may arise in Europe, there should cash fl ow generated by the project itself. be more room for project fi nance. In the case of a liquefaction plant, it is the cash fl ow of LNG sales income based After many successful experiences of on the long-term sales and purchase project fi nance for gas projects, lenders’ agreement, usually with take-or-pay appetite had become stronger and clauses. Lenders can hedge the risk of competition among lenders became acute. income reduction caused by lower off Particularly from 2005 to early 2007, many take volume, but are exposed to the risks banks were eager to participate in project of lower prices. In the case of a pipeline fi nance lending to natural gas projects, and a receiving terminal, the core resulting in a reduction of the lending security can be the tariff income based margins. For example, the spread on Libor on the long-term throughput agreement. for LNG project fi nance had been reduced In this case, lenders can avoid the risk of from around 150 bp in the mid-1990s to changing gas prices if tariffs are based on less than 100 bp, or sometimes even as the throughput volumes. To ensure the low as around 50 bp. core security, several back-up measures such as a completion guarantee, sponsors’ The mid-2007: The subprime loan cash injection under certain conditions, crisis and insurance are required, and all related assets and rights of the project are The impact of the fi nancial crisis on the assigned or mortgaged as collateral. Since fi nancing of natural gas supply projects large amounts and long-term lending are was deemed to be less serious than in required to fi nance natural gas projects, other sectors in the fi rst stage of the international banks usually syndicate the crisis – during the summer of 2007 consortium for lending project fi nance. and the fi rst half of 2008. After the The lending price (margin and interest) subprime loan crisis started in late 2007, and security structures are negotiated the situation deteriorated sharply. The between sponsors and the leading bank, number of banks which could participate which organises the banks participating in syndicated loans declined and the in the (usually) syndicated loan. lending price increased because of the sharp deterioration in banks’ funding Although not as large as liquefaction, situation. The interest rate offered for project fi nance has been used for LNG new project fi nance jumped up over 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 92

libor+200bp compared with rates less However by mid-2008 the situation had than libor+50 bp in 2006-07. At that moved to a more gloomy stage. time, however, several international banks deemed to be able to manage their Mid 2008: The fi nancial crisis funding were still eager to extend project fi nance to natural gas projects because In the spring of 2008, the impacts of the US the loan assets of project fi nance were recession were becoming more severe and categorised as better ones in their risk- obvious. Despite the serial reduction of return portfolio compared with other risk interest rates by the Federal Reserve Board assets such as Asset Backed Securities (FRB), the US fi nancial market continued (ABS), and Collateralised Debt Obligations to deteriorate. After Lehman Brothers (CDO). These banks were encouraged by collapsed in mid-September 2008, fears the increase in prices – both of natural of systematic failure of global fi nancial gas and the lending price for the project markets grew. Global fi nancial and equity fi nance. Tight markets and high energy markets weakened dramatically. This led prices still encouraged new gas supply to the intervention of the US, European projects. Although EPC costs were and Japanese governments to save some increasing sharply, oil and gas producing banks and insurance companies and try to countries were seeing increasing energy put in place plans to help the banks such revenues. as the Emergency Economic Stabilization Act adopted in October 2008 in the This had consequences for energy markets. United States. The depth and breadth of After August 2007, oil prices increased global recession was becoming apparent. sharply despite the possible impact on Commodity prices generally peaked in energy demand of the then unfolding mid-2008, and fell steadily into 2009. In fi nancial crisis. WTI jumped to USD 100 the case of gas prices in the United States, per barrel in October 2007, and continued they fell by nearby three quarters from to increase until the end of the fi rst half their peak in June 2008 to April 2009. of 2008. The analysis of money fl ows showed that a certain part of investment Together with the expanding fi nancial funds were changing their target from crisis, the situation of fi nancing for natural high risk securitised fi nancial products gas projects had dramatically changed and stocks to commodity markets such as well. Early 2008, some banks were still as oil or gold. The fi nancial investment willing to extend project fi nance, but in future trade in oil markets by hedge recognised the structural defects of their funds and commodity index funds which business model. What has changed since had existed since early 2000s escalated then is as follows: under the expanding uncertainty of the fi nancial crisis. Commodity markets were Diffi culties for international banks. The recognised by hedge funds as less linked basic business model of international banks to security or stock markets at that time, contained the “exit strategy”, meaning hence providing greater diversity of risk. that selling their loan assets by means of securitisation methods in order to 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 93

maintain their risk asset-equity balance. expected to be more active in providing Even for project fi nance lending, most fi nance to new projects. Multilateral banks were intending to securitize, Financial Institutions including Regional and then sell their loan assets. When Institutions such as EIB, EBRD, ADB and the security market was active, there IDB are supporting natural gas and related were differing types of risk appetite by projects as well such as the Nabucco project. differing funding sources. For example, For private banks, these enhancements pension funds preferred long-term, low- are advantageous because the loan asset risk investment while private equity covered by the guarantee facility of these funds or hedge funds took high-risk but public institutions is classifi ed zero or high-return assets. To meet this variety 10% risk weight asset even in the Basel II of appetites, banks securitised their regulations. loan assets, subdividing by risk-return variations. This structure of a loan asset Review investments plans. Over the second sale was similar to mortgaged security half of 2008, investors behind natural sales. The sharp reduction in activity of gas supply projects faced a more serious this type of securities market due to the situation that compounded the effects fi nancial crisis has affected this strategy, of the fi nancial crisis. Gas prices declined in particular the collapse of investment rapidly while EPC costs remained at a high funds, resulting in the near extinction level. Investors have been forced to review of high-risk takers. Hence, banks have to the economics of their projects as natural hold these long-term loan assets after gas demand is weakening, and growth providing the loan. It is not easy for most is uncertain at best, due to weakening banks to increase their risk assets, even economic activity everywhere. Currently, though it is a “well-structured” project these problems on the project side – the fi nance loan asset, while they are required expanding uncertainty of natural gas to reduce their leverage (asset-equity price and demand – have become at least ratio), and their write-downs in existing as critical as the fi nancial issues, affecting assets are expanding. big and small projects alike.

Recourse to offi cial fi nancial support For the energy sector, three issues are by bilateral and multilateral fi nancial particularly important: institutions. These fi nancial institutions play a signifi cant role in project fi nance. „ Funding strains persist and banks’ access Export Credit Agencies (ECAs) such as the to longer-term funding is diminished. US EXIM, JBIC, NEXI, ECGD, Coface, SACE, While in many jurisdictions, banks can and KEXIM20 have supported several natural now issue government-guaranteed, gas supply projects by means of their longer-term debt, their funding loan and/or guarantee facilities, and are gap remains large. As a result, many

20. US EXIM: The Export-Import Bank of the United States, JBIC: The Japan Bank for International Cooperation, NEXI: Nippon Export and Investment Insurance, ECGD: The Export Credits Guarantee Department (United Kingdom), Coface: The export

credit insurance company of France, SACE: The export credit agency of Italy, KEXIM: The Export-Import Bank of Korea. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Investments 94

corporations are unable to obtain bank supplied working capital and some are having diffi culty raising longer-term debt, except at much more elevated yields.

„ Lending costs are rising. Terms are generally expected to be tougher, as political risks and sales agreements will come under intense scrutiny. Flexible marketing arrangements may not be viewed as advantages, as they do not necessarily guarantee stable cash fl ows. Lenders may be less favourable to super- giant projects and unconventional technologies.

„ The retrenchment from foreign markets is now outpacing the overall deleveraging process, with a sharp decline of cross-border funding intensifying the crisis in several emerging markets. The withdrawal of foreign investors and banks, together with the collapse in export markets, is creating funding pressures in these economies. Net private capital fl ows to emerging markets will be negative in 2009.

For gas-based investment, all these issues will be important. Projects that can reduce their scale relative to markets, and shorten lead times, are likely to face fewer fi nancing hurdles. For some parts of the gas supply sector, this may encourage innovation, such as smaller production or terminal facilities. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Developments in the LNG markets 95

DEVELOPMENTS IN THE LNG MARKETS

„ The year 2008 was marked by large An era of global projects regasifi cation capacity expansions but begins saw little growth in LNG output due to many production problems. In the past couple of years, higher gas „ A massive expansion of global LNG prices and tighter market balances liquefaction capacity is about to come accelerated global exchanges of LNG over the period 2009-13, with some cargoes, notably from the Atlantic to the signs of further slight delays, while Asia-Pacifi c markets. The past issues of the demand is slumping compared to one Natural Gas Market Review argued that year ago. those inter-regional movements of LNG underpin the globalising trends of gas „ Demand is uncertain – a generally markets. weakening trend, but could surge, depending on the timing and type of Some observers and industry experts have economic recovery. Other factors can predicted that the next few years will see easily affect short-term LNG demand a return to “regional” markets along with – prices of other energy sources (coal, the expected signifi cant increase in both oil, and pipeline gas). liquefaction and regasifi cation capacity around the world, assuming that any „ 2009 and 2010 will be a test of the extra regional requirements should be fl exibility and resilience of the global met by extra output within the regions. LNG market – can it balance? Particularly for the North American market, the increase in domestic gas „ The same period (2009-10) will be a production from unconventional sources critical time for the next generation of has substantially weakened LNG demand. LNG supply projects – fi nal investment decisions (FID) will be needed in 2009 or However, the trends in the past couple 2010 if new gas is to come to market in of years have already transformed the 2014 or 2015. business to an irreversible extent: the business model of multiple supply sources „ Only one new LNG FID was made in to support deals in multiple market outlets 2008. While regasifi cation and shipping in different regions has many attractions expanded rapidly, liquefaction is the to a number of large industry players. All limiting factor in global trade. Unless LNG export projects that are going to we see new FIDs in 2009-10, a hiatus in start incremental and new production post 2012 output seems likely. in 2009 have supply commitments in multiple OECD (and non-OECD) markets. But all of them have experienced delays in construction and commissioning.

2009 has been highlighted as a year when the global LNG markets will see an 2009 OECD/IEA, © Natural Gas Market Review 2009 •Developments in the LNG markets 96

Map 7 Global LNG Projects Starting Exports in 2009

Sakhalin II

Qatar Mega Trains

Yemen LNG

Tangguh

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. unprecedented expansion in liquefaction to 22 bcm in 2007). The reduced volumes capacity, whereas the year 2008 saw little of LNG in the United States were virtually or no growth of LNG trade after years of distributed between Japan, Korea and substantial growth earlier in the decade. Spain, particularly in the fi rst half of 2008.

As a result, the cargo movements from 2008 LNG markets : sharp the Atlantic to Pacifi c regions increased to contrast between the fi rst 20 bcm in 2008, from 13 bcm in 2007 and 5 bcm in 2006. Some of them were called and second halves «diversions» as they moved to different destinations from originally anticipated In parallel with general energy market ones. However, more recently, those trends, global LNG markets saw strong transactions of relatively long distances starts in the fi rst half and bearish activities are carried out on a short- and medium- in the second half toward the end of 2008. term contract basis, rather than spot In the end, the year saw no growth in basis. Thus, the term “diversion” does not traded volumes; this was the fi rst year of include all of the non-traditional cargo no production growth in the 21st century. movements. In 2008, North American LNG activities were notably smaller than 2007, as imports Europe increased LNG imports by 15% into the United States fell by more than to 59 bcm in 2008, driven by increases in half (less than 10 bcm in 2008 compared imports into Spain, France, and Italy, despite 2009 OECD/IEA, © Natural Gas Market Review 2009 • Developments in the LNG markets 97

the continuing sluggish performance in because they are getting older; similarly the United Kingdom. for older feedgas pipelines.

The year 2008 also saw many production The year 2008 also saw a number of other problems and feedgas shortages. Some fi rsts in the history of the LNG industry. liquefaction facilities may have problems Argentina, which is actually relatively rich in natural gas resources, became

Table 13 Recent LNG supply problems (force majeure) at a glance

LNG plant Lost supply Notes

Caused by numerous thefts from condensate pipeline 2.5 bcm in 4 months NLNG, Nigeria Repair completed in March 2009. Operational status is (December 2008 - March 2009) uncertain as of June 2009 Transformer problems Qatargas I, Qatar 0.6 bcm in January 2009 Unusual to declare force majeure Return to 100% operations in February 2009 Arzew, Algeria 3 bcm in 6 months Caused by corrosion of feedgas pipeline

Source: company information, media reports.

Map 8 Global LNG trade in 2008

0.2

89

8 50

15

51

0.4 20

(bcm – preliminary data)

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. 2009 OECD/IEA, © Natural Gas Market Review 2009 •Developments in the LNG markets 98

the fi rst LNG importing country in South The demand reduction in Asian LNG America, ahead of Brazil and Chile. Brazil markets starting in the fourth quarter also received its fi rst LNG cargo in July 2008 has been stark into 2009. Buyers in 2008, although the unloading of the cargo Japan, Korea, and Chinese Taipei are asking was only completed in January 2009. long-term sellers to reduce deliveries or Three large-scale receiving terminals were defer cargoes even after annual delivery commissioned in North America, despite programs (ADPs) have been concluded the decreasing need for imports, and one earlier. of them is the fi rst LNG receiving terminal on the West Coast of the Americas – Costa On the back of this static growth in 2008 in Azul in Baja California, Mexico. trade and the expected huge expansion of capacity in liquefaction and regasifi cation, Another interesting point is the longer the LNG shipping fl eet capacity is also average shipping distance, 7 129 km in steadily expanding. Another record- 2008, compared to 6 290 km in 2007 and breaking 53 new-build ships came out 5 700 km in 2000 – another indication of of shipyards in 2008, surpassing the the globalising trends. deliveries in 2006 (30) and 2007 (34) which

Figure 14 Expanding size of LNG new-build carrier ships

= Q-Max / ship = Q-Flex < 200 000 < 160 000 < 150 000 < 140 000 <78000 <23000

2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Delivery year

Key point: Record-breaking ship delivery continues in 2008

Source: IEA, LNG World Shipping, LNG Daily, GIIGNL. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Developments in the LNG markets 99

were already at record-breaking levels. The To put things in context, the 2009-13 53 new ships represented a 25% increase period will see liquefaction capacity in cargo capacity in a year of virtually no increase from 280 bcm as of end 2008 trade growth. A further 50 or so ships are to 373 bcm by end 2010 and 410 bcm by expected to be delivered in 2009. end 2013, almost a 50% increase within fi ve years. Although there might be some The size of individual LNG carrier ships is slippage in the commissioning dates, this also expanding. Until 2001, the maximum capacity is already under construction size was less than 140 000 m3 for any new- and deemed to be commissioned (see build LNG carrier ships. Then 145 000 m3 details below in this section). In parallel, became a standard around the middle of regasifi cation capacity will increase from the decade. In parallel with slight upward 637 bcm as of end 2008 – already twice as movement to over-150 000 m3 for the much as liquefaction – to 813 bcm by end industry standard, super-giant Q-Flex 2010. (209 000-217 000 m3 cargo capacity each) and Q-Max carriers (260 000-266 000 m3) Among the major changes to be noted are being built for Qatari expansion are: projects, as they are expected to ship cargoes to relatively distant markets. „ The increase of the regasifi cation Q-Max carriers are said to be 40% more capacity in the Atlantic basin rebalancing fuel effi cient than existing vessels. Ships the share towards that area. of another size between the current standard and the super-giant, 165 000- „ A third of the incremental increase 180 000 m3, began to be delivered in 2008. of regasifi cation capacity expected by end-2010 will be located in the United States and might be relatively LNG business outlook : underutilised in the short term – or 2009-13 start operating later. „ Regasifi cation surcapacity will continue The LNG business is an integrated one, from to encourage short-term and spot production and liquefaction to shipping trade as well as the growth of hybrid and regasifi cation. Today more questions liquefaction capacity (which can target focus on the future developments of both Atlantic and Pacifi c markets). liquefaction capacity post-2013 while Unlike liquefaction, regasifi cation the shipping fl eet capacity is steadily capacity benefi ts from shorter lead expanding and regasifi cation far exceeds times – usually three years or even liquefaction capacity. There is also a large shorter – and can increase much more asymmetry on the length of time needed quickly. to develop integrated liquefaction projects compared to regasifi cation terminals or „ Planned capacity has the potential to building new ships. double both the liquefaction and the regasifi cation capacity. Although some 2009 OECD/IEA, © Natural Gas Market Review 2009 •Developments in the LNG markets 100

Figure 15 Liquefaction and regasification capacity, existing, under construction and planned 1 600

bcm 1 400

1 200

1 000

800

600

400

200

0 Regas Liquefaction Regas Liquefaction Regas Liquefaction Existing Existing/Under construction Existing/UC/Planned Atlantic Pacific Hybrid

Key point: Regasification capacity outpaces liquefaction

Source: IEA, company announcements.

projects are likely to be cancelled, a key 2009 and 2010, the huge, relatively new, question mark is how much planned regasifi cation capacity in that country liquefaction capacity will come on is expected to play an important role in line post-2013 and what will be the balancing global LNG markets, subject to evolution of the regasifi cation capacity availability of underground gas storage in the regional markets. These two capacity. issues are addressed in the investment section. While terminal regasifi cation capacity continues to increase at a rapid pace, a It is quite natural that there is more large amount of new liquefaction capacity regasifi cation capacity than liquefaction will be seeking markets, particularly from capacity, as under this circumstance 2009-13. The LNG market is at the core of LNG can play a balancing role between the fundamental uncertainties in global markets and enhance fl exibility to cope gas markets for the two years to come: with demand fl uctuations, or even supply interruptions as seen in January 2009 in „ How will the new liquefaction capacity Greece and Turkey. There have always coming on line and these potential been concerns about under-utilisation major imbalances be addressed with of receiving terminals, particularly those the market weakening in 2009? in the United States. But at least for 2009 OECD/IEA, © Natural Gas Market Review 2009 • Developments in the LNG markets 101

„ What will be the infl uence on spot prices All the construction and commissioning in the Atlantic basin and how will this activities of those LNG projects, as well affect unconventional gas production as one GTL (gas-to-liquid) plant and other in the United States? projects, have been concentrated on the 106 km2 Ras Laffan Industrial City, causing „ Will non-OECD markets be more logistical nightmares. It is not just lack of active? human resources and materials, but also logistical constraints that have delayed „ Will this mean more short-term trade, project implementation. or more interest by sellers in medium- or longer-term deals? At the beginning of 2008, sponsors still insisted that the fi rst shipment from the fi rst „ And crucially what will be the impact mega-train could start in the third quarter on the FIDs on liquefaction capacity of 2008. The inauguration ceremony of this year and next? the fi rst of the mega trains was held on 6 April 2009, after initial production began New liquefaction under construction will in March. Ramping up to plateau capacity come predominantly from Qatar, but production is also expected to take more there will be newcomers to the LNG scene time than originally anticipated. Although in 2009 – Russia and Yemen, while other all the liquefaction facilities may start up LNG exporters continue to build up their by 2011, full production capacity may not liquefaction capacity. be reached until 2013.

Qatar Qatar’s massive investments from 2009 can be summarised as follows: The biggest expansion of liquefaction capacity is expected to come from Qatar, „ Six mega trains to add 64 bcm per year who has already been the biggest exporter production by 2013 – need more time of LNG in the world since 2006. The size of to ramp up. expansion is enormous and unprecedented, from 41 bcm per year at the end of 2008 „ Three in 2009 (Qatargas 4 (March), Ras to 105 bcm (77 Mtpa) when the additional Gas 6 (June), Qatargas 5 (September)), six trains are all in operation by 2013, two in 2010 (RasGas 7, Qatargas 6 representing 27% of global capacity. (First half)), and one in 2011 (Qatargas 7 (maybe in 2010)) are to be Partly due to the size of both the trains commissioned. themselves and the expansion as a whole, the Qatargas and RasGas projects „ One began producing LNG in March are not immune to the delays and cost 2009 (originally 2007) following a overruns seen in the industry since at protracted testing and commissioning least 2005. The original start-up schedule period. for those trains was from 2007 to 2010 when FIDs were made in 2004 and 2005. „ Diversifi cation is a key in marketing. 2009 OECD/IEA, © Natural Gas Market Review 2009 •Developments in the LNG markets 102

In order to cover the expected needs of Other projects in 2009 transportation (larger volumes and longer distances than in the past), super-giant Three other new production projects are LNG carrier ships are being delivered to the due to be on stream in 2009 – also behind export ventures from Korean shipyards: schedule. 31 Q-Flex and 14 Q-Max ships. Sakhalin II, Russia Qatar has been expanding and diversifying its market reach since it started exporting Russia’s Sakhalin II project shipped its LNG in 1997 to Japan. The current expansion fi rst LNG cargo from the fi rst of two phase was originally proposed to target liquefaction trains in March 2009 to its markets in the United Kingdom and United long-term customers in Japan2 . The second States. But from 2006, the Qataris started train is expected to start operations in to market part of the expected mega- the third quarter of 2009. The facilities train output to other regional markets are not expected to reach full capacity in on medium- and long-term basis. This has the short-term due to constraints on the been a strategy to diversify its markets in 800 km feedgas pipeline and are expected terms of geographic spread, and liquid and to produce 4-5 bcm (3-4 Mtpa) of LNG, traditional market (and different regional or about 50 cargoes, in 2009, out of the pricing) combinations. The targeted 13 bcm (9.6 Mtpa) nameplate capacity. geographical distribution between Asia, Europe and North America has evolved The Sakhalin project is an example from one-third each early 2008 to 40% of the long lead times that a project in Asia, 35% in Europe, and 25% in North may require before being completed. America early 20091. Exploration activities started around the island of Sakhalin 30 years ago, while the production sharing agreement (PSA)

Table 14 At a glance: other new liquefaction projects in 2009 Gazprom’s (and Russia’s) entry into the Pacific gas market, and physically into LNG markets Sakhalin II, Russia Importance for Asian importers (Japan and Korea) = diversification of supply 13.1 bcm per year = 9.6 Mtpa sources in shorter distance A project with Japan’s engineering and money Indication of time that a project may take - mid-term investment important Yemen LNG The first project that Total takes the lead - there are only a dozen companies in 9.2 bcm per year = 6.8 Mtpa the world that have actually operated LNG liquefaction plants Tangguh, Indonesia First increase in LNG production in this decade in the country Source: company reports.

1. Ahmed al-Khulaifi , Chief Operating Offi cer of Qatargas, CERAWeek 2009, February 2009. 2. One off spec cargo (‘Cargo 0’) was sent to India prior to the fi rst cargo, but is expected to reach the destination later in April 2009. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Developments in the LNG markets 103

was signed 15 years ago between the in 2008, the project had already started Russian Federation, the Sakhalin Oblast deliveries of replacement cargoes from Administration and the Sakhalin Energy other supply sources since summer 2008. Investment Company (SEIC). Despite some early marketing success with Japanese This project marks Gazprom’s (and clients in 2003, the project operator Shell Russia’s) entry into the Pacifi c gas market, soon faced massive cost increases, and and physically into LNG markets, giving delays. This, added to the growing pressure the company signifi cant diversifi cation from the Russian Federal Environmental of its outlets. This is also important for Agency, led Shell and its existing partners Asian importers (Japan and Korea), as in SEIC, Mitsui and Mitsubishi of Japan, it represents diversifi cation of supply to hand over a controlling 50%-plus- sources from a shorter distance, with one-share stake in the export venture to a project implemented with Japan’s Gazprom for USD 7.45 billion in 2007. engineering and fi nance. The project has also demonstrated how many years may During 2008, it became apparent that the be required to be implemented, implying project would start exports in 2009, rather that medium- to longer-term investment than in 2008. As the project’s contractual is important to secure natural gas. commitments to some buyers commenced

Table 15 Sakhalin II: 25 years in making 1984-86 Lunskoye and Piltun-Astokhskoye fields are discovered. 1992 A feasibility study agreement by MMM (Marathon, McDermott and Mitsui) and Russian Federation. Shell and Mitsubishi join. 1994 Sakhalin II PSA by the Russian Federation, the Sakhalin Oblast Administration and Sakhalin Energy. 1997 McDermott withdraws. 1999 First oil production at Piltun-Astokhskoye: Russia’s first offshore oil production. 2000 Marathon withdraws. 2001 Supervisory Board approves Phase 2. 2003 Sakhalin Energy signs sales with Japan’s Tokyo Gas, Tepco, Kyushu Electric. Full development of both Piltun-Astokhskoye and Lunskoye fields starts. 2005 A major cost increase and project delay (from 2007 to 2008) is revealed. December 2006 A protocol to bring Gazprom into the Sakhalin Energy as a leading shareholder. April 2007 Gazprom acquires 50% plus 1 share and the leading role. June 2008 Project financing deal with JBIC and other lenders.

Source: Sakhalin Energy website3 and media reports.

3. Source: www.sakhalinenergy.com/en/aboutus.asp?p=key_milestones. 2009 OECD/IEA, © Natural Gas Market Review 2009 •Developments in the LNG markets 104

Yemen LNG, Yemen in Papua in Eastern Indonesia is expected in July 2009, again after a delay of more Yemen LNG (YLNG) is to ship the fi rst cargo than six months. In March 2009, the from its fi rst 4.6 bcm (3.4 Mtpa) train in country’s energy minister said that one the middle of 2009, a delay of more than option for the reduced lifting by the long- six months. The second train is expected term buyers from the Bontang venture to begin operation several months later. in 2009 would be to sell the 12 cargoes As its FID was made in August 2005, and to customers of the Tangguh project, construction started in October that year, which may fall further behind schedule. just before the global EPC market crunch Indonesia is also considering a third train began to plague the industry, the cost at the project, which may come on stream overrun for the project is thought to be in 2014-15 with capacity of 5.2 bcm smaller than those experienced recently (3.8 Mtpa). The partners also say that they at other LNG projects in the world. might be willing to reserve as much as 2.7 bcm (2 Mtpa) for the domestic sector, The project is the fi rst for France’s Total possibly through an import terminal as operator and for France’s Technip to proposed on the Island of Java. assume a lead contractor role. This French combination is also working on Russia’s The Tangguh venture has a contract of Shtokman project. 3.5 bcm (2.6 Mtpa) with the promoters of China’s Fujian terminal, which is still About one-third of the LNG is planned to waiting for its commercial operation after go to Korea. The remaining volumes are receiving the fi rst commissioning cargo contracted by Total and GDF SUEZ, both of in April 2008. Other long-term sales deals which have multiple outlets for LNG. from the venture include two Korean sales, one Mexican and one Japanese. The Korean Yemen’s state-owned Safer Exploration customers Posco and K-Power, which have and Production Company and YLNG signed contracted respectively 0.75 bcm and an agreement securing gas supply from the 0.82 bcm, are currently being supplied Marib basin Block 18 for the LNG venture from other sources, notably Egypt. Sempra in January 2008. There had been concerns gets 5 bcm (3.7 Mtpa) for its Energia Costa over gas availability and the sustainability Azul terminal in Mexico’s Baja California. of reservoirs on Block 18 since the control Up to half of the Sempra volume can be over the block was taken by Safer from diverted to other markets, most likely Hunt Oil, one of the partners in YLNG, in in Asia, including Korea Gas Corporation November 2005. Total is providing Safer (Kogas). Tohoku Electric, who currently assistance in developing the block as a buys 1.1 bcm (0.8 Mtpa) from Indonesia’s condition for project fi nancing. Arun through 2009, signed, in May 2008, a purchase agreement for 0.16 bcm Tangguh, Indonesia (0.12 Mtpa) from the Tangguh venture for a period of 15 years from 2010. Start-up of the fi rst of two trains of 10.3 bcm (7.6 Mtpa) BP-led Tangguh LNG project 2009 OECD/IEA, © Natural Gas Market Review 2009 • Developments in the LNG markets 105

Other liquefaction projects under Pluto, Australia construction for 2010-13 starts Pluto has a planned capacity of 6.5 bcm After the expected massive expansion of (4.8 Mtpa). The Pluto fi eld located in liquefaction capacity in 2009 and 2010, Western Australia was discovered in 2005. new supply additions scheduled between Along with the neighbouring Xena fi eld, it 2011 and 2013 are likely to be few, as under holds reserves of 5 tcf (143 bcm). The FID normal circumstances it takes a project was taken in August 2007. The project is around four years to be operational after underpinned by 15-year sales agreements receiving a FID and only fi ve liquefaction with Kansai Electric and Tokyo Gas which trains are under construction for have a 5% stake in the project each, the completion during the time frame. operator Woodside Petroleum holding the rest (90%). The partners now expect Peru LNG, Peru production to start late 2010. This ambitious schedule would amount to one Peru LNG is one of the few LNG export of the fastest LNG exporting projects projects in the world outside of Qatar due ever developed. The estimated cost stands to come on stream in 2010, as it was the at AUD 12 billion, including upstream only project that made a FID in 2006. The development, almost doubling the original project will be the fi rst in Pacifi c South estimate made in 2005. America. Woodside is retaining 0.6-1.3 bcm The plant has a capacity of 6 bcm (0.5-1 Mtpa) of the project’s output (4.4 Mtpa). The project sponsors are Hunt for fl exible marketing. It was originally Oil (50%), SK Energy (30%) and Repsol YPF meant to sell in the West Coast of North (20%). The gas is transported from the America, but Woodside shelved its own Camisea fi elds in the country’s southeast LNG receiving terminal plan off the coast rain forest through a 408 km pipeline to of California at the beginning of 2009. the terminal located 170 km south of Lima. Chicago Bridge & Iron won the EPC Woodside continues to evaluate options contract estimated at USD 1.5 billion for for securing gas for a proposed second the liquefaction plant in January 2007. train expansion at Pluto LNG: further development of Woodside’s existing The majority of the output from the plant is reserves at the Pluto and Xena fi elds; contracted to Mexico’s planned Manzanillo gas from third-party sources; and gas terminal on the Pacifi c Coast through from Woodside’s future discoveries. The Repsol. Some volumes may be sold to Asian company indicated in February 2008 that LNG buyers. As the Mexican terminal is due it would like to reach a FID on Train 2 of to be operational in July 2012, the initial the Pluto project in 2008, but drilling volumes will go to other destinations, activities in the Cazadores and Bellicose including the Canaport terminal in the license areas in 2008 failed to fi nd enough Canada’s Atlantic Coast operated by Repsol gas. and due to open in 2009. 2009 OECD/IEA, © Natural Gas Market Review 2009 •Developments in the LNG markets 106

Angola LNG, Angola participation agreement to join a second train consortium, which would be led by Angola LNG is a 7.1 bcm (5.2 Mtpa) Sonangol (40%). liquefaction plant located near Soyo in the South of the Congo river. The project Algeria (Skikda Replacement Train and is now owned by Chevron (36%), state- Gassi Touil) owned Sonangol (Sociedade Nacional de Combustíveis de Angola) (23%), Total, Algeria started exporting LNG in 1964 and BP and ENI 14% each. The FID was taken has now an installed production capacity in December 2007 after being postponed of 27.2 bcm (20 Mtpa) from 18 trains at several times and the project is now Arzew and Skikda, excluding the three expected to start early 2012. trains at the Skikda plant destroyed in an explosion in January 2004. The plants are Sonangol has a 20% interest in the all owned and operated by state-owned American Clean Energy LNG terminal Sonatrach. located in Pascagoula, Mississippi and expected to start late 2011. It was the In July 2007, Sonatrach agreed with KBR4 Angola LNG sponsors’ preferred option, on a USD 2.88 billion EPC contract to build but given the growth in United States’ gas a replacement train at the Skikda complex. production and low prices, the partners are At that time the new train was to start re-evaluating their marketing strategy. operating in November 2011. The train will have 6.1 bcm (4.5 Mtpa) of nameplate Given the current lack of local gas markets, capacity, greater than the three trains LNG export was clearly the main option to that were destroyed in the fatal explosion make use of gas reserves. The project will in January 2004. In March 2009, Algeria’s use both associated and non-associated oil minister revealed that the Skikda gas from several offshore fi elds. The replacement train will not be completed project also has a plan to process and until 2013, instead of 2011 as previously treat up to 3.5 Mcm per day of gas for the envisaged. A separate plant at Arzew, to domestic market, which could stimulate process gas from Gassi Touil fi eld, will start market development. If successful, the at about the same time as the Skikda train, project would provide a good example also around a year later than previously of an LNG project accompanied with planned. domestic market development, satisfying both export and domestic needs, rather The commencement of construction of than a choice between the two. The the replacement plant after the accident process of developing a second train is was delayed by cost issues for almost already underway. When ENI joined the three years. At that time, the FID of fi rst train consortium in 2006, it signed a USD 2.88 billion, equated to USD 640 per

4. The company has an alliance with JGC on gas projects around the world. But for this project, KBR decided to undertake the task alone. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Developments in the LNG markets 107

ton of installed capacity, compared to from the country due to a feedgas USD 270 of the Equatorial Guinea’s fi rst pipeline problem in June from Arzew train also completed around the time affected 20% of the capacity. In order to (May 2007). But the Skikda complex, which utilise the incremental export capacity of also accommodates existing liquefaction more than 30 bcm per year (the two LNG trains, offers some cost savings in relation plants and two new pipelines [Medgaz and to marine infrastructure, pipelines and the Galsi], as well as the Transmed expansion), upstream components, highlighting the signifi cant enhancement of upstream price infl ation in LNG liquefaction plant at gas production as well as modernising that time. domestic pipeline infrastructure will be essential, given the fact that domestic gas The only FID on an LNG liquefaction project demand is also growing strongly. in the world in 2008 was on Algeria’s other project, a liquefaction train at Arzew for gas from Gassi Touil. The EPC contact for the 6.5 bcm (4.7 Mtpa) train was awarded to a consortium of Snamprogetti and Chiyoda in July 2008, after Sonatrach cancelled its earlier award of an earlier EPC contract to Petrofac and IKPT5. Like the Skikda replacement train, the project is now targeted for 2013.

In March 2008, Sonatrach agreed with StatoilHydro to supply 3 bcm per year of LNG from 2009 to the Norwegian company’s capacity at the Cove Point LNG terminal in the United States. This is in line with the Sonatrach’s plan to expand gas sales to the United States. The company also has access to terminal capacities in the United Kingdom, France, and Spain6 .

There are some challenges to meet Algeria’s export target of 100 bcm per year by 2015. In addition to the LNG project delays, ageing domestic pipelines are another uncertain factor. In 2008, a declaration of force majeure of some LNG shipments

5. The combo had no experience in leading any LNG liquefaction projects and the industry observers doubted the viability of their undertaking. 6. Isle of Grain in the United Kingdom, Montoir in France and Mugardos (El Ferrol) in Spain. 2009 OECD/IEA, © © OECD/IEA, 2009 Natural Gas Market Review 2009 • Market developments 109

MARKET DEVELOPMENTS

Gas for power The steadily increasing use of gas in power generation has resulted in a „ Gas-fi red power has grown rapidly, greater inter-dependence of the gas especially in OECD countries, where it and electricity markets. Used mainly to has provided four-fi fths of incremental satisfy intermediate and peak load, gas- power since 2000, and is now the fi red generation is often the marginal second most important source of source of electricity supply. As a result, power. Gas and electricity markets are electricity prices are largely infl uenced now increasingly interconnected. by those of natural gas. At the same time, power generation is becoming the fastest „ In the short term, in the current growing sector of gas demand. So spot recessionary environment, gas-fi red gas prices are likely to be increasingly power, with shorter lead times and infl uenced by electricity markets. As lower capital cost, may well remain the the linkage between these two markets favoured choice in OECD countries. increases, reliability and operational issues in one can exacerbate the effects „ Growing shares of intermittent on supply and demand in the other. renewable power, especially wind, seem likely to increase the demand for Figure 16 shows the steady upward trend gas-fi red power, backing out higher in gas used in power in the OECD regions carbon options, notably coal. since 2000 despite a slow-down in 2008. Gas accounted for more than three-quarters of new electricity demand. During this Gas: fuel of choice? period, 288 GW of gas-fi red plants came on line compared to 44 GW for coal and 59 The power sector has been the main driver GW for wind. for incremental gas demand in the OECD in recent years and is expected to remain so However, the global recession had a well into the coming decade. Natural gas negative impact on the power sector now accounts for 20% of global electricity in 2008, in particular on electricity production, second after coal at 41%. demand. Based on preliminary estimates, generation in the OECD declined by 0.1% In 2008, 2343 TWh were generated by gas- in 2008, in particular during the second half fi red plants in OECD countries, slightly up of the year. While the output from gas- from 2 307 TWh in 2007; it represented fi red plants slightly increased, electricity 21% of total electricity generated against generated by coal-fi red plants, oil-fi red 37% for coal. In 2007, gas overtook nuclear plants and other renewables declined. as the second largest source of power. Hydroelectric generation increased by 3% Wind represented 2% of total generation. while generation from wind power plants Russia, the Middle East plus Egypt account increased by 23% refl ecting the addition for more than half non-OECD gas-fi red of new capacity. Lower electricity demand power output. has adversely affected gas demand by utilities. In many European countries, 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 110

Figure 16 Changes in power generation by fuel source in OECD

250

TWh 200

150

100

50

0

-50

-100

-150 2000 2001 2002 2003 2004 2005 2006 2007 2008E Coal Oil Gas Nuclear Hydro Wind Other Renewables

Key point: Gas has been the fuel of choice in 21st century but 2008 sees major changes

Source: IEA. gas demand has been affected by higher The EIA reported 188.5 bcm (6 654 bcf) of short-run marginal costs for gas-fi red gas used for power in 2008, a decline of plants compared to coal-fi red plants 5.3 bcm or 2.8% compared to the previous during the second half of 2008 and early year. Electricity generated by gas-fi red 2009. Furthermore CO2 prices collapsed plants declined over the second half of (high CO2 prices favour gas over coal), the year, but this was a consequence of a weakening the competitive position of cooler summer than in 2007. Meanwhile, gas further. However, spot gas prices have electricity generated by coal plants fallen much faster in the United States declined by 1%. Electricity generation in and the United Kingdom, putting gas in the United States is expected to show a better competitive position relative to slightly negative growth in 2009 and more coal. destruction in gas or in electricity demand may continue in the remainder of 2009. Regional analysis First quarter power demand fell around 4%; gas-fi red power declined by more than Electricity generation in the United States double that fi gure. The US Department of declined by 1% during 2008, but this Energy (DOE) projects a decline in total is deceptive as it fell by 3% during the electricity consumption of 1.7% this year second half of the year according to the followed by an increase of 1.2% in 2010 Energy Information Administration (EIA). as a slowly improving economic climate 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 111

contributes to a recovery in the sales of a much stronger factor in determining electricity. electricity generation than are weather deviations or relative fuel prices. Utility In Europe, electricity generation has been LNG consumption fell 12% between falling at unprecedented speed, negatively January and February or 18% down from affecting gas demand by utilities. In the last February. United Kingdom, electricity consumption declined by 3% over the last months of The relationship between power output 2008 and early 2009 on the back of falling and overall economic growth is even industrial demand (-6%). National Grid stronger in emerging markets than in the expects this trend to continue and the OECD countries. Since 2002, China alone recession to impact through the summer generated almost half of the electricity period (April-September) with demand on demand growth in emerging markets, average reduced by 1.1 GW. In 2008, Spanish expanding output at a phenomenal power generators’ demand for gas rose double-digit rate per annum. In China, by 30%. It was strong as combined-cycle electricity output contracted at a 9% gas generators stepped up production to annual rate in November, as industrial offset the impact of persistent drought in users of energy, ranging from steel to auto early 2008. Slow utility demand coupled to petrochemical producers continued to with a jump in hydroelectric generation cut planned production. Indian electricity and relatively high gas prices have generation was also recently reported fl at contributed to weakening power sector year-on-year, the lowest increase in three demand for gas in 2009. Enagas reported years, while power output was also hard that the demand for gas in Spain fell by hit in Singapore and Taiwan. While many 30% during the fi rst quarter 2009. In of these markets are largely coal powered, particular, February 2009 recorded a 215% other signifi cant gas users also saw falling increase in hydroelectric generation and power output, notably Russia, where gas a substantial increase in generation from accounts for nearly half power output of wind, both obviously due to favourable 1 000 TWh. weather. Short to medium-term outlook Japan has also seen a large fall in power demand, led by an unprecedented drop in Overall, we expect a decline of gas industrial production, which is reported demand in the power generation sector to have declined by 15-20% in late 2008 in early 2009 due to the overall decline of and by over 30% during the fi rst months electricity demand in most countries. The of 20091. Electricity sales by the ten main decline will be accentuated in countries utilities in February 2009 declined by where gas prices are linked to oil prices 16% on the same month a year earlier to and remain high during the fi rst half of 75 TWh. As in Europe, the industrial sector 2009. However, as gas prices are expected

1. METI, Indices for industrial production, production and shipments. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 112

Figure 17 OECD capacity expansion

350

GW 300

250

200

150

100

50

0 1990-99 2000-08 2008-17 2008-20 Existing Under construction Planned Wind REN Nuclear Hydro Oil Gas Coal

Key point: Gas still the option of choice

Source: Platts. to converge to lower levels during the end electricity generating capacity is under of 2009, gas-fi red plants will be in a better construction in OECD countries, with gas position to compete against coal-fi red representing over 50 GW and coal around plants even if coal prices remain at around 40 GW. This compares to around 600 GW USD 60 per tonne. Gas-fi red generation has under construction worldwide, expected a substantially higher fuel cost component to start operations by 2015. Globally, than nuclear or coal. Its cost is therefore gas only comes third behind coal (around more sensitive to fuel cost variations than 215 GW) and hydro (160 GW). China and the other generation options. The declines India alone represent around two-thirds in all gas prices expected in 2009 will of new coal capacity and more than half of improve the competitiveness of gas-fi red the new hydro capacity. generation, taking into account the higher effi ciency of combined cycle gas turbines In OECD countries, gas-fi red capacity is (CCGTs) (55%) relative to coal-fi red power expected to continue to account for the plants (40-42% and often less). bulk of capacity additions in the coming decade. Many factors play in favour of gas- In the medium term however, natural gas fi red investments, including the lower up- demand for power generation is expected front investments, shorter construction to increase both in OECD and non- lead times, more fl exible operation and OECD countries. Around 150 GW of new lower greenhouse gas (GHG) emissions 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 113

compared to the coal option. Furthermore, impact on coal-fi red generation will vary gas is valued for its fl exibility, and is depending on specifi cs of the regional expected to be the fuel of choice for power markets. Under many scenarios, the generation over the next decade due to relative share of coal-fi red generation in the much lower lead times of alternative the power mix will likely diminish due to sources, except some renewables. Current the retirement of existing units and/or diffi culties in fi nancial markets seem likely the development of fewer new units. This to favour new gas build, or at the very could change in the longer term when, and least, increase gas-fi red plant load factors. if, coal with carbon capture and storage (CCS) becomes competitive. Over the past decade, natural gas has been competing fi ercely with coal A resurgence of nuclear power will meet and has been the fastest growing fuel some of the supply requirements as source in the Europe. This refl ects in around 14 GW of nuclear capacity are part tightening in CO2 regulations and under construction in OECD countries. strong public opposition to coal-fi red Nuclear energy has been recognised capacity. Public attitudes may be a key by the European Commission as a way barrier to generation investment. In the to curb CO2 emissions but the decision United States, a strong anti-coal attitude to build new plants has been left to has resulted in signifi cant delays and Member countries. However, there is cancellations of about half of coal-fi red great uncertainty about the timing of projects (noting of course that half of US new nuclear reactors, in part refl ecting power is coal-fi red). In Canada, there is a challenges in their fi nancing. Nevertheless, policy commitment in Ontario to phase- public opinion has eased somewhat in out coal-fi red power plants. The patterns recent years and several utilities are now of investment in the coming decade will poised to submit applications to build depend on climate change and renewable new nuclear generating plants. Among energy policies. the most advanced projects are the plants under construction at Olkiluoto in Finland While in Europe the Emission Trading and Flamanville in France expected to Scheme (ETS) provides transparent come on line in 2012-13. Other plants signals for carbon prices, in other OECD under construction are located in Japan, jurisdictions, any new policies intended to Korea and the United States. Only two new curb GHG emissions will increase the total reactors were started in the OECD in 2008 costs of fossil fuel for power generation and the fi rst half of 2009, both in Korea. through additional costs associated with cap-and-trade and/or carbon tax. This will Flexibility challenges in the power likely alter the mix of new power plants sector and increase the demand for natural gas. Coal-fi red generation, which produces Gas-fi red generation could become the about twice the CO2 per MWh as gas-fi red swing resource utilised to provide fl exibility generation, is the most affected by the in power systems with large shares of cap-and-trade and carbon tax plans. The intermittent renewable generation. Gas- 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 114

fi red capacity will increase while its overall or 11% of total electricity generation; load factor may be reduced in favour of this impacted on the utilisation rate of renewable resources when available. This gas-fi red plants which declined to 18% switching will have an impact on the – or a demand of 15 Mcm per day. Such profi tability of new investments. fl uctuations require heavy investments in gas storage, particularly of the type needed Over the last fi ve years, wind power capacity to respond quickly to large gas demand in the OECD has increased by an average of movements from power generators. Spain 8 GW per year – much more in 2007 and has recently set a new record for wind 2008. Output doubled between 2005 and power generation with more than 40% of 2008. Wind output is highly variable and the country’s energy needs being covered unpredictable, therefore wind turbines by wind turbines during periods of a few generally need backup power from hydro hours. On a cumulative basis, wind energy or fossil fuels to keep the electricity grid in met 11.5% of demand up to April 2009, balance. Gas turbines are able to respond with production up by a third on last year. quickly to provide the needed generation, Renewable energy provided 31% of total and can be turned on and off quickly. electricity supply in Spain in February, They also have relatively low capital cost, partly due to heavy rainfall that enabled making them a preferred choice to provide increased hydroelectric production. back-up capacity. Thus, as wind power capacity increases, the demand for gas- As wind generation increases in Europe, fi red capacity also tends to increase. there needs to be in the long term suffi cient available capacity that is fl exible enough Spain provides a good example of the to respond at all times to cover reliably interactions between wind-based and gas- such variations in output (as well as to fi red generation. By the end of 2008, Spain digest surpluses). If this fl exible response is had 21 GW of wind powered capacity, provided by gas, as it is in Spain, then that producing about 9% of the country’s increases the importance of storage and total power supplies. Most of these secure gas fl ows. Large shares of wind power wind generators are located in scarcely are likely to encourage more investment in populated areas, while major load centres fl exible capacity (such as gas) than in other are in urban areas, with high air-conditioner thermal plants such as coal or nuclear, loads. Peak summer loads coincide with because those plants will no longer have periods when there usually isn’t much the full load hours they could once have wind, while the opposite happens during counted upon. Other methods of fl exible winter meaning large differences in terms response are available, being other types of gas-fi red plant load: on 20 June 2008, of fl exible generation (pumped storage but Spain broke a record in terms of peak daily new hydro developments are very limited gas demand from the power sector with in OECD countries), increased transmission 64 Mcm per day representing an utilisation interconnection, and demand side response rate of 75% compared with 22 GWh (which remains a much discussed but much per day for wind. On 20 December 2008, underutilised approach). It is likely that the however, wind plants produced 67 GWh 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 115

gas system will be required to provide this In North America, data transparency is fl exibility and reliability. quite advanced. Data on stocks are given by week by the Energy Information Administration (EIA) as well as monthly Towards greater transparency import and consumption data. The market is also well supplied with price „ There have been improvements on gas data by time and location, plus fl ows and data transparency in Europe, both on pipeline capacities. In Europe however, pipeline fl ows and storage levels. there have been gaps in terms of data on transport by pipeline and storage stocks. „ However, there remains much missing Under the pressure of the European data in particular in Eastern Europe, as Commission (EC) and national regulators, well as a lack of harmonisation between transmission systems operators (TSO) the different transmission system and storage system operators (SSO) have operators (TSOs). started publishing data. Improved data is a key element to improve trading, „ Lack of this data undermines Europe’s but also in case of disruption, it allows a security of gas supply, in the short better overview of fl ows and stocks and is term, as it impedes the ability of the therefore critical in order to get available market to move gas to where it may be gas volumes where they are needed. needed and in the longer term through weakening essential market signals. Pipeline fl ows

At the 5th meeting of the Madrid Forum In order to have a well-functioning gas on February 2002, the Guidelines of Good market as well as increase gas security, Practice (GPP) were agreed, marking the transparency of information is critical (see start of the process aiming to improve “Development of Competitive Gas trading transparency of gas data in Europe. In line in Continental Europe” IEA 2008). Timely with these aims, the European Regulators and adequate price and other signals are Group for Electricity and Gas (ERGEG) essential if the investment on which long- launched its Electricity and Gas Regional term security of supply depends is to occur Initiatives (ERI and GRI) in spring 2006. in the right place, time and is of the right These two initiatives were created to speed type. Such investments need to cover up the integration process of the different upstream gas development, long-distance national energy markets. Subsequently pipelines, LNG regasifi cation terminals, and the GRI created three regional gas markets storage, including a variety of drawdown in Europe (North-West, South South-East rates, sensitive to market needs. and South) as an interim step to create a single EU gas market. The regional areas have different priorities depending on 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 116

how advanced liberalisation is. However Since the start of the project signifi cant the improvement of transparency is a progress has been made: data for priority in all three. 133 interconnection points was provided as of September 2008. However, though most In the DG2 Competition’s energy sector TSOs provide information on at least the inquiry published in 2007, the absence historic gas fl ows and the daily aggregated of suffi cient and timely information was fl ows on a D-1 basis, further improvement highlighted as one of the most serious is needed. Indeed there are signifi cant shortcomings in the functioning of the variations in quality, completeness and internal market. This was also seen as a timeliness between TSOs. Now, seven major stumbling block for the entry of years after the start of the improvement new market players (especially in countries process, it is still impossible to get an where the TSO is part of a vertically overview of the gas fl ows in large parts of integrated company). In December 2007 Europe due to different data formats of as a reaction to these fi ndings, the TSOs reporting, the application of the 3-shipper in the GRI North-West, in consultation rule (that suppresses data where there with consumer groups, committed are too few shippers to protect company themselves to the implementation of the confi dential data), but mostly due to the TSO Transmission Transparency project. absence of data from many transmission The goal of this project is to publish operators (especially in Eastern Europe). information on capacity availability and gas fl ows at cross-border points in the In November 2008, frustration with this North-West gas region. With regard to gas slow progress resulted in the launch of fl ows the 16 TSOs3 committed to publish a list of Minimum Requirements at the information on: 15th Madrid Forum by network users, comprising industry groups such as EFET, „ Daily fl ows and interruptions Eurogas, Eurelectric, OGP, GEODE, CEDEC and (later) IFIEC. These parties also asked the „ Daily prompt allocations EC to make these requirements binding. In response to this initiative GTE organised a „ Daily aggregate day-ahead workshop on 29 March 2009 to work on this nominations request. However GTE members argued that they should be allowed to recover „ Historic gas fl ows their associated costs. Concentrating particularly on gas fl ows, the following six The fi nal deadline for implementation improvements seem attainable: for the project was December 2008. Of course this initiative did not limit TSOs Aggregation of publication: gas markets from publishing additional information. are increasingly diffi cult to examine

2. European Commission Directorate General for Competition 3. Swedegas, Gaslink, National Grid, Interconnector, Energinet, GTS, Fluxys, DEP, Gasunie Deutschland, E.ON Gastransport, RWE Transgas, Wingas Transport, Ontras, GdF Transport, GRT Gaz and BBL. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 117

Table 16 Data published by Transmission Systems Operators

Transmission Historic Real-time Country D-1 gas flows D+1 gas flows operator gas flows gas flows

Belgium Fluxys 3338 Denmark Energinet.dk 338 3 Germany E.ON Gastransport 3338 Ireland Gaslink 3338 Gas Transport Services Netherlands (GTS) 3333 Spain Enagas 3338 France GRT Gaz 3388 France TIGF 3388 Germany RWE Transportnetz Gas 3338 Gasunie Deutschland Germany (GUD) 3388 Italy Snam Rete Gas 3388 United Kingdom National Grid (NG) 338 3 Austria OMV Gas GmbH 3 888 Austria WAG 3 888 Austria TAG 3 888 Germany GdF DT 3 888 Bosnia BH-Gas Herzegovina 8888 Bulgaria Bulgargaz 8888 Croatia Plinacro 8888 Czech Republic RWE Transgas Net 8888 Finland Gasum 8888 Germany Wingas 8888 Germany Ontras 8888 Germany GVS/ENI 8888 Greece Desfa 8888 FGSZ Natural Gas Hungary Transmission 8888 Luxembourg SOTEG 8888 Norway Gassco 8888 Poland GAZ-SYSTEM S.A. 8888 Poland EuRoPol GAZ 8888 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 118

Table 16 Data published by Transmission Systems Operators (continued)

Transmission Historic Real-time Country D-1 gas flows D+1 gas flows operator gas flows gas flows

Portugal REN Gasodutos 8888 Romania Transgaz 8888 Serbia Srbijagas 8888 Slovakia Eustream 8888 Slovenia Geoplin plinovodi 8888 Sweden Swedegas 8888 Switzerland Swissgas 8888 Turkey BOTAû 8888 Source: TSOs. Note: In May 2009 some of the GTE members started uploading data on the transparency platform of GTE. individually. However the data publication domestic production. The Netherlands and on cross-border fl ows, which by defi nition Germany do not publish such fl ow data. are supranational, is left to individual TSOs. This seems an obvious argument for Inclusion of all European countries an overarching international approach for (especially Eastern Europe): while there publication. Such an approach also has the is still a lot of improvement needed in benefi t of preventing, double-counting, Western Europe, Eastern Europe is lagging and of reconciling often confl icting fl ow even further behind. In most of these formats or even data4. countries, the provision of information is very poor. The Russia-Ukraine gas dispute Harmonisation of data formats: the highlighted the importance of an adequate bottom-up approach of the project overview of gas fl ows. Timely availability of resulted in different reporting units and this data would allow market participants frequency. Unlike storage, there is no to make better and more effi cient European entity or TSO group publishing decisions on the allocation of their gas in all the available information on gas fl ows the event of further emergencies, and to in a consistent data format. invest more effectively and effi ciently.

Inclusion of domestic production entry Solution for the 3-shipper rule: currently in points: despite the fact that domestic the GRI North-West Transparency project, European production is declining, it still 29 out of the 133 interconnection points represents a substantial share of the are subject to the 3-shipper rule. This means supply mix. Not every country currently that no fl ow information is published on publishes fl ows on the entry points for roughly a quarter of the interconnection

4. Currently bordering TSOs both publish data on the same border points. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 119

points. If Eastern European countries were At the end of 2006, Gas Storage Europe to start publishing data, this number would (GSE) – a grouping of European SSOs – probably rise due to the heavy dependence announced that they would publish on a on one supplier. Taking into account the weekly basis storage levels for selected commercial interest of shippers, a more regions. The aggregated storage inventory satisfactory solution is needed. started early January 2007 with four geographical zones. Since October 2007, Real-time information: Following the these regions have been linked to existing example of National Grid (NG) of the hubs or major trading points: United Kingdom, the fi rst TSO publishing near real-time fl ow information, Gas „ NBP + Zeebrugge: facilities in Belgium Transport Services of the Netherlands and some in the United Kingdom6 also started publishing such information. Though on an aggregated level and „ TTF: some facilities in the Netherlands therefore less detailed than NG it enables and Denmark market players to base their actions on the actual situation. Such initiatives should „ Baumgarten: some facilities in Austria, improve the timeliness and effectiveness the Czech republic, Hungary and of market participants balancing demand Slovakia and supply. „ PEG: facilities in Northern France Storage levels „ Germany: some facilities in Germany The second EU Gas Directive required storage operators to provide suffi cient „ PSV: facilities in Italy (excluding information for effi cient and secure access strategic storage) to storage facilities5 while the Guidelines for Good Practice for System Storage „ Iberia: facilities in Iberia and Southern Operators (GGPSSO) provided guidance on France the information to be published. However, in December 2006, an ERGEG monitoring Data on stock levels at the beginning report highlighted the shortcomings of each calendar week for each of the of this implementation. Information on different regions are usually available at storage capacity booked and available as the end of the week. well as easy access to storage tariffs and conditions is essential as well as historical Despite the obvious progress that this operational data. One major issue for SSO transparency initiative represents, total was confi dentiality, which allows them to working capacity covered by GSE amounts publish no information if there are fewer to 53 bcm compared to 82 bcm in Europe than three users. (including Turkey). Some countries

5. Article 8 of the second gas directive.

6. NBP and Zeebrugge are separated since 25 May 2009. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 120

Map 9 Gas Storage Europe storage data coverage

GIE member NBP and ZEE TTF (Eurohub) PEG PSV Germany Brumgarten Iberian

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: GSE, http://transparency.gie.eu.com.

especially in Eastern Europe (Poland, have started publishing data on their own Romania, Bulgaria) are not covered and websites. Again, data available is mainly there are still missing data within the in Western Europe. The quality of the regions covered as these regions do not data in terms of frequency and lag time include all storage operators. In particular between the day of the operation and the Germany covers around 60% of the publication of the data varies considerably working capacity (90% since 25 May 2009), from one operator or country to another. while in Baumgarten, half of the Austrian In Austria and the Czech Republic, data are capacity is not covered and Italy does not gathered by the regulator or the Ministry include around 5 bcm of strategic storage. which allows a complete coverage of the Furthermore the capacity increases facilities but at the expense of a certain that occur when new operators join the delay in the publication. Furthermore, network or new facilities come on line are some operators do not keep historical diffi cult to track. data while the net injection/withdrawals are sometimes published instead of the In parallel, most of the SSOs participating absolute levels. to the aggregated storage inventory 2009 OECD/IEA, © Natural Gas Market Review 2009 • Market developments 121

Table 17 Data published by Storage Systems Operators

Country Entity Frequency Lag time Comments

Austria E-control Monthly 2 months Covers all facilities Belgium Fluxys Weekly 1 week

Czech Republic Ministry6 Monthly 1 month Covers all facilities; only net injection/withdrawal* Denmark DONG Daily Days No data from Energinet.dk Daily details disappear two weeks after, weekly Storengy Daily Days France available TIGF Weekly 3 days Germany Ministry Monthly 2 months Net injection/withdrawal Hungary E.ON Földgaz Weekly 2 weeks Disappears the week after Disappears the week after, daily data available Italy Stogit Weekly 2 days after several months Pozagas Weekly 1 week Disappears the week after Slovakia Nafta Weekly 1 week Disappears the week after Spain Enagas Daily Days United Kingdom NG Daily Days

Source: SSOs.

7. RWE Transgas publishes daily data on its storage facilities but they do not represent the total capacity. 2009 OECD/IEA, © © OECD/IEA, 2009 Natural Gas Market Review 2009 • Non-OECD countries and regions 123

NON-OECD COUNTRIES AND REGIONS

Non-OECD countries represent just under China’s natural gas market has been half of global gas use, but account for 63% expanding rapidly in recent years, of global gas output. The following section particularly after the completion at the provides an overview of selected non- end of 2004 of the West-East Pipeline, OECD consumers and producers. Note that which transports gas produced in the Russia, the largest producer and second western part of China to eastern cities. largest consumer, is discussed in the In 2007, China’s natural gas consumption Investment section; Qatar developments grew by 23.8% and attained 69.5 bcm, can be found in the Investment and LNG making China one of the world’s top sections. 10 gas consuming countries. Despite the rapid increase in consumption, the share of natural gas in China’s energy mix is China still 3.5%, while coal dominates with nearly three quarters of energy supply. In „ Chinese gas use at near 80 bcm in 2008 particular, gas-fi red power makes up only is the third highest amongst non-OECD 1% of the power mix, almost exclusively countries. However, this represents in the South, including Hong Kong. In order less than 4% of Chinese total energy to promote the use of this “clean energy” supply, which is dominated by coal. as a substitute fuel for oil and coal, the government aims at expanding the share „ China has ambitious plans to double of natural gas up to 10% by 2020, and domestic gas production to 160 bcm by has enhanced the development of the 2015, and has in place agreements to domestic gas market. The government has import a minimum of 24 bcm of LNG by maintained a “cost-plus” based domestic 2011. price regime until now in order to promote gas use, resulting in relatively cheap prices „ In addition, China will import up to compared to international levels. This 40 bcm of Turkmen gas by pipeline price regime was sustained by controlled starting early in the next decade, prices for domestic gas output, plus a marking the fi rst physical link between very cheap LNG import contract (around East Asian and Eurasian gas markets. USD 3 per MBtu) which started in 2006. Other pipeline imports may be sourced However, this regime is now being from Kazakhstan and Myanmar. challenged by the signifi cant increase in higher priced gas imports in the near „ Even with these large supply additions, future. gas will remain a small part of China’s energy supply. Consumption

„ Price reform will be an important The growing urbanization, the expansion of policy development, to ensure rational industrial use, including the petrochemical and effi cient use and supply of gas in industry and the power sector, have been China. the driving forces behind the recent high- paced increase in demand. Moreover, high 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 124

oil prices until mid-2008 made residential demand, which may have a positive effect and industrial consumers switch to gas on the natural gas market’s growth. as it was much cheaper than oil and LPG in China at that time. The differential Domestic production between domestic prices of natural gas and international prices of alternative China’s natural gas production grew by an fuels caused several perverse situations annual average rate of 15% from 2000 to in the country such as overproduction in 2007, amounting to 69.5 bcm in 2007, and some petrochemical plants using cheap it is estimated to have reached 79.3 bcm gas. On the other hand, many gas-fi red in 2008. China National Petroleum power plants were idle, faced with supply Corporation (CNPC) forecasts incorporate shortages of natural gas due to demand an aggressive production outlook, growth in other sectors. Confronted with foreseeing that China can maintain the these situations, the government issued a current high pace of increase in natural new priority sector policy in August 2007, gas production, attaining 160-170 bcm which categorised city residential use and by 2020. In January 2009, the Ministry combined systems for heat and power of Land and Resources announced a more as being the fi rst priority and restricted ambitious target of 160 bcm by 2015. As industrial use. In November 2007, the far as domestic gas reserves are concerned, government decided on a sharp increase China’s latest national investigation in in natural gas prices. 2005 identifi ed prospective resources amounting to 56 tcm while its recoverable Since late 2008, in common with most resources were estimated to be 22 tcm. In markets, natural gas consumption growth 2008, CNPC announced that China’s total slowed sharply, showing the effect proven reserves amounted to 5.94 tcm. of the global economic recession, but More recently, in December 2008, CNPC similar to the Chinese economy, still kept announced the discovery of the large-scale steady growth. According to provisional gas fi eld called Klameli in the Junggar Basin, estimates, in 2008, China’s natural gas in Xinjiang, with confi rmed reserves of consumption grew by 11.8% to 77.7 bcm. 100 bcm. In addition to this conventional China’s monthly merchandise exports gas, the potential of coalbed methane is have been decreasing since November estimated at 37 tcm of geological resources 2008 in comparison to that for the and 134.3 bcm of proven reserves. previous year, and recorded a staggering fall of 25.7% in February 2009. In January LNG imports 2009, the government announced a large-scale two-year “stimulus plan” The fi rst LNG receiving terminal in amounting to CNY 4 trillion (USD 580 billion) Guangdong opened in June 2006. In 2008, in order to stimulate the economy and to this terminal received a total of 4 bcm maintain annual GDP growth above 8%. of LNG based on the long-term contract Although the precise measures are still not with Australian North West Shelf (NWS) clear, public investment in infrastructure project. Faced with the strong demand in may be a pillar to expand domestic the Guangdong region in 2007 and 2008, 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 125

China National Offshore Oil Corporation to import LNG from Gorgon or Browse (CNOOC) procured additional spot LNG projects in Australia. The price formula from Oman, Algeria, Nigeria, Egypt and is said to be close to “oil parity”, due to Equatorial Guinea despite high prices at LNG market conditions at that time. In that time (USD 8.2-20.6 per MBtu). November 2008, CNPC signed another The second LNG terminal in Fujian was SPA with Shell: LNG may be supplied completed in 2008, and the fi rst commercial by Australia’s Gorgon project and cargo from Indonesia’s Tangguh project supplemented by additional LNG volumes is expected to be delivered mid-2009. from Shell’s portfolio. On the other hand, The start of the third terminal in Shanghai CNOOC signed two more SPAs in 2008, was delayed, and is expected to occur one with the QatarGas II project and later in 2009 or even 2010, with LNG another with Total, probably intending supplies coming from Malaysia’s Tiga to meet the increase in demand by the project. Two additional terminals are now expansion of the Guangdong terminal under construction in Jiangsu and Dalian and the start of another new terminal. As initiated by CNPC and both of them are a result of these procurement activities expected to open by 2011. In 2008, CNPC of LNG by CNOOC, CNPC and Sinopec, signed a sale and purchase agreement the total contracted volume on a long- (SPA) with the seller of the Qatargas term basis now totals around 33 bcm per IV project, although it initially planned annum1.

Table 18 Existing long-term LNG sales and purchase agreements

Volume Term Signing Destination terminal Buyer Supply source First cargo (bcm per year) (years) date /capacity (bcm) North West Shelf, 4.5 25 December 2004 Guangdong (5.0) June 2006 Australia Tangguh, Indonesia 3.5 25 September 2006 Fujian (3.5) 2009 CNOOC Malaysia LNG Tiga 4.1 25 July 2006 Shanghai (4.1) 4Q 2009 Qatargas III 2.7 25 June 2008 4Q 2009 Total 1.4 15 January 2009 2010 Queensland Curtis 5 20 May 2009 2014 LNG, Australia Qatargas IV 4.1 25 April 2008 Jiangsu (4.8) 2011 CNPC Shell 2.7 20 November 2008 Dalian (4.1) 2011 ExxonMobil 2,7 20 Pending Sinopec PNG LNG 2,7 Pending 2014

Source: Company information, media reports.

1. In addition to these confi rmed volumes, other non-confi rmed agreements have been reported, such as the non-binding agreement between CNPC and Woodside (Browse, 2.0-3.0 Mtpa), the Head of Agreement between CNPC and Iran (South Pars, 2.0 Mtpa), and the Memorandum of Understanding between Sinopec and Iran (South Pars, 10 Mtpa). 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 126

Pipeline gas imports creates for the fi rst time a pipeline link between the Chinese market and the Despite the many years of discussions European and Russian markets, and between Russia and China on building establishes Turkmenistan as an important a gas pipeline, no real progress has been pivot between western and eastern observed until now. China changed its Eurasia. strategy to focus on Central Asia, and succeeded in securing a commitment to CNPC is also actively exploring Aktyubinsk gas supply from Turkmenistan. In July and Urikhtau in Kazakhstan, and the Aral 2007, CNPC and Turkmenistan signed Sea in Uzbekistan. In November 2008, CNPC two agreements; a production sharing and Kazmunaigaz signed a comprehensive agreement (PSA) for development of gas agreement for co-operation on natural reserves on the right bank of the Amu gas development, including another gas Darya River in eastern Turkmenistan, and a pipeline construction originating from 30-year SPA for 30 bcm per year of natural Beineu in western Kazakhstan that will gas. In August 2008, both parties agreed connect to the Turkmenistan-China in principle to increase the sales volumes Pipeline. However, there is little scope in on the SPA to 40 bcm as offered by the the short term for either Uzbekistan or Turkmen President Berdymukhammedov. Kazakhstan to send signifi cant volumes to China. Additional pipeline gas imports To transport this gas back to the are being planned from Myanmar to the domestic market, China planned the southern part of China. In December Central Asia-China Pipeline via Uzbekistan 2008, China and Myanmar signed an SPA and Kazakhstan, and rapidly obtained for 10 bcm per year of natural gas with a confi rmation from these two transit planned 1 000 km pipeline. countries of their co-operation for the pipeline. This cross-border pipeline will run Infrastructure development around 2 000 km to the Chinese border, where it will connect to the second The second West-East pipeline was West-East pipeline. Construction of the launched in February 2008, in order to Turkmenistan-China pipeline began in transport natural gas from Turkmenistan. 2007 and the fi rst phase with a capacity It will be built in two phases: the fi rst phase of 20 bcm per year is expected to be is the western link from the border with completed in 2010. Kazakhstan to Gansu, to be completed by the end of 2009. The second phase is the Around 13 bcm per year for this pipeline eastern leg, linking to markets in Shanghai, is foreseen to come from the Bagtyiarlyk Guangdong and Hong Kong by 2012. Thus, gas fi eld, which CNPC is developing in the second West-East Pipeline will meet Turkmenistan based on the PSA; the expanding demand in two major economic remaining portion should be provided by zones in the coastal area, i.e. the Yangtze Turkmengaz from the Malay and Uchaji River Delta and the Pearl River Delta. The fi elds. The parties have reportedly agreed total length of the main trunk line is an oil-based pricing formula. This project 4 843 km, and the transport capacity will 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 127

be 30 bcm per year. Three underground Towards price reform storages are planned to be built alongside the pipeline, which will have 2.5 bcm of total Natural gas prices have been under working gas capacity. CNPC announced a government control in China. The total investment cost of CNY 142 billion current price regime is composed of (USD 20 billion). Sinopec is planning to three elements; (i) ex-plant price, (ii) build two other inter-provincial pipelines, transportation tariff, and (iii) end-user originating in Sichuan, to the Yangtze price. (i) and (ii) are set by the central River Delta area (the Sichuan-East Pipeline) government principally based on the costs and to the Pearl River Delta (the Sichuan- of production and transportation plus the South Pipeline). Additional LNG terminals appropriate margin. (iii) is determined are approved or under planning in many by each provincial government based regions such as Zhejiang, Qingdao, Zhuhai, on distribution costs and the prices of Shenzhen, Caofeidian, and Hainan. alternative fuels. However, this regime contains a number of structural fl aws, in particular concerning balancing the seasonal, regional and inter-sectoral

Map 10 Chinese gas infrastructure

Astana RUSSIA RUSSIA

KAZAKHSTAN Ulan Bator MONGOLIA

We Bishkek st-Eastp KYRGYZSTAN West-East pipelinipelin Tashkent eII Tangshan Tarim basin Ordos basin Beijing Dushanbe P’yongyang TAJIKISTAN Dalia n Qaidam basin eI Seoul AFGHANISTAN Qingdao Tokyo Islamabad Kabul Rudong

CHINA Shanghai PAKISTAN INDIA NEPAL Ningbo Delhi BHUTAN Kathmandu Thimphu Existing gas pipeline Fujian Under construction gas pipeline Dhaka Dachan Bay Planned gas pipeline Hong Kong BANG. Existing underground storage Guangdong Dapeng MYANMAR Under construction Hanoi Zhuhai LNG import facility LAOS Vientiane Planned LNG import facility Major gas field Yangon THAILAND VIETNAM 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: Petroleum Economist, IEA, media reports. 2009 OECD/IEA, ©

123-146 chapitre 5 NGMR_2009.ind127 127 17/06/09 14:34:39 Natural Gas Market Review 2009 • Non-OECD countries and regions 128

gap of demand and supply. Gas infl ows India from multiple fi elds to the same pipeline distributing to multiple users are causing „ As in China, gas plays a small part in diffi culties in identifying the gas source India’s energy needs, barely 5% of and the original cost. Moreover, the total primary energy supply. increase in imported natural gas with higher prices seems to have pushed the „ But demand has been growing rapidly, Chinese government towards reform of despite being constrained by a lack of the natural gas price regime. The policy gas availability. paper issued in 2007 was a step in that direction. The LNG price level in recent „ Gas supplies look set to rise sharply in SPAs is likely to be close to “oil parity”, the next few years, with a near doubling which may be double or triple current of domestic output, and an increase in domestic wholesale prices of natural gas LNG import terminal capacity from in China. Turkmen gas could be expensive 13 bcm in 2007 to 30 bcm by end-2009, as well for users in eastern coastal cities potentially opening the way to a near in China, which have to pay transportation doubling of gas use in India in the short tariffs for the long distance of the second term. West-East Pipeline. Fortunately for China, the international gas price has been falling „ Pipeline imports seem unlikely before since late 2008. 2015.

Despite all the negative impacts of the world economic crisis, it has also brought Like China, India gas consumption several positive factors for the evolution remains relatively modest compared to of the market. Falling international gas its population. Primary energy demand is prices and less concern over infl ation in still largely dominated by coal (over 50%) China have provided the opportunity for but gas demand has the potential to price reform in China. The revaluation grow substantially over the next decade. of the Yuan, which appreciated 15% Since 2003, gas use has increased by more against the US dollar from 2006-08, has than 60%. Demand has nevertheless eased the impact of rising import prices. been constrained to levels around 40 bcm The government is said to have set up an (44 bcm in 2007) by the lack of supplies expert working group to develop a reform which has affected the use of gas in the plan for a natural gas pricing regime power sector and fertilizer production, which may be implemented earlier than (41% and 26% of use respectively), most people anticipate. Each stakeholder, as well as the development of including producers, local governments the transmission network. Indigenous and the association of city gas and production at 32 bcm in 2007 is being industrial users, has been consulted and supplemented by LNG imports. India proposed their respective ideas. has been importing gas through two LNG terminals, starting in 2003, and rising rapidly. In 2007, imports totalled 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 129

11.7 bcm, mostly from Qatar, but also been the development of natural gas Algeria, Nigeria and Trinidad and Tobago. vehicles (NGV) in Western and Northern India. Around 700 000 vehicles have been In 2008, India set up a gas utilisation policy converted to natural gas, accounting for to optimise the use of gas in a context more than 3% of gas use. of supply scarcity. The Model Production Sharing contract (MPSC) provides Domestic production guidelines for the utilisation of gas in the different sectors. The 22 fertilizer plants Domestic production has been relatively have been given fi rst priority. Some using stable over the past fi ve years. Most of the naphtha or fuel oil and not connected gas has been produced by Oil and Natural to the grid will be connected by 2011. Gas Corporation (ONGC), Oil India and Joint Liquefi ed petroleum gas (LPG), is the ventures of Tapti, Panna-Mukta and Ravva. second priority. Gas-fi red power plants Most of the output comes from Western rank third in the list as some plants are offshore fi elds while some onshore fi elds either not running or use refi ned products. are located in the Assam, Andhra Pradesh Fertilizers based in Andhra Pradesh will be and Gujarat States. But gas production is the fi rst to benefi t from the recent start expected to increase substantially in the in April 2009 of the Krishna-Godavari (KG) short term, thanks to Reliance Industries’ fi eld whose production is expected to giant fi eld Krishna-Godavari, whose reach up to 30 bcm by 2011. production is expected to add 30 bcm supply, doubling domestic gas production Consumption over the next few years. Additional gas production is also expected from six fi elds Gas demand has been growing strongly over under implementation by ONGC although the 2000-07 period. The main consumers no date has been announced so far. The are the fertilizer industry as well as the government has also offered blocks under power generation sector which represent the New Exploration Licensing Policy (NELP) more than two-thirds of total gas demand. to private and public sector companies Gas-fi red power is a little below 10% of with the right to market gas at market power output, which is dominated by coal determined prices. Over the past ten years, (with two-thirds of generation). However, the government has awarded 212 oil and if the country was not suffering from a gas blocks but launched its biggest licensing shortage of gas supplies, demand could round in April 2009, offering 70 blocks. be around 20 or even 30 bcm higher than it is. In the power generation sector, most Supply and import infrastructure of the 13 GW of installed gas-fi red capacity are used at relatively low factors while As demand continued to grow, resulting in power demand goes unmet in many areas. severe shortages, India started importing In addition, big cities such as Bangalore and LNG in 2003. Total regasifi cation capacity Chennai have not yet been linked to the amounts to 21.8 bcm. In 2007, LNG pipeline system, although such connections represented around 28% of demand. So are planned. One specifi c use in India has far, India has two LNG terminals located 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 130

in the North-West of the country. The Transportation infrastructure 8.9 bcm Dahej terminal, operated by Petronet, came on line in 2004 and was The existing pipeline network is essentially expanded to 17 bcm in 2009. The 3.7 bcm in the west and northern parts of the Hazira LNG terminal started operations in country, linking the terminals and the 2005; its capacity was increased to 4.9 bcm fi elds to major cities such as New Delhi. through debottlenecking in 2008. A third Until recently, the main transmission 7.5 bcm LNG terminal Ratnagiri in Dabhol is companies were GAIL and GSPL (Gujarat currently under construction and expected State Petronet). The development of the to be completed in 2009. Petronet plans domestic production and the coming on to complete its second LNG terminal line of LNG terminals will help GAIL develop (3.4 bcm) in Kochi in the southern state of the transmission network. Furthermore Kerala by 2011, while another terminal has India’s gas policy promotes private pipeline been proposed by Gujarat State Petroleum investment. As a result, Reliance Industries Corp Ltd (GSPC) at Mundra Port. Petronet completed in 2008 the East-West pipeline has secured supplies for its terminals with linking the KG fi eld in the East to its RasGas. refi nery in Gujarat. The 1 440 km pipeline is now the longest in India. Meanwhile India has also been looking at importing GAIL plans to invest USD 4 billion over the gas by pipeline. Even though two projects next three years to double the length of are still under consideration, the Myanmar- its pipeline network to 13 000 km with the Bangladesh-India pipeline project seems Dahej-Uran, the Dabhol-Panvel and the to have been cancelled. Jagoti-Pithampur pipelines. Furthermore GAIL plans to connect new cities such as „ The Iran-Pakistan-India (IPI) pipeline: no Pune, Kota, Indore and Gwalior. GSPL plans real progress has been made so far. The to expand its transmission network from main hurdles are disagreements over 1 130 km to 1 575 km. gas transit fees, tariffs, Indian concerns over pipeline security in Pakistan as Pricing issues well as the absence of a purchase deal between Delhi and Tehran. Pricing remains an issue in India which has been facing the rapid increase of „ The Turkmenistan-Afghanistan international LNG prices since it started Pakistan-India (TAPI) is also advancing importing LNG in 2004. Prices for domestic slowly. Negotiations are still under way production from state-owned companies between the four countries. According were kept relatively low. Furthermore, to plans in 2008, construction was Indian industrial users were not ready to scheduled to begin in 2010 and accept rapidly increasing international operations to start in 2015; however prices. In September 2007, the government Turkmenistan may have diffi culties changed the pricing system for domestic meeting all its export commitments. production. The price for companies other In April 2009, Turkmenistan offered gas than ONGC has been set between USD from the Yasrak fi eld to feed TAPI. 4.22 and 5.76 per MBtu compared with 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 131

Map 11 Indian gas infrastructure

Kabul Existing gas pipeline Islamabad AFGHANISTAN CHINA Planned or under construction gas pipeline Gas production area Existing LNG import facility New Delhi NEPAL BHU. Under construction PAKISTAN Kathmandu Thimphu LNG import facility Planned LNG import facility Vijaipur Planned LNG export plant Dhaka

Dahej Bhopal Calcutta BANG. VIETNAM Hazira INDIA MYANMAR Ha Noi Pipavav LAOS Mombai (Bombay) Vientiane Ratnagiri (Dabhol) Hyderabab Kakinada Yangon Krishna-Godavari THAILAND basin Indian Ocean Bangalore Bangkok New Mangalore Chennai (Madras) CAMBODIA Phnum Penh

Kochi Indian Ocean Tuticorin SRI LANKA Colombo 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, Petroleum Economist, media reports.

USD 2.02 per MBtu for ONGC. Although „ Asia is a thriving market for LNG these prices were much lower than imports and exports due to distances international LNG prices, which were between suppliers and consumers above USD 10 per MBtu over 2008, the making pipelines too costly. The latter have already declined sharply in producing countries are conveniently late 2008, and can be expected to decline located to supply LNG to the major further over the course of 2009. markets in China, India, Korea and Japan. Southeast Asia In early 2008, the outlook for Asia Pacifi c „ Gas continues to be an important part gas producing countries was buoyant of the region’s energy mix despite the with most countries expected to register current economic downturn. strong economic growth. There was high demand for gas from within the region „ The demand for gas is expected to and outside the region. Even with the increase while the investment in completion of a number of LNG projects, production, supply and transport there was concern that not all demand infrastructure is continuing. for gas could be met. Gas prices peaked 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 132

Map 12 South East Asian gas infrastructure Existing gas pipeline THAILAND Yangon Luzon Planned or under construction gas pipeline VIETNAM Manila Bangkok Mariveles Gas production area CAMBODIA LNG (Baatan) Map Ta Phut Phnom Penh LNG liquifaction plant Ho Chi Minh PHILIPPINES Palawan Planned LNG liquifaction plant Khanom

Krabi Mindanao Planned LNG regasification terminal BRUNEI Arun Bandar Seri Begawan Medan Kuala Lumpur Natuna Lumut Dumai MALAYSIA Bintulu MLNG SINGAPORE Jurong Isl. Kalimantan Bontang Sumatra Sungiasalak Senipah Tangguh Plaju Sulawesi Seram Papua Jakarta INDONESIAPAPUA West Java Java Surabaya NEW GUINEA Pasuruan Dili Masela Bali Sumbawa Port Moresby East Java Lombok Flores EAST TIMOR 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: Petroleum Economist, IEA. during the period as most gas contracts in in power generation, petrochemicals and the region are pegged to oil. Negotiated other energy intensive industries. Almost contracts and on-going price negotiations 100% of electricity is gas-fi red. Brunei has were subjected to upwards review. a very limited gas pipeline infrastructure, However, rapidly falling oil prices in the and there is no cross-border pipeline from second half of 2008 reversed these trends. Brunei to its neighbouring countries. Demand for energy also fell as countries experienced sharp economic slowdowns. Oil and gas exports account for more than Many countries have revised downward half of its GDP. Brunei is intensifying its their short- to medium-term forecasts for efforts in the exploration and development economic growth. Further, the supply of of new fi elds, hoping to extend LNG sales LNG is expected to increase signifi cantly contracts to Japan and Korea beyond their in 2009 both globally and regionally, as scheduled 2013 expiration. However, due large increments of new LNG production to disputes with Malaysia over maritime arrive on stream. boundaries, potential deepwater areas remain undeveloped. Brunei Indonesia Currently around 80% of Brunei’s gas production (10 bcm out of 12 bcm per Tangguh LNG project in West Papua has a year) is exported as LNG to Japan and capacity of 10.3 bcm, starting in 2009. This Korea. Gas is also consumed domestically is the third LNG complex in Indonesia after 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 133

Bontang and Arun. Volumes are destined pipelines. One of the terminals in West for export to the west coast of North Java is currently planned to be operational America (5 bcm, half of which is subject to in 2013, counting on supply from the diversion), Fujian, China (3.5 bcm) and SK Bontang LNG plant and Tangguh. Power and POSCO, Korea (1.6 bcm). There are also plans to take uncommitted gas for With the current emphasis on greater Indonesia’s domestic use. utilisation of gas for domestic consumption so as to reduce dependence on oil, the Indonesia’s NOC Pertamina is expected government has plans for more gas to be to decide on its partners to develop the made available domestically. About a third giant Natuna D-Alpha gas block in the East of power use is oil-fi red, with gas accounting China Sea in 2009, from the short-listed for less than half this level. The largest companies including Shell, StatoilHydro, users of gas in Indonesia are power plants, China National Petroleum Corporation (about 20% of annual gas use of 36 bcm), (CNPC), and ExxonMobil, the former followed by industrial users, fertiliser and operator of the block. More recently, petrochemical plants, i.e. those who use gas Petronas, Malaysia’s NOC, has been invited as feedstock. As the government is slowly to partner with Pertamina in the venture. reducing subsidies on oil for domestic use, The fi eld was discovered in 1973 and has more demand for gas is expected. estimated reserves of 54 tcf (1.5 tcm) of recoverable gas. The high CO2 content of Malaysia about 71% makes the development of the fi eld diffi cult. Based on the offi cial Malaysian government fi gures, Malaysia’s economy is predicted Indonesia is blessed with the largest gas to slow down in 2009. However, analysts reserves in the region (3 tcm). Pipeline in the private sector expect the country systems in Sumatra and Java seek to to face recession in 2009. A decline in gas overcome the geographical mismatch consumption has been observed as demand between the main demand centres in for gas by power plants declined about Indonesia (Java and Bali), and some of 5% in February this year. Around half of predominant supply sources in Natuna domestic natural gas use is in the power Island and South Sumatra. Other supply sector. Nevertheless, as gas prices are regions, such as Kalimantan and Papua, subsidised in Malaysia, demand is expected are not connected by pipelines with the to be stable or decline only slightly. largest consuming regions. Due to the economic crisis, the gas price Due to this mismatch, LNG import has been reduced to assist businesses terminals are being considered in East during this period. The gas price to be Java, West Java and North Sumatra to effective from 1 March 2009 is as follows: complement the existing and future 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 134

Table 19 Gas prices in Malaysia (as of March 2009)

New price effective 1 March 2009 Previous gas price Sector (MYR per MBtu) (MYR per MBtu) Power sector 10.7 14.31 Reticulation (residential/commercial) 15 22.06 Industry 15.35 23.88

Source: Economic Planning Unit, Prime Minister’s Department, Malaysia. Note: MYR: Malaysian Ringgit. 1 USD = 3.5 myr as of June 2009.

It was also decided that the gas price will Singapore be reviewed twice a year on 1 January and 1 July. Currently, the gas being subsidised Singapore is constructing a 4.1 bcm LNG by PETRONAS is around 50% of market terminal on the industrial Jurong Island price. to be operational around 2011. Security of gas supply is the main driver for this The debottlenecking of MLNG Dua facility development, to complement the current is scheduled to be completed by the end of 8 bcm per year pipeline imports from 20093. Once completed, each of the three Indonesia and Malaysia, which is used trains will be capable of producing 4.1 bcm to generate 80% of the country’s power per year, in total, an additional 1.5 bcm per supply. Gas demand is expected to rise as year. With the debottlenecking exercise on power generators switch from oil to gas; MLNG Dua complete, the Bintulu complex’s in addition, new petrochemical plants are annual production capacity will rise to planned. 33 bcm. The debottlenecking of MLNG Tiga depends on the economy and gas supply. Supported by the development of the The expansion, if undertaken, will increase LNG terminal and perhaps additional gas the Bintulu complex’s annual production import capacity from West Natuna, the capacity to 35.5 bcm. Additional supply Gas Act 2008 will facilitate open access for of gas from Sabah via a 500 km pipeline gas importers and retailers in Singapore is being planned to supplement the gas that will increase and expand gas market supply to the Bintulu complex. The main liquidity in this region. There is a potential consumers for gas in Sarawak are LNG availability of surplus gas that may be plants and a fertiliser plant. diverted towards spot trading.

On 11 December 2008, Kikeh fi eld (offshore Thailand Sabah) commenced exporting gas to Labuan Gas Terminal (LGAST). The main customers Thailand is a signifi cant gas user, at for the gas are methanol plants. 35 bcm per annum, two-thirds of which

3. Source : PETRONAS. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 135

is used in the power sector. Nearly 70% The Philippines of the country’s 140 TWh annual power output is gas-fi red. Thailand currently Demand for natural gas in the country is receives gas from several fi elds in the Gulf expected to register a healthy growth in of Thailand, and the Yadana and Yetagun the next two decades, from the current gas fi elds in Myanmar (about 10 bcm per low base of 4 bcm. Currently, gas is year) as well as the Malaysia-Thailand sourced from the Malampaya fi eld which Joint Development Area (JDA). In 2008 has limited reserves. Philippine National state-owned PTT started construction Oil Co. (PNOC) has a plan to build an LNG of a receiving terminal on the east coast receiving terminal in Bataan. In 2007, of the country to be completed by June Japan’s Marubeni conducted a technical 2011. PTT has agreed to purchase 1.4 bcm feasibility study on the terminal and per year of LNG from Qatar. Thailand’s gas associated gas-fi red power plants with demand is forecast to rise to 52 bcm in minimum capacity of 1 GW. Since then the 2011 and 72 bcm in 2021. Thailand wants plan has registered little progress. LNG to diversify away from piped-gas from Myanmar, as domestic production Myanmar seems likely to fall. Major potential users of regasifi ed LNG include the state-owned The negotiation on gas sales for block M-9 Electricity Generating Authority (EGAT). is approaching its fi nal stages. The Heads The government is also promoting the use of Agreement (HoA) signed in June last of natural gas powered vehicles (NGVs) for year would form a basis for the fi nal gas the transportation sector4. sales agreement. The HoA stated that 80% (6.8 Mcm per day) of the average volume of Vietnam gas available will be exported to Thailand while the remainder will be for domestic While power and gas use are currently consumption5. The project is targeted to low, Vietnam expects double-digit power be on stream by 2012. demand growth, most of which would will be met by gas-fi red power generation. In On 24 December 2008, China and Myanmar the Phu My area, new power plants will signed an agreement for the sale of oil and be supplied by gas from the Nam Con Son gas for a 30 - year period. The agreement basin, while the South-West basin is being stated that the supply of gas will come developed to supply projects in that area. from the Shwe fi eld, with reserves of up to Vietnam is also developing both hydro and 170 bcm. It also includes the construction coal-fi red power projects. of oil and gas pipelines to Kunming in Yunnan Province. China is expected to start receiving gas from Myanmar via pipeline by 2013. Myanmar annual gas output can

4. The number of NGVs is expected to increase from about 51,000 in 2006 to more than 500,000 after 2010. 5. Source : Ministry of National Planning and Economic Development. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 136

be expected to double from the current Nigeria level of 12 bcm to around 25 bcm by 2015. Nigeria’s gas reserves, estimated at around Since the discovery of hydrocarbons in the 5.2 tcm or 3% of global reserves, are the Bay of Bengal, the tension over maritime largest in Africa. Although a signifi cant borders with Bangladesh has increased. and growing LNG exporter (21 bcm in Talks between the countries are on going. 2007), domestic gas use in this populous (145 million) country is low at 13 bcm, Papua New Guinea about a third being in the power sector, where it provides more than half the very The front-end engineering and design low production of 23 TWh. The Nigerian (FEED) for PNG LNG project began in May government launched the gas master 2008 after the partners in PNG LNG agreed plan in 2008, which focused on exploiting to the fi scal terms with the Papua New the country’s signifi cant gas potential for Guinea government. The fi nal investment economic development by prioritizing the decision (FID) on this project is expected to domestic use of gas for power generation be taken by the end of 2009. The partners over export. To achieve this goal, the of this project are keen to secure long-term government has tried to attract investors contracts with targeted buyers in Japan, in building three central gas gathering and China, Korea, Chinese Taipei and India for processing facilities and three gas pipeline the whole volume of 8.6 bcm per year. The transmission systems. In March 2009, the project is scheduled to start shipments government selected 15 companies for in 2014. Gas is sourced from Hides, Juha, these investments, including IOCs as well Angore, Kutubu, Agogo, Moran and Gobe as Gazprom. This development should give fi elds with estimated reserves of 9 Tcf companies a clearer direction for their (255 bcm). businesses including the planned LNG projects. The Nigerian National Petroleum Corporation (NNPC) announced in February West Africa 2009 that plans are in place to deliver around 20 bcm per year of gas to the „ Nigeria is a signifi cant LNG exporter, domestic market by end-2009, although with potential to provide signifi cantly it is unclear if this has been adopted as a more. national policy by the government.

„ Domestic use is low, and much gas Nigeria fl ared 22 bcm of gas in 2007 is fl ared, despite chronic power according to OPEC data. The Nigerian shortages. government has taken a fi rm stance on gas fl aring. It was announced that the „ Other regional producers are entering government would not budge from the the LNG market (Angola, Equatorial deadline of ending fl aring by end-2008 Guinea) and gas from Cameroon could and companies that continue to fl are gas be fed to Equatorial Guinea. after the deadline would be heavily fi ned. However, the deadline passed without any 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 137

serious repercussions for fl aring companies TSGP would carry Nigerian gas for and the government has proposed end- 4 200 km through Niger and Algeria to the 2010 as a new deadline. Nigeria hopes Mediterranean. It is strategically important that the existing fl ared gas can be used as for the European Union, which wishes feedstock for LNG exports or domestically to diversify its gas supplies and increase for power generation. energy security. Algeria is also interested in this project as it could help not only There have been a number of delays enhance its position as a key gas supplier in commissioning the West Africa Gas to Europe, but also meet the country’s own Pipeline (WAGP) which will carry Nigerian demand. Apart from Gazprom, Total has gas to Ghana through Benin and Togo. The expressed its interest in taking a stake in 678 km pipeline experienced a number of TSGP in February 2009. This project is still obstacles including operational problems, at an early stage and a formal consortium sabotage by militants in the Niger Delta, to develop the pipeline is yet to emerge. and other accidents. The project offers a potential to support regional development Equatorial Guinea and cut spending on fuel product imports for power generation. For example, Ghana With the successful operation of the fi rst generates more than a third of its power LNG project (EGLNG), Equatorial Guinea from oil. The Takoradi power plant in hopes to establish itself as a hub for the Ghana will be the fi rst benefi ciary of the aggregation of gas in the area. In January pipeline. First gas was brought to Ghana 2009, an MOU was signed between the in December 2008. Since April 2009, gas is national gas company (Sonagas), E.ON supplied at 30 Mcm per day to the power Ruhrgas, Union Fenosa Gas and Galp Energia plant. for the creation of a company that will act as the owner of a gas-gathering system Since early 2008, Russia’s Gazprom has which will utilise gas that is currently being been pressuring Nigeria to take part in fl ared. The gas-gathering company, known its hydrocarbon projects. In September as Consortium 3G, is currently drafting a gas 2008, Gazprom signed an MOU with master plan for Equatorial Guinea. The aim the NNPC to co-operate on oil and gas of the plan would be balancing the needs of projects in Nigeria, though few details LNG export with those of domestic gas use. were disclosed. Gazprom also mentioned Until recently, the country was an observer in February 2009 that it was interested in of the Gas Exporting Countries Forum investing over USD 2.5 billion in Nigeria’s (GECF), but became a formal member at gas infrastructure required by the gas the 7th Ministerial meeting in Moscow in master plan. In return, it is likely that December 2008. Gazprom would like to be involved in not only LNG projects but also in the Trans- The government’s stance on gas fl aring Sahara Gas pipeline (TSGP) project. has become more assertive6 than a few

6. The government announced in July 2008 that it will take a legal action over gas fl aring by ExxonMobil, which contributes more than 70% of the gas being fl ared in the country. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 138

years ago, as the country is keen to use supply and creating a petrochemicals its gas resources. While the second train industry. In this regard, Angola’s LNG of EGLNG has been planned, its fi nal project contributes to the development investment decision is complicated due of the domestic market, rather than to diffi culties sourcing suffi cient gas for competing with it. the project. Although in 2006, Nigeria and Equatorial Guinea signed an agreement in which Nigeria was to supply gas feedstock Middle East and North Africa for the second train of EGLNG, Nigeria has since planned new LNG projects and „ Middle East and North Africa (MENA) tried to reserve a large amount of gas countries hold almost half of global gas for domestic use. On the other hand, co- reserves, and are both signifi cant gas operation with Cameroon is forthcoming, users and exporters. as its national hydrocarbon company (SNH) started discussions in early 2009 „ Rapidly growing domestic power and with counterparts of EGLNG to supply gas industrial demand growth will reduce for the second train. export availability in the absence of new gas developments, and the right Angola policies to underpin them.

The Angolan government encourages „ Iran, the world’s second largest gas investment in exploring for natural gas, in reserve holder, is now the world’s third order to utilise gas for domestic electricity largest gas user; a third of gas is used supply and diversify its generation mix in the power sector. Despite its vast which depends mostly on hydropower7. In reserves, it is a net gas importer. March 2009, Angola’s parliament decided to exempt gas exploring companies from paying taxes. Angola has little The Middle East and North Africa infrastructure in place to utilise its countries hold around 80 tcm or 46% of gas reserves that are currently fl ared8, proven global gas reserves. The region and needs to install new gas-gathering has seen domestic gas demand increase facilities and upgrade power generation signifi cantly in recent years. Between 2000 infrastructure. The Angola LNG project and 2007, domestic consumption grew (ALNG) has made progress since receiving by 48% in the North African countries its fi nal investment decision in December while there was an increase of 56% in the 2007, and appears to be on schedule with Middle East. This is a trend that is set to the fi rst LNG expected in 2012. ALNG plans continue, although not at the same pace. to provide the domestic market with up Even though the Gulf region has vast gas to 1.3 bcm of gas for increasing electricity reserves, most Gulf countries are heading

7. Hydropower accounts for 90% of total power generation in Angola. 8. Angola fl ared 7.3 bcm of natural gas in 2007, according to OPEC data. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 139

Map 13 African gas infrastructure Algiers Skikda SYRIA Arzew TUNISIA ELNG Rabat Damietta Baghdad Madeira (Port.) Marsa Hassi Tripoli T1&T2 LNG MOROCCO Messaoud Mellitah el Brega IRAQ JORDAN Cairo KUWAIT Canary Isl. (Spain) In Salah In Amenas LIBYA Qena SAUDI WESTERN EGYPT SAHARA ALGERIA Riyadh Sahara Desert ARABIA MAURITANIA Cape Verde Nouakchott NIGER MALI ERITREA San’a SENEGAL CHAD Y Dakar BURKINA Niamey Karthoum Asmara Bamako THE GAMBIABanjul FASO Ndjamena Bissau Ouagadougou SUDAN DJIBOUTI GUINEA-BISSAU NIGERIA Djibouti GUINEA Kaduna Conakry IVORY Abuja Addis Ababa

Freetown BENIN ETHIOPIA COAST TOGO CENTRAL SIERRA LEONE Yamoussoukrou OK LNG GHANA P. Novo AFRICAN Monrovia Lome CAMEROON Accra REPUBLIC LIBERIA Abidjan WAGP Brass LNG Bangui NLNG (Bonny Isl.) Yaounde SOMALIA Byoko Isl. EQUA. GUINEA UGANDA Mogadishu Kampala KENYA SAO TOME & PRINCIPE Libreville CONGO GABON RWANDA Nairobi DEMOCRATIC REP. Kigali Bujumbura Brazzaville OF CONGO Mombasa Pointe Noire Kinshasa BURUNDI CABINDA Malongo Dodoma Quinfuquena TANZANIA Luanda Comoros ANGOLA MALAWI ZAMBIA Lilongwe Lusaka Harare Antananarivo ZIMBAWE MADAGASCAR NAMIBIA BOTSWANA MOZAMBIQUE Windhoek Gaborone Pretoria Existing gas pipeline Johannesburg Maputo Mbabane Planned/under construction gas pipeline Sasolburg Alexander Bay SWAZILAND Gas production area Maseru Richard’s Bay LESOTHO Durban Gas field SOUTH LNG export plant AFRICA Under const/planned LNG export plant Mossel Bay Planned LNG import terminal Cape Town

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: Petroleum Economist, IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 140

towards gas shortfalls. This is the case for they seek to diversify their imports. This Kuwait, Dubai, Saudi Arabia, United Arab will require investments in cross border Emirates (UAE) and Oman. In particular, capacity (France-Spain, potential reversal Kuwait and Dubai are turning to LNG of TENP pipeline linking the Netherlands to imports with Kuwait starting imports in Italy) and transmission capacity in order to 2009. Also Egypt is facing a balancing act bring these volumes to the core European between domestic gas use and exports, and markets. Spain is already suffering from a moratorium on new export projects until potential over-supply as total import 2010 was introduced in 2008. The increases capacity is roughly twice demand and in gas demand are and will continue to Italy is likely to have overcapacity if other be mainly driven by power generation projects such as additional LNG terminals and industry, such as petrochemicals and (beyond Rovigo) and pipelines (Turkey- desalination. Signifi cant gas resources are Greece-Italy) are completed as well. also reinjected into oil fi elds. Italy probably needs to become a transit country for additional North African gas North Africa exports both LNG and to reach other markets. pipeline gas, mainly to Europe. The region has currently a pipeline export capacity Algeria of about 50 bcm, to Spain and Italy. This capacity will increase by the end of 2009, Algeria has the eighth largest reserves of when the 8 bcm Medgaz pipeline from natural gas and is the sixth largest natural Algeria to Spain starts operating. Further gas producer worldwide. Their production pipelines are planned such as the 8 bcm in 2007 was 90 bcm, of which 63 bcm Galsi pipeline, going from Algeria to Italy was exported and the remaining 27 bcm (via Sardinia) expected in 2012-13 or the consumed domestically. It exports both expansion of Green Stream by 3 bcm. As pipeline gas and LNG to Europe as well as to for LNG, there are currently 45 bcm of North America and Asia. Algerian supplies liquefaction capacity in North Africa and to OECD Europe have been quite stable 75 bcm in Middle East. Signifi cant capacity over past years, varying between 50 and additions are coming on stream in the 60 bcm. Due to the delays in LNG projects MENA region in the short term (see section (see section on LNG markets), as well on the Developments in the LNG markets), as potential delays of pipeline projects, at a time when the global gas market is Sonatrach postponed meeting its long experiencing a downturn in demand. Most touted 2010 gas export targets of 85 bcm European countries, for instance, saw per year until 2012, with an increase to slowdowns in their gas demand in the last 100 bcm by 2015. After the announcement quarter of 2008 and the fi rst quarter of of the new targeted completion dates of 2009, as gas consumption in the industrial 2013 for the two LNG projects, the 85 bcm sector dropped following the economic target also looks more likely to be reached slowdown. only after 2013. In March 2009, however, the country’s energy minister reasserted Gas supplies from the MENA region are the export target of 100 bcm per year a priority for European consumers, as by 2015, and confi rmed plans to spend 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 141

USD 63.5 billion in the energy sector up and 49 bcm under a high and low case until 2013, claiming that oil prices of scenario respectively). Major drivers for USD 40-50 per barrel were suffi cient to this demand growth would be the power sustain this. There are some hurdles to this sector and new major industrials such as target though: project delays, an ageing Ammoniac SBGH in 2011 or Aluminium infrastructure and a reserve squeeze as Beni Saf in 2012. In the power sector, domestic demand is increasing. the majority of the new capacity is gas- fi red (see table below). Going forward, to Algeria is currently modernising its succeed with their export target as well as 16 200 km pipeline infrastructure (some of to satisfy the rapidly increasing domestic which is 40 years old) and extending it by demand, new production capacity needs 5 300 km. Domestic demand comes mainly to come on line. from the power generation sector which represents just over 40% of total demand Beyond Gassi Touil expected for followed by 27% used by industrial 2012 (discussed further in section on customers directly supplied by Sonatrach. Developments in the LNG markets), According to the long-term forecasts of development of some gas fi elds led by the regulator Commission de Régulation de Sonatrach needs to move forward, as well l’électricité et du gaz (CREG) issued in 2008, as Timimoun with Total, Touat with GDF demand is expected to increase to 55 bcm SUEZ, Reggane with Repsol. As for future by 2017 under a base case scenario (67 bcm supplies, international companies need the

Table 20 New power plants in Algeria 2008-12 (planned and under construction)

Plant Type Capacity (MW) Expected online date

Oran Est Gas turbine 75 Mar-08 Relizane Gas turbine 465 May-July 2009 Arbaâ Gas turbine 560 February-October 2009 Alger Port Gas turbine 71 April-May 2009 M’sila Gas turbine 430 June-August 2009 Annaba Gas turbine 71 Mar-09 Batna Gas turbine 254 April-May 2009 Hadjiret Ennous CCGT 1 200 2009 Terga CCGT 1 200 2012 K. Edraouch CCGT 1 200 2012 Hassi R’mel Hybrid (solar/gas) 150 (30 solar) 2010

Source: CREG, programme indicatif des besoins en moyens de production d’électricité 2008-17. Note : most plants have several turbines, which come on line at different dates. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 142

right incentive to go ahead with exploration criticised the government for securing activities, especially in a time of economic low prices when domestic gas demand is downturn. Algerian Minister of Energy rapidly increasing, and the export contract and Mining Chakib Khelil announced that went to court, as it was not approved by Algeria will consider making changes to the parliament. Although contested, the their upcoming oil and gas licensing round country’s Higher Administrative Court after a weak response in the most recent ruled, in February 2009, that the exports round, held in December 2008. Of the 70 could continue. international oil companies that showed interest in the licensing round, only nine As the government of Egypt decided submitted bids. This round was the fi rst to to prioritise supplies to its domestic be held under a 2006 amendment of the market fi rst, a moratorium on new export hydrocarbon law, which gives Sonatrach contracts until 2010 was introduced. The a minimum 51% share in all oil and gas dilemma is that the state wants gas for exploration agreements made with the domestic market, but the international foreign companies. players might choose to hold off on development of deepwater gas if Egyptian Egypt authorities do not agree to a higher domestic price, or to release some of this output There has been a rapid rise in domestic gas to supply new export projects (e.g. a new consumption over the last 20 years. More LNG train). For example, the fi rst train at recently, from 2000-07, gas consumption Damietta has not run at full capacity due to a increased by close to 70% in just seven shortage of feedgas. Still, compromises can years up to 37 bcm, roughly equalling also be made, as shown by the long-term gas that of Spain. The single most important sales deal that Germany’s RWE Dea struck demand driver of gas consumption in with the Egyptian government for the gas Egypt has been power generation which from its offshore North Idku gas fi eld in has been and will continue to be the largest the fi rst half of 2008. RWE had slowed its gas consumer in the country, accounting development plans for this offshore fi eld for about 60% of total gas utilised. since 2006, as it was not allowed to develop this gas for LNG exports. This put strong Egypt is facing a tough choice between pressure on the Egyptian state, knowing domestic gas use and exports as it intends that it needed gas to satisfy the domestic to extend the Arab Gas Pipeline all the way market. RWE was thus able to get a much to European markets as well as adding new higher price for its expensive deepwater LNG trains to existing projects (see section gas, even though they were not allowed on the Developments in the LNG markets). to export their production. The Arab Gas Pipeline transports gas from Egypt, through Jordan into Syria and In general, IOCs are required to sell about Lebanon. Egypt also exports gas to Israel, two thirds of their production to the after signing a contract for delivering Egyptian state. This gas will then be sold 1.7 bcm per year (with an option to take to the domestic market at low prices up to 2.1 bcm per year). The opposition given the high levels of energy subsidies. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 143

Plans to phase out such subsidies are per year. Libya is also seeking to increase being discussed, but this is politically very its natural gas exports, particularly to diffi cult. This is an issue that needs to be Europe. Their current export projects dealt with as current domestic prices by consist of the expansion of the existing no means refl ect the spiralling exploration 8 bcm Green Stream pipeline to Italy by and development costs seen in the 3 bcm and the expansion of the Marsa El deepwater offshore areas. Meanwhile, Brega LNG plant. The LNG plant currently the price at which EGAS will buy gas has an output level of 1 bcm (0.7 Mtpa), developed by IOCs is now negotiated on signifi cant below the design capacity a case-by-case basis. In the context of of 4.4 bcm (3.2 Mtpa). Sirte Oil Co. (SOC) the 2008 licensing round it was reported entered a rejuvenation agreement with that the buy-in prices ranged between Shell in 2005, to redevelop and upgrade the USD 3.70 and USD 4.70 per MBtu depending plant, but the work is moving very slowly. on the location of the concession – fi gures Libya has succeeded in attracting foreign seen quite favourably by the industry, and investors, both upstream and downstream. signifi cantly higher than in some other Companies like BP, Shell and Exxon are major producing countries. looking for potentially exportable gas. And ENI, the major international player The past year has seen some signifi cant in Libya, is teaming up with Gazprom. For additional gas discoveries both on- Gazprom, this will be an important step and off-shore. The Egyptian Ministry to diversify its supplies and gain more of Petroleum is now said to be more access to European markets. However, confi dent of increasing proved reserves exploration in the last year has been and supplying more gas both domestically disappointing particularly compared with and for export. They have given BP and ENI Egypt or Algeria; and without signifi cant authorisations for the additional 7 bcm new discoveries, growing domestic LNG train at Damietta, though fi nancial demand is soon likely to put pressure on constraints may now force the companies volumes available for export. to delay. Meanwhile, an agreement is said to have been reached for a signifi cant Domestic consumption, estimated in 2008 increase in the price of gas for Israel, which at 10 bcm, is forecast to increase to around would open the way for a resumption of 30 bcm by 2012. It will mainly be driven by deliveries at full volume. the industrial sector and power generation where gas usage is strongly encouraged Libya by the government. A substantial number of new gas-fi red plants are planned, Expansion of natural gas production is most of them located along the coast. a high priority for Libya as it aims to use To achieve this, pipeline capacity is natural gas instead of oil domestically for being expanded both in the West around power generation and industrial activities, Tripoli and in the East beyond Benghazi. freeing up more oil for export. Between A pipeline link between Alexandria and 2000 and 2007 natural gas production the most eastern city of Tobruk in Libya increased by 180% to reach about 30 bcm is also under consideration. As an example 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 144

on the industrial side, Yara International Imports completed a 50% joint venture with the National Oil Corporation of Libya (NOC) Currently, Iran is a net importer of gas. and Libyan Investment Authority (LIA) Tehran receives 9 bcm per year10 from when they signed the fi nal agreement, Turkmenistan through the pipeline that in February 2009, to create the fertilizer runs from the Turkmen Korpedzhe fi eld joint venture Libyan Norwegian Fertilizer to Kurt-Kui on the Iranian side. The gas Company (Lifeco) that will own and is mainly consumed by Iranians in the operate the fertilizer facilities at Marsa north-eastern corner of the country. The El Brega. NOC will supply natural gas to Turkmen supply has been interrupted Lifeco under a long-term agreement with several times amid price disputes. When a price linked to fertilizer product prices. deliveries resumed in 2008, Iranian authorities would not disclose how much Iran they were paying. For 2009, it is reported that Iran has agreed to pay USD 350 per Domestic demand for natural gas in Iran mcm. This is at or above the European is rising steeply. Consumption grew at an price, and will require Iranian government annual average of 8% from 2000 to 2007 subsidies of close to USD 1.5 billion to reaching 107 bcm in 2007. The National underwrite the low domestic price level. Iranian Gas Company (NIGC) forecasts a Capacity for imports from Turkmenistan doubling of commercial gas delivery by is likely to be expanded from 8 to 13 bcm 2012, equating to a 16% per year growth. per year in the period to 2012. Iran has This is partly due to heavy subsidies on further signed a deal with Azerbaijan for the domestic market, as well as a desire to gas import from the Shah Deniz offshore reduce dependence on imported gasoline, gas fi eld post 2012, through the spur of through gas use in vehicles. The need to the South Caucasus Pipeline (SCP) leading reform gas pricing is well recognised in to Turkey via Georgia already extending the country. In addition, the ambitious into Iran, but not being used. plans for expansion in the petrochemical sector will require large volumes of gas. Export pipeline commitments

Furthermore, the need for reinjection Meanwhile, Iran has signed a variety in Iran’s maturing oil fi elds is about to of contracts and Memorandums of increase sharply. Currently 30-40 bcm per Understanding to supply gas, mainly to year of gas is reinjected, possibly growing its regional neighbours, few of which to more than 100 bcm in 20159. There are have yet been implemented. nevertheless disagreements between different governmental bodies on how Iran is committed to supply Turkey with national gas resources should be used. 10 bcm per year, but there have been several interruptions in Iranian delivery and the

9. Facts Global Energy. 10. The fi gure is not actual but on contract basis. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 145

average supply since 2003 has been lower Iran has not resolved a long-standing at 4-5 bcm per year. Since around 63% of dispute with Crescent Petroleum of the Turkey’s current gas demand is met by United Arab Emirates (UAE) for the supply Gazprom, additional Iranian supplies would of 6 bcm per year of associated gas from signifi cantly reduce Turkey’s dependence the offshore Salman fi eld. There are also on Russian supplies. In September 2007, other potential deals with Bahrain and state-owned Turkish petroleum company Kuwait. All these plans are vulnerable to TPAO signed a preliminary deal to develop disputes over prices. three phases of South Pars, and has the option to transport the Iranian gas back The Swiss energy company Elektrizitäts- to Turkey. The agreement includes plans Gesellschaft Laufenburg AG (EGL) signed in for two pipelines that would eventually March 2008 a 25-year contract for delivery be connected to the Nabucco pipeline in of gas to its power stations in Italy via a Erzurum. The pipelines’ capacity will be pipeline scheduled to be completed in 30 bcm per year and will be linked to the 2012 (the Trans-Adriatic pipeline, TAP). Iranian east-west pipeline system. This The contract implies that Iran would sell would allow Turkmen gas to be shipped 5.5 bcm per year through the existing to Europe through Iranian territory, if Iran-Turkey link for 25 years. Turkmen production is substantial enough. The long-planned Iran-Pakistan-India In October 2008, Iran said it would supply Pipeline (IPI) is intended to carry 60 Mcm neighbouring Armenia with 1 bcm per per day, shared equally by India and year. The amount of gas may expand to Pakistan. But India and Iran have not been 3 bcm later. In exchange, Armenia will able to agree on pricing or on the delivery supply Iran with electricity (3 kWh per point for the gas. India has now virtually cubic meter gas). Gazprom is to contribute withdrawn from the project since the USD 200 million to the cost of the Iranian- terror attacks in Mumbai in November Armenian pipeline. Some commentators 2008. Without participation by India, it is have suggested that this would relieve the obviously more diffi cult for Pakistan to Russians of the need to supply Armenia via agree on terms and conditions with Iran. Georgia. In March 2009 Armenia announced the completion of the line, but no date for Export LNG commitments deliveries has been set. In March 2009, Iran’s Oil Minister said that Iran signed a contract in early 2008 with the country has signed a deal with China Oman for the transfer of 10 bcm per year National Offshore Oil Corp. (CNOOC) to by pipeline. The deal implies that Oman develop the North Pars gas fi eld as an and Iran will jointly develop the Kish gas LNG export project. CNOOC plans to fi eld in the Gulf as well as the Hengam gas invest USD 5 billion in upstream and fi eld. Oman has been short of gas for its USD 11 billion in LNG facilities, in Qalhat LNG plant, but may receive enough exchange for 50% of the production of from the planned extension to Qatar’s the fi eld. Russia has also shown interest in Dolphin pipeline via Abu Dhabi. developing the South Pars fi eld. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Non-OECD countries and regions 146

With LNG projects based on South Pars gas reserves involving Total/Petronas and Shell/Repsol on hold for some time, only the Iran LNG project led by National Iranian Oil Corporation has begun site preparation works. No realistic completion date is in sight. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 147

OECD COUNTRIES AND REGIONS

OECD countries account for half of gas use inventories and increased demand (see globally, and while many are signifi cant section on gas prices). After that spike, producers, and even exporters, the OECD they have been progressively declining countries are net gas importers. to well below USD 4 per MBtu in March, April and May 2009 despite a colder than average winter season. This recent decline North America refl ects fundamental adjustment to supply and demand conditions in North America „ Natural gas prices rose and fell as well as a drop in oil prices. Industrial gas dramatically, like oil prices, in 2008. demand in particular has fallen sharply, However, unlike oil, they have beginning in late 2008 and into 2009, so continued to fall sharply well into 2009, that in February 2009 industrial gas use to less than half the price of oil on an was down 15% on a year earlier. At the energy basis. same time, the conventional wisdom of plateauing or declining US gas production „ Demand in the United States, Canada (backed up by around 1-2% per annum and Mexico also fell sharply late in 2008 decline 2000-06) has been overturned and into 2009, notably in industrial and by a sharp increase in unconventional power generation use. gas production, so that gas output rose around 8% in 2008, continuing into 2009. „ The astonishing rise in unconventional One outcome has been high storage levels: gas production, of at least 50 bcm per 54.3 bcm as of early May 2009, 13.7 bcm annum, reversed the historical decline higher than last year and 10.3 bcm above in United States gas output, and has the 5-year average of 44 bcm. Demand for global implications, through reducing imported gas (from Canada and LNG) fell United States demand for LNG. 14% in 2008, while LNG imports were down dramatically by more than half. In Canada, „ Whether these production levels can be prices have followed a similar evolution maintained at prices below USD 4 per with a steady increase from around USD 7 MBtu is one of the major uncertainties per MBtu fi rst quarter of 2008 to USD 11 in the United States and indeed on per MBtu in July before falling to USD 6 global gas markets in 2009-10. per MBtu in February 2009.

Demand Recent market evolution Canada’s gas consumption has been In 2008, Henry Hub prices averaged USD 9 relatively stable the last fi ve years, at an per MBtu, up from USD 7 per MBtu in average of 96 bcm. Around one-third of 2007. Prices were particularly volatile, Canadian gas demand comes from the increasing from USD 7 per MBtu to more residential and commercial sector and than USD 13 per MBtu in June 2008 due is very seasonal. The industrial sector to increases in oil prices, continuing cold consumes less than one-third and the weather in the fi rst quarter of 2008, lower rest is consumed in the power generation 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 148

sector. In particular, gas is used by the (+39 bcm). In 2007, the main drivers were non-conventional oil industry in order to power generation (up 10% year-on-year) extract and process oil sands. Gas is used and the residential sectors (up 8% year- in co-generation processes to generate on-year). In 2008, it was the residential and both electricity and steam. Canadian commercial sector that had the greatest consumption increased by 4% to 100 bcm increases, at around 3.5%. The economic in 2008. Also exports saw a fall during slowdown hit particularly the industrial 2008, down 6% year-on-year. Natural gas and power sectors, which account for consumption in the United States was up almost 60% of the gas consumption in by 5 bcm in 2008 reaching 657 bcm, a more the United States. The severe economic modest increase than the one seen in 2007 slowdown has resulted in layoffs and plant

Map 14 North American gas infrastructure

Victoria Island Gas pipeline Prudhoe Bay Planned/under const. gas pipeline Gas field LNG import terminal ALASKA Under const. import terminal (USA) Norman Wells Planned/approved LNG import terminal LNG export plant

Anchorage Planned LNG export plant Kenai

Prince Rupert Edmonton Prince Albert CANADA Calgary Winnipeg Regina Vancouver Thunder Bay Seattle Bismarck Sudbury Quebec Montreal Billings Minneapolis Ottawa Portland St. John, Rapid City Toronto N. Brunswick Casper Chicago Providence Everett Omaha Toledo Northeast Eureka Salt lake C. Indianapolis N. York Gateway Reno Denver St. Louis Pittsburgh Washington D.C. San Francisco UNITED STATES OF AMERICA Cove Point Raleigh Santa Fe Stephens Douglasville Los Angeles Rosarito Tucson El Paso Dallas Cameron Savannah Energia Naco Golden Pass Sabine Elba Island Costa Azul Puerto Libertad Chihuahua Gulf Tampa Freeport LNG Gateway Freeport Lake Charles BAHAMAS Monterrey Miami Nassau Mazatlán MEXICO Havana CUBA Aguascalientes DOMINICAN REP. Altamira HAITI Guadalajara Tuxpan Merida Port-au-Prince Mexico C. Veracruz S. Domingo Manzanillo Lazaro Cardenas BELIZE GUADELOUPE (FR.) Salina Cruz GUA. HONDURAS 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: Petroleum Economist, IEA, media reports. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 149

closures, while ammonia and ethanol States for the fi rst and second quarter producers have seen prices and output of 2008 was around 9% compared to the drop rapidly1. Also the steel industry same period in 2007. The increase was in the United States has been hit hard led by the development of onshore fi elds, with production levels down over 50% e.g. in Texas and Wyoming (supported by in January 2009 compared with the same an increase in the average number of gas month a year earlier. The drops in both rigs in these regions). More than half of sectors were particularly important during the increase in production between fi rst late 2008 and early 2009. In January 2009 quarter 2007 and fi rst quarter 2008 came and February 2009 industrial gas demand from Texas, where supplies increased by was down 12% and 15% respectively, well 15%. Wyoming followed closely with an below the fi ve-year average. Gas demand increase of 9%, Oklahoma with 6% and in in the power generation sector dropped Louisiana with 4%. The production growth by 3% in 2008 due to a combination of a in the last two quarters slowed down to milder summer, lower prices during the a level of around 4% due to hurricanes fi rst half of the year, and lower electricity in September 2008 which reduced the demand towards the end of 2008. Gas- production in the Gulf of Mexico by fi red power was down 4% in early 2009. around 6 bcm. As much as 95% of the Still, the low gas prices also have the gas production in the Gulf of Mexico was potential to mitigate some of the demand shut-in at the start of September; full decline. The current prices have for restoration is not expected until late May instance enabled the restarting of some 2009. closed-down fertilizer or feedstock plants and gas-fi red generation is displacing coal- The Western Canada Sedimentary Basin fi red generation in some regional markets, (WCSB) accounts for 98% of Canadian gas despite sharp coal price declines. production, of which 80% comes from Alberta, 16% from British Columbia and Demand in Mexico followed the pattern the remaining 4% from Saskatchewan. seen in many OECD countries. Strong Throughout 2008 Canadian gas production growth in 2006 and 2007 (8-9% in Mexico’s was lower than in 2007, recording a near case) continued in the fi rst half of 2008, 5% fall for the year. Around 57% of only to be reversed sharply later in the Canadian production was exported to the year, with near double digit falls in the last United States, with a drop by around 5% quarter. Gas use in 2008, at 61 bcm, was between 2007 and 2008. Canadian gas only marginally up on 2007. exports to the United States are likely to remain weak for the next couple of years Domestic production due to increased United States domestic production and new infrastructure (e.g. The average monthly year-on-year increase Rockies Express Pipeline). Canadian gas in natural gas production in the United production is projected to peak in 2011 at

1. E.g. several ethanol producers have fi led for bankruptcy including VeraSun, the United States’ second largest producer. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 150

Figure 18 North American production

60

bcm 50

40

30

20

10

0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 United States 2007 United States 2008 United States 2009 United States 2006 Canada 2007 Canada 2008 Canada 2009 Canada

Key point: United States output grows strongly

Source: IEA. around 187 bcm, and then decline, but this Low prices combined with the tightness will depend on the future development in credit has and will continue to lead of the Mackenzie Delta and of coalbed to reduced drilling activities. Still, some methane production, both of which may companies already have commitments become important supply sources. for rigs, or there may be other factors preventing immediate shutdowns and In the United States, the recent production cutbacks. According to data published by growth has been driven by unconventional Baker Hughes2, the total number of rigs gas. This development has been made drilling for gas in the United States peaked possible due to high natural gas prices at 1606 in September 2008 but was down through most of 2008 and improved to 711 end of May 2009. In particular, technology, especially in the area of shale North American demand for drilling more gas. The high-price environment created complex horizontal wells3 soared 40% the incentives for major investments in during 2008 peaking in October with a drilling programs and there was a signifi cant weekly number of 650 rigs. The number increase in the number of horizontal rigs. of rigs drilling horizontal wells started to decline in the last quarter of 2008 as the

2. US rig report for May 1, 2009. Current and historical data, Baker Hughes. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 151

Figure 19 Average weekly rigs in North America

1 100 1 000 900 800

Number of rgis 700 600 500 400 300 200 100 Jan-06 Apr-06 Jul-06 Oct-06 Jan-07 Apr-07 Jul-07 Oct-07 Jan-08 Apr-08 Jul-08 Oct-08 Jan-09 Apr-09 Direct Horizontal Vertical

Key point: Low prices led to a significant fall of the number of rigs

Source: US Rig Report for May 1, 2009 - Current and historical data, Baker Hughes.

economic downturn and sharply decreased shale gas and coalbed methane), following prices took their toll and was down to 375 the trend seen in recent years. This growth in May 2009. The numbers for vertical rigs will be led by shale gas (e.g. from Barnett, fell, for the fi rst time, below the number for Haynesville, Fayetteville and Marcellus). The horizontal rigs as of end-March 2009. This share of unconventional natural gas in total is the result of producers shutting down natural gas production is set to increase. the rigs drilling less economical, vertical Many of the unconventional gas plays are wells fi rst. Horizontal rigs are typically commercially viable at prices of USD 4-5 per used to develop unconventional gas MBtu and in specifi c areas the threshold is resources, where decline rates are steeper estimated to be as low as USD 2-3 per MBtu. than for conventional gas, meaning that As noted above, there has been a steep the producers have to keep drilling to reduction in the rig counts in early 2009, but maintain production levels. the largest share of the reductions has been in the vertical rig count as producers have shut Most of the growth in natural gas down the less effi cient, more costly rigs in the production in the United States will come less prospective areas fi rst. This has to some from unconventional natural gas (tight gas, extent, balanced the production picture as

3. Both oil and gas drills. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 152

the rigs kept in operation have a higher production, if it occurs, will thus depend degree of effi ciency in combination with on both national and international market being moved to areas with better prospects. forces. As noted above, some of the unconventional gas can survive prices Notwithstanding these declines in drilling, down to USD 2-3 per MBtu, and is therefore gas output in early 2009 continued to able to compete with or reduce the levels increase by around 4%. Nonetheless, it of LNG that are potentially available to seems very likely that this fall in the the US gas market (see section on the rig count will lead to a slowdown in gas Development in the LNG markets). production. The actual effect on the production level will depend on various The average weekly number of rigs drilling factors making it hard to predict. A decline for gas in 2007 in Canada fell signifi cantly in production would normally push the from the 2006 numbers, ending at 215, down price for natural gas upwards (assuming from 361 rigs, and increased only modestly in demand also recovers) and thus lead to 2008 to 220. It has been down to 40-50 since an eventual recovery in drilling. The price late April 2009. Most of the drilling in Canada picture will also be affected by external took place in Alberta, closely followed by forces, through the LNG imports planned British Colombia. The production of natural for the United States. A recovery of

Figure 20 Annual LNG imports to the United States

3

bcm

2.5

2

1.5

1

0.5

0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2006 2007 2008 2009

Key point: LNG imports divided by two between 2007 and 2008

Source: IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 153

gas in Canada declined from 188 bcm in 2006 Norway to 175 bcm in 2008. „ Norway is the IEA’s second biggest gas Again developments in Mexican gas exporter, 93 bcm by pipeline in 2008; in output mirrored those seen in a number of addition Norway will export 6 bcm per producing countries. Growth was strong year of LNG from the Snøhvit facility in 2006 and 2007, at double-digit rates, when it reaches full production. continuing into 2008. But falling prices have seen growth disappear, leaving „ Gas production at 100 bcm in 2008 is output fl at in the latter part of 2008 and set to rise to between 115 and 140 bcm early 2009 compared with a year earlier. within the next decade. Total output in 2008 was still up a healthy 4.4% over the previous year, at 58 bcm. „ Acreage releases will be necessary to attain this production objective. Supply balance „ Pipeline systems need to be expanded Total natural gas imports to the United and extended if export goals are to be States reached a record high of 130 bcm in reached. 2007. The 2008 level is down by almost 14% compared to the 2007 level, at 113 bcm. Since Norway is the second biggest exporter March 2008, imports from Canada have been of gas to Europe, behind Russia but generally lower than 2007, culminating in ahead of Algeria. While oil production on December 2008 when they were 12% below the Norwegian Continental Shelf (NCS) December 2007. LNG imports in 2008 were has shown a falling trend, natural gas particularly affected as they fell by 54% to production has been increasing steadily just under 10 bcm compared with a record from 77 bcm in 2003 to 100 bcm in 2008, level of almost 22 bcm in 2007. The recent a 10% increase over 2007, continuing this price situation together with the increase growth in 2009. 60 fi elds on the NCS are in domestic production in the United States currently producing, 11 fi elds are under has had global implications through the development and 73 discoveries await LNG trade; LNG volumes previously planned appraisal. During 2008, about every second to meet United States’ needs are now exploration well resulted in a discovery available to other markets (see section on and in total, 25 oil and gas discoveries the Development in the LNG markets). The (15 gas discoveries) were made on the United States is a net exporter to Mexico. NCS, resulting in a record year4 adding Imports from the United States increased 49-97 bcm of recoverable gas. The largest by 25% between 2007 and 2008 while share of the gas discoveries were made in exports declined by 20%. the Norwegian Sea.

4. To compare, 12 discoveries were made in 2007 (NPD). 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 154

Figure 21 Norwegian gas production 2002-09

12

bcm 10

8

6

4

2

0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2002-07 range 2006 2007 2008 2009

Key point: Norwegian gas output increased strongly in 2008 and early 2009

Source: IEA.

Most exports are via pipeline to Europe but was established in 2001 to manage the Norway started to export LNG in 2007 from state’s direct fi nancial interest (SDFI)5. the offshore arctic fi eld of Snøhvit and can Gassco operates the pipeline system from now reach the Asian and North American the fi elds to the European markets on markets. The last major development in the behalf of the owners grouped in Gassled. Norwegian pipelines network was the 25 bcm Gassled was established in 2003 as a joint Langeled pipeline to the United Kingdom venture of oil and gas companies operating which came on stream in October 2007. The on the NCS. For 2008, the Ministry of 7 bcm Tampen Link connecting the Statfjord Petroleum and Energy offered production fi eld with the existing Far North Liquids and licenses to 40 companies of which 26 Associated Gas System (FLAGS) was offi cially were foreign. Of these 40 companies, opened the same month. 19 companies were offered operatorships, including 15 foreign6. StatoilHydro is the main player on the NCS. Petoro, a state-owned limited company,

5. In 1985 Statoil’s NCS licenses were split in two. Statoil was allowed to keep one half and the SDFI was given the other half. 6. BG Norge AS, Centrica Resources Norge AS, ConocoPhillips Skandinavia AS, Dana Petroleum Norway AS, Dong E&P Norge AS, Eni Norge AS, Lotos E&P Norge AS, Lundin Norway AS, Maersk Oil Norway AS, Marathon Petroleum Norge AS, Nexen Exploration Norge, OMV Norge AS, Premier Oil Norge AS, Talisman Energy Norge AS and Wintershall Norge AS. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 155

Gas sales exploration for gas and the development of new fi elds such as Ormen Lange and Gassco transported 93.3 bcm of Norwegian Snøhvit is expected to continue. Although gas to European terminals during the gas the Norwegian Ministry of Petroleum year 2007-08, 9 bcm more than the previous and Energy expects NCS oil and gas gas year. StatoilHydro sold around 80 bcm production to fall after 20159, gas should during that period, including the group’s exceed falling oil production in 2013 and own production (around 39 bcm), third- reach a production level between 115 and party gas and gas sold on behalf of the 140 bcm within the next decade. SDFI. StatoilHydro is the second biggest gas supplier in Europe and the sixth Sustainability is an important issue in biggest in the world7. Norway. The emission level from gas production in Norway is lower than in other Norway’s biggest markets are Germany, the oil and gas producing countries. This has United Kingdom and France. Domestic gas been achieved through innovative work usage in Norway is insignifi cant compared such as removing CO2 from gas produced to exports, at less than 7 bcm in 2008, up in the Sleipner fi eld and reinjecting it 26% from 20078. The largest consumer of into a deep geological layer below the gas domestically is the Tjeldbergodden Sleipner platform. A CO2 offshore tax was methanol plant. The 420 MW gas-fi red introduced in 1991, and currently amounts power plant at Kårstø which started in to USD 50 per tonne. Furthermore, the November 2007 has hardly been used Norwegian government aims at increasing due to high short-run marginal costs and its effort regarding carbon capture and declining electricity prices. The low gas storage (CCS), in particular on the Kårstø prices observed since early 2009 combined power plant and Mongstad refi nery. with the collapse of CO2 prices resulted in a restart of the plant in February 2009. Investment in exploration and production will be crucial to reach production Supply outlook and Infrastructure targets. Statistics Norway (SSB) development estimates 2009 total investments10 for oil and gas production will amount to Norway is likely to continue to play an NOK 137.4 billion11. Although they have important role as a gas supplier to European been adjusted down from previous gas markets as Europe is expected to estimates due to tough economic become increasingly import dependent conditions, they are still higher than last and aims to diversify gas supplies. Increased year’s investments of NOK 123.9 billion.

7. The group sells gas to customers in Germany, France, Belgium, Italy, the Netherlands, the UK, the Czech Republic, Austria, Spain, Denmark, Ireland, Norway, Azerbaijan, Georgia, Turkey and the USA. 8. OECD data. 9. Development of production on the Norwegian Continental Shelf”; KonKraft report 2, December 2008. 10. First quarter 2009. 11. 1 USD = 6.5 NOK (May 2009). 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 156

In 2009 investments in exploration (and with the Norwegian Parliament (the concept studies) alone are expected to Storting). reach NOK 29.2 billion (EUR 3.3 billion). „ The current export capacity stands at Norway’s long-term role as a major gas 120 bcm compared to a production level supplier to Europe will depend on two key close to 100 bcm in 2008. Transportation factors: capacity is thus a limitation for the new gas coming from the Norwegian Sea „ The potential opening of new areas and needs to be debottlenecked. on the NCS for oil and gas activity, in particular offshore Lofoten and The plan to build a pipeline from the Troll Vesterålen which have been closed for fi eld to Europe was shelved in November exploration activity. The decision lies 2007, when the Norwegian government announced that it would not support the

Map 15 Norwegian gas infrastructure Existing gas pipeline Planned or under construction gas pipeline Gas production area Haltenpipe Tjeldbergodden Nyhamna

Langeled Tampen Asgard link Transport Pipeline NORWAY Kollsnes St Oslo SWEDEN at pi pe Flags Kårstø Stockholm Vesterled Zeepipe IIA e Zeepipetpi IIBp Sta

E

u r Skanled o p Bua St. Fergus i p e Ålborg

I I North Sea Baltic Sea DENMARK Copenhagen d

e Z

l e

e e

g

p F

n i

r N p

a a o e

L n r RUSSIA Teesside pi

p p

I e

i

p e Easington Dornum Dublin Emden UNITED Bacton IRELAND BBL THE NETH. KINGDOM Intercon- Berlin nector Amsterdam Warsaw London GERMANY Zeebrugge POLAND Dunkerque 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: Petroleum Economist, IEA, company announcements. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 157

Troll Future Development plans to increase Netherlands gas production from the fi eld12 due to a possible negative impact on future liquids „ The Netherlands has the highest gas use production. of any IEA economy, as a percentage of total primary energy supply. Norway has been considering a 843 km pipeline from Kårstø to Grenland and „ Gas provides around 60% of the then to the Swedish west coast and to Netherlands power output, and in the Denmark, the Skanled gas pipeline. It could short-term new gas-fi red capacity is be extended to Poland (the Baltic Pipe). being constructed. The export capacity would be 24 Mcm per day up to Grenland and 20 Mcm per day „ The Netherlands remains a signifi cant afterwards. Bringing gas to Grenland has exporter of gas with an important been favoured by politicians and industrials ability to meet sharp demand swings. such as Yara International. In February 2009, Petoro reached an agreement on The discovery of the Groningen fi eld behalf of the Norwegian government to 50 years ago enabled the Netherlands to take up to 30% share in Skanled whereby move away an energy economy dominated Østfold Energi and Agder Energi would by coal and oil. Within 10 years, three transfer their respective shares; while quarters of the population had been Skagerak Energi’s stake would be reduced connected to gas, and within 20 years, 98% from 20 to 10%. Gasunie had agreed to of the population and most commercial join the project. and industrial users burnt gas. Gas now represents 40% of primary energy The Skanled Project Group decided in demand – the highest in the IEA. The April 2009, to suspend the project, due to Netherlands is not only the fi fth largest increased commercial risk combined with consumer of gas in OECD Europe; it is the global economic developments that also a net exporter supplying pipeline gas have given an uncertain view on future gas to surrounding countries and a provider demand. The project might be re-launched of swing capacity to cope with seasonal if the commercial conditions become and other demand variations. However, more favourable in the future according the Netherlands is gradually entering a to Gassco. new period of development: as a result of the expected decline in production, it is expected to turn into a net importer within two decades. The Netherlands is seizing this opportunity to become a major transportation hub for the North West European region.

12. Holds about 10% of the oil and gas on the Norwegian Continental Shelf. By far the biggest Norwegian gas fi eld – it is four times the size of Ormen Lange. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 158

Recent market evolution by 30% compared to 1990 levels and to improve energy effi ciency levels by 2% Since the liberalisation of the Dutch annually (compared to 0.9% currently). gas market in July 2004, the market has These targets will tend to put downward been increasingly dominated by large pressure on gas demand in most sectors, international players, mostly by means but uncertainty prevails in the power of acquisitions of smaller Dutch utility sector. companies. In 2008-09, this trend of consolidation continued with the planned In the household sector, the Energy takeover of Essent by RWE and of NUON Performance Coeffi cient for new build by Vattenfall. Only Eneco and Delta remain houses, improved insulation, and independent Dutch utility companies, competition from all-electric houses in while Gasunie took over BEB’s transmission the new build segment will contribute network creating the fi rst supranational to the declining trend. Demand in the transmission company. commercial sector will be affected by boiler replacements, improved insulation The Minister of Economics plans additional and a decrease in the working population. measures to further improve liquidity, Demand in the industrial sector is expected among which are a simpler balancing to remain rather stable or slightly decline regime, an improved access to cross- due to increased energy effi ciency. border capacity and the offering of quality conversion as a system service. In the power sector, between 16 GW and 17 GW of new capacity is planned, Demand exceeding by far demand growth – noting that the Netherlands imports about one- In 2008 total Dutch gas consumption fi fth of its electricity needs. In the short totalled 50 bcm, some 7.9% higher term to 2011, most of the new capacity than in 2007 due to a colder winter. The under construction is gas-fi red – around Netherlands has a mature natural gas 2.8 GW compared to total generating market with the highest penetration capacity of 20 GW. But there are also rate in OECD Europe and as a result 2 GW of renewables, mainly wind and little room for expansion. Consequently for the period 2011-14 around 5 GW of the consumption of natural gas in the coal-fi red capacity is planned. However, household, commercial and industrial the economic recession, the tight credit sector has been gradually decreasing market added to a strong opposition due to technology improvements and from environmental organisations might effi ciency savings. An exception is power endanger the (timely) realisation of some generation where close to 60% of power of these projects. is gas-fi red and is expected to grow. Domestic production Future gas consumption depends heavily on environmental policies as the Netherlands On 1 January 2008, the remaining plans to reduce its GHG emissions by 2020 reserves in the Netherlands amounted to 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 159

Table 21 Power plant projects in the Netherlands

Location/Name Company Capacity (MW) Primary fuel Planned start-up Status

Eemshaven/ Nuon (1st unit) 350 Gas/coal 2011 Construction halted Magnum Eemshaven/ Nuon (2nd unit) 850/1 050 Gas/coal 2014 Permit Magnum Borcele/ Delta 870 Gas 2009 Construction Sloecentrale Lelystad/ Electrabel 900 Gas 2009 Construction Flevocentrale MaasStroom/ Intergen 419 Gas 2010 Construction Maasvlakte Schoonebeek NAM 130 Gas 2010 Construction Maasvlakte Unknown 600 Gas 2011 Unknown Moerdijk Essent 430 Gas 2011 Construction Maasbracht/ Essent 640 Gas 2012 Construction Clauscentrale Maasvlakte Enecogen 840 Gas 2012 Permit (FID Q2 2009) Eemshaven Advanced Power 1 200 Gas 2013 Permitting Bergum Electrabel 454 Gas 2014 Planned Eemshaven Electrabel 125 Gas 2008 (?) Unknown Amsterdam Nuon 500 Gas Unknown Planned Diemen Nuon 500 Gas Unknown Planned Maasvlakte E.ON 1 050 Coal/biomass 2012 Construction Maasvlakte Electrabel 800 Coal/biomass 2012 Permit

Eemshaven RWE (1st unit) 800 Coal/biomass 2013 Permit

Eemshaven RWE (2nd unit) 800 Coal/biomass 2014 Permit Geertruidenberg/ Essent 800 Coal/biomass 2014 On hold Amercentrale Sas van Gent Delta 82 Biomass/gas 2010 Unknown Delfzijl Aldel 115 Biomass/gas 2014 Planned Source: Tennet and companies websites.

1 390 bcm of which 1 075 bcm were from of OECD Europe supply. Since 1974, the the Groningen fi eld, 117 bcm from onshore government has applied a total production small fi elds and 198 bcm from offshore small cap and the “small fi elds” policy in order fi elds. The Netherlands produced 85.7 bcm to develop as many of the smaller gas in 2008, up by 11.8 % from 2007. 54% was fi elds as possible, given them priority over produced by the Groningen fi eld and 46% production from the Groningen fi eld. This by the small fi elds. This represents 14% has contributed to a large increase in the 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 160

small fi elds’ output and to the development competition from offshore wind parks. of offshore gas. This policy proved highly Finally, compression work is being done on successful since up to now around 36% the Groningen fi eld within the Groningen (1.1 tcm) of all produced gas (3.0 tcm) in Long Term (GLT) project: in order to the Netherlands originated from fi elds maintain reservoir pressure, a total of other than Groningen. Exploration activity 460 MW of compression will be installed has been nevertheless declining in the by end 2009. Netherlands with only 12 wells drilled in 2008, although seven new gas fi elds started Supply balance producing. Consolidation has also been taking place in the upstream sector: NUON The Netherlands started exporting gas acquired Conoco Phillips’ Dutch subsidiary to Germany in 1964 and since then total Burlington, GDF SUEZ took over a large part exports have been increasing. Exports of NAM’s assets in the Netherlands; and in 2008 increased by 8% to 60 bcm due Total acquired Talisman’s Dutch subsidiary to colder weather. Exports were sharply Goal Petroleum Nederland B.V. weaker in the last quarter of 2008 but showed a sharp increase in January 2009 Dutch gas production is expected to start from colder weather and the disruption to decline in the next years, especially of Russian supplies. In January 2009, net the production from the small fi elds. exports were 40% higher than January In the near term, this decline can be 2008. partly compensated by an increase in the production from the Groningen fi eld. The Netherlands now supply gas to However, the speed of production decline Germany, Belgium, France, Switzerland, will be partly determined by a successful Italy and the United Kingdom on the basis continuation of the small fi elds policy. of long-term contracts. With the contract In particular, offshore production is between GasTerra and Centrica starting time-constrained by the presence of the in December 2006, the Netherlands required offshore infrastructure and by started exporting gas to the United the fl exibility of the Groningen system Kingdom through a dedicated pipeline the for load factor conversion of the small Balgzand to Bacton pipeline (BBL). In 2008 fi elds’ gas. If most of the infrastructure is GasTerra prolonged the existing long- dismantled in around 15-20 years, reserves term agreement with E.ON Ruhrgas until have to be developed rapidly. Several 2028, supplying an additional 60 bcm. measures are already being taken. One is the handling of the so-called “sleeping” In parallel, the Netherlands started to concessions, where permit holders either import relative small volumes of pipeline perform exploration and production gas since the mid-seventies, which activities themselves or outsource them increased signifi cantly at the end of to third parties. Another includes fi scal the nineties with the start of market measures to make the exploration and liberalisation. The main exporters to the production of the marginal fi elds more Netherlands are Norway, Russia, Germany attractive. Another challenge is the and Denmark. In 2008, imports reached 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 161

Figure 22 Dutch gas balance 1960-2008

120

bcm 100

80

60

40

20

0

-20

-40

-60

-80 8 1960 1962 1964 1966 1968 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 200 Production Imports Exports Consumption

Key point: A major gas exporter but imports are increasing

Source: IEA.

25.3 bcm. As Gasunie is participating in the 4Gas and Taqa and another in Eemshaven Nord Stream pipeline, additional Russian by Essent, Gasunie and Vopak. It is likely volumes could reach the Dutch market. that another terminal will be built.

Infrastructure developments In 2007 the high pressure transmission grid owned by Gasunie consisted of The Netherlands aims to become a European 12 050 km and the local distribution grid hub for gas based on its central geographical of 123 635 km. A major number of projects position in Northern Europe, the existing are currently under way, enabling the transport and storage infrastructure, and concept of a gas roundabout. Gasunie the plans to develop further import and started in 2008 with the North-South transport infrastructure. project aiming at building 485 km of new pipelines by 2012. Four LNG terminals are planned, the most advanced being the GATE LNG terminal Next to these pipeline expansions, from Gasunie and Vopak. The terminal multiple storage projects are underway, in is under construction in Rotterdam and various phases of development. Currently scheduled for completion in 2011. Two other Gasunie and NUON are constructing four LNG terminals are planned in Rotterdam by salt caverns at Zuidwending. Further 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 162

Map 16 Gas infrastructure in the Netherlands

3.1(Emden) 10 (Eemshaven LNG) North Sea 1.5 (Grijpskerk) *

13.1/1.8 (OSZ) 0.7 (Zuidwending) 7 (Norg) 2.4 (BBL) Alkmaar 3.2 (Bergermeer)

0.7 (Epe) Amsterdam 9 (Liongas LNG) THE NETHERLANDS Winterswijk* 4 (Seahorse) GERMANY Zevenaar* 12 (Gate LNG) Rotterdam* Existing gas pipeline Under construction/ planned gas pipeline Hilvarenbeek* Under construction LNG import facility Planned LNG import facility 3.0/ 4.7 (Zelzate) Gas production area Existing underground storage Planned underground storage BELGIUM * < 3 shippers 4.7 0.7 H gas (‘s Gravenvoeren) (Bocholtz) L gas 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: Petroleum Economist, IEA. expansion of the German Epe salt caverns „ Gas-fi red power has been a major is planned13, as well as the expansion factor, increasing fi ve fold over the of the storages of Norg and Grijpskerk. period 2000-08. Finally Taqa is preparing a fi nal investment decision for a large new gas storage facility „ Spain is the number three LNG consumer in the depleted gas fi eld of Bergermeer. globally; this has been a major means of diversifying gas supply from more than 70% dependence on one supplier in 2000 Spain to around 32% dependence in 2008.

„ Spain has seen a sharp increase in gas Spain is the sixth largest European gas consumption of 65% over the period consumer and has been one of the fastest 2003-08. growing gas markets in Europe. Natural

13. Basically Dutch storage, as it is only connected to Dutch grid. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 163

gas’ share in the country’s Total Primary The liberalisation of the gas market has Energy Supply in 2007 was 21.8%, slightly been particularly impressive. In 2007, the below OECD countries’ average. Gas liberalised market represented 88.5% of demand increased from 23.2 bcm in 2003 the total market compared with 11.5% to 38.2 bcm in 2008. for the regulated market. Many small users switched due to the progressive and Spain has been very successful in planned disappearance of the regulated diversifying its supply sources with market (and tariffs) in July 2008. A new LNG representing around two-thirds of system of last resource tariff and defi ned total supplies. Six LNG terminals are now time frame to 2010 for gradual reduction operational, representing a capacity of in the consumption threshold has been 58 bcm compared to 14 bcm for the two introduced for small users who had not gas pipelines from Algeria and France. switched after July 2008. Five last resort Spain is now looking at enhancing this suppliers have been appointed by the supply capacity as well as reinforcing the Government: Gas Natural, Iberdrola, interconnections with the wider European Endesa, Union Fenosa and Naturgas. market. Since end-2007, Spain has been working with Portugal on building an Iberian gas market – MibGas.

Figure 23 Spanish gas consumption 2000-08

45

bcm 40

35

30

25

20

15

10

5

0 20002001 2002 2003 2004 2005 2006 2007 2008

Key point: one of the fastest growing markets in OECD Europe

Source: IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 164

Gas demand of weaker electricity demand, higher hydro levels and increased wind output. Gas demand remains dominated by the Furthermore gas-fi red plants are higher industrial sector which accounts for 50% on the merit curve than nuclear, hydro of total demand, compared with 35% and wind, and for power generators with for power generation and 14% for the contracts with an oil linkage their plants residential and commercial sectors. are not competitive against coal. But industrial demand has remained fl at over the past years. Demand growth The power generation sector remains a was essentially driven by the power key consumer with growing potential; generation sector – where gas has gas-fi red power was forecast to grow become the fuel of choice – and to a from 95 TWh in 2007 to 141 TWh by 2016. lesser extent by the residential sector. Gas In 2007, 14 new CCGTs joined the system, penetration remains lower than in other totalling more than 5 GW of capacity countries with 6.8 million gas customers and in 2008 0.6 GW. Although demand is (out of a population of 44 million) but likely to be weaker in 2009, most power the connection of new households has plants under construction and planned been impressive increasing more than are gas-fi red or wind. Furthermore, Spain 60% since 2000. Between 2000 and 2007, has indicated a desire to reduce the share gas-fi red power increased nearly fi vefold, of nuclear power in the mix, currently at from 20 TWh to 95 TWh, equal to almost around 20%. all incremental power demand. During the past three years, total gas consumption Gas supply increased at 6% per year on average, largely driven by the new CCGTs coming on line. Spain imports more than 99% of its gas Demand increased by 11% to 38 bcm in needs and is the world’s third-largest 2008, driven by record consumption from importer of LNG. Less than 80% of imports the power generation sector during the are based on long-term contracts indexed fi rst quarter. Due to very low hydro levels to oil prices. The ratio of piped natural during winter 2007-08, gas-fi red plant gas to LNG deliveries has been declining utilisation increased substantially and peak from “50% LNG-50% piped gas” structure daily gas demand broke several records. in 2000. A signifi cant increase of LNG volumes was observed up to 2007, when However, demand has considerably 68% of total import was supplied as LNG, weakened during the last quarter of 2008, 32% as piped gas. and especially the fi rst quarter of 2009 according to the state-owned TSO Enagas, In 2008, 32% of gas was imported from which reported a 31% consumption decline Algeria – both pipeline and LNG, followed from power generators and a 9% decline by Nigeria with 20%, Qatar with 13%, from other sectors, for a total demand Trinidad and Tobago with 12% and Egypt decline of 17%.This is due to the economic with 11% and Norway with 7%. Norway crisis impacting industrial demand, and started exporting LNG in 2008 but most for the power sector, to a combination supplies are still pipeline gas. Algeria’s share 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 165

Figure 24 Evolution of Spanish gas supply

45

bcm 40

35

30

25

20

15

10

5

0 2001 2002 2003 2004 2005 2006 2007 2008 Norway Algeria Libya Nigeria Oman Qatar Trinidad and Tobago Others

Key point: Rapid diversification of supply sources

Source: IEA. has declined signifi cantly from 70% in set aside for short-term contracts, less 2001 while Spain has remained the second than two years long14. This often results largest market for Algerian gas. The arrival in under-utilisation of the LNG terminals: of gas from the Medgaz pipeline (8 bcm the Barcelona, Huelva and Cartagena annually, by mid-2009) will raise this share, terminals operated by Enagas were used although some gas may also fl ow north at 30-40% in 2008, compared with 50%- into France, The Royal Decree 1766/2007 70% for the other LNG terminals Bahía de limits imports from one single country to Bizkaia, Reganosa and Sagunto. a maximum of 50% compared to 60% in the previous Royal Decree 1716/2004. Infrastructure development

Spain has been able to attract many spot According to the Hydrocarbons Sector LNG cargoes in the past due to TPA to key Law (1998), energy planning is mandatory infrastructure. A quarter of the capacity of for basic gas infrastructure. The last regasifi cation, storage, transportation and Strategic Plan 2008-16 was adopted in distribution system intake installations is 2008 by the government to provide a

14. “The utilisation rate of the LNG terminals is low because they are designed to deal with the demand peaks of the Spanish Gas System, which is characterised by a highly seasonal demand.” Source: country submission. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 166

stable regulatory framework and secure remain weak, with the exception of the enhanced investment in the development Spanish-Portuguese interconnection and of the grid. Spain is keen to develop both two existing connections with France at additional LNG terminals and pipeline Larrau – the 2.6 bcm Lacal pipeline used capacity. The last LNG terminal Reganosa for transit through France of Norwegian started in 2007 and most of the existing six gas, and Biriatou – the 0.5 bcm Euskadour LNG terminals are expected to be expanded line linking the Bilbao terminal to the by 2013. A new LNG terminal El Musel on TIGF network. The capacity of these the Northern coast is planned by Enagas interconnections is expected to be by 2011. Two additional LNG terminals enhanced in both directions and open would be located in the Canary Islands seasons are currently being conducted. (Tenerife and Gran Canaria). Furthermore, The enhanced co-operation of the French the Medgaz pipeline is expected to be and Spanish TSOs has been promoted operational in 2009, rebalancing the LNG- within the framework of ERGEG South pipeline capacity equilibrium. Gas Regional Initiative. It has resulted in launching of a joint Open Season Another key point is the development of Period in November 2008 as a part of international pipeline connections, which the commercialisation of the capacity

Map 17 Spanish gas infrastructure Musel Canary Islands Reganosa Bilbao Gaviota FRANCE Santa Cruz Oviedo de Tenerife S. Sebastian Las Palmas Larrau

Pontevedra Leon Serrablo Orense Burgos Logroño

Barcelona Zamora Zaragosa

Atlantic Yela Madrid Castor Mediterranean Sea Ocean PORTUGAL SPAIN Sagunto Valencia Palma de Mallorca

Alicante El Ruedo Cordoba Las Barreras Lorca Existing pipeline Marismas Under construction/projected/ Poseidon Almeria Cartagena planned pipeline Huelva LNG import facility + extension

M

E Mediterranean Sea

D Planned LNG import facility

G A Existing underground storage Z ALGERIA MAROCCO Planned underground storage 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: Petroleum Economist, IEA, company announcements. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 167

in existing (after application of the TPA 39% for new entrants. Gas Natural’s share rules) and planned capacity. A third of the total gas market dropped from 64% interconnection project to the eastern in 2002 to 48% in 2007. One of the main side in Catalonia (MidCat project) is at features was the gas-power convergence the planning stage and aims at building a with existing gas incumbents entering 13.5 bcm bi-directional pipeline by 2015. the electricity market through increased gas-fi red fl eet and vice-versa. Gas Natural Spain also lacks underground storage has been the most successful entrant into with only two underground storage the electricity sector. facilities, both depleted gas fi elds operated by Enagas, in Gaviota and Most of new entries to gas and electricity Serrablo representing a total capacity of markets have taken place through mergers 2 166 Mcm – around 6% of annual demand, and acquisitions of existing companies. In which is low compared to other countries. 2004 EDP took over Hidrocantabrico; in Shippers are therefore obliged to keep 2007 – Enel and Acciona took over Endesa stocks of an amount equivalent to 20 days’ (after previous failed attempts by Gas of their sales/consumption. Therefore, new Natural and E.ON). Gas Natural is acquiring underground facilities are planned: Enagas the country’s third biggest power group has been awarded an administrative licence Union Fenosa. Due to increasing concerns to convert a third depleted gas fi eld, at on market concentration, the Spanish Yela. Yela has a capacity of 1.05 bcm and competition authority decided that Gas should be operational by 2011. Three Natural must dispose of 600 000 small gas other projects Castor, Marismas and clients and sell 2 GW of gas-fi red capacity. Reus are currently under development Gas Natural is also committed to selling and will double storage capacity, up to its stake in Enagas and reducing its links 5.76 bcm by 2016, accordingly to the latest to Cepsa by standing down from the oil infrastructure plan. group’s board.

This modest underground storage But liberalisation has also benefi tted capacity necessitates using LNG storage incumbent companies with well developed at the terminals. This capacity is also to distribution networks. Around 70% of be expanded; for example Barcelona, customers remained loyal to the retailer Cartagena, Huelva, Sagunto Terminals are affi liated to the same vertically integrated going to add storage tanks of 150 000 m3 each. group of the distributor. “Dual fuel” offers of combined electricity and gas deliveries, Market developments popularised by Gas Natural and electricity companies (Endesa, Iberdrola and Union The Spanish market has witnessed major Fenosa) have resulted in a limited rate recent developments in terms of gas (14%) of total deliveries supplied by the industry structure. First of all, liberalisation energy marketers. increased the number of active traders to 14: in 2007 the incumbents represented 61% of the liberalised market compared to 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 168

Turkey economic growth and high industrialisation phase. Between 2000 and 2007, GDP grew by „ Turkish gas demand has grown at a nearly 40%, even allowing for the banking rapid 63% in the period 2004-07, but crisis of 2001 when GDP declined 7.5%. in late 2008 demand declined sharply. Natural gas has met a major part of Turkey’s rapidly growing energy needs, rising from „ Turkey has a high level of gas-fi red 6% of supply in 1990 to more than 30% in power – more than half – and while 2007. Between 2000 and 2007, it doubled there are major plans for a more diverse its share, representing in absolute terms a power mix, gas-fi red power will still 150% increase, so that gas demand is now double in absolute terms over the next comparable with that of Spain. decade. Gas demand „ More than 60% of Turkey’s gas comes from Russia via two pipeline routes; In common with most OECD gas diversifi cation in new supply is highly consuming countries, the fi rst half of desirable. 2008 saw strong demand growth, (more than 11% in the fi rst quarter) with growth Turkey is a rather atypical OECD member levelling off in the summer, and demand country, as it is currently undergoing a high contractions becoming marked late in the

Figure 25 Turkish annual gas use

40

bcm 35

30

25

20

15

10

5

0 2000 2001 2002 2003 2004 2005 2006 2007 2008

Key point: 63% growth over 2004-08

Source: IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 169

year, especially in industrial use. Demand industrial demand which has multiplied by levels in the three months ending January four during 2000-08. With the fast growth 2009 were down by nearly 11% from of the Turkish economy, increasing corresponding months a year earlier. Total population and rising living standards, demand growth was only 1.6% to a level electricity demand is growing at a high of 37 bcm for 2008, marking an abrupt halt rate: electricity consumption increased to the rapid growth that saw gas use rise by 50% over 2000-07. It is expected that 63% between 2004 and 2007. First quarter the temporary decrease in consumption of 2009 demand fell 18%. due to the economic downturn in 2008-09 will not change the long-term trend and Gas has been especially important in the that – based on conservative projections power sector, rising from barely one-sixth – electricity consumption will double by of generation in 1990 to half in 2007, in 2020. This will require at least doubling absolute terms a tenfold increase. In the installed generation capacity which residential and commercial sector, over the represents an unprecedented challenge same period, gas went from zero to one- among OECD member countries. While third of demand, mostly for heating due the share of gas-fi red power is forecasted to the gasifi cation program implemented to decline, with more coal, hydro, wind by BOTAS¸. This has also benefi tted and the introduction of nuclear in the mix,

Figure 26 Turkish gas use 2007-09

4 000

Mcm 3 500

3 000

2 500

2 000

1 500

1 000

500

0 Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 2003-08 range 2007 2008 2009

Key point: Sharp contractions at year’s end continue in 2009

Source: IEA. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 170

gas-fi red power is still expected to nearly that currently around two-thirds of gas double in absolute terms over the period supply comes from one supplier, Russia, 2008-3015 . Delays in any of the alternatives via only two pipeline routes, security of will exacerbate increases in gas-fi red supply concerns dominate gas (and to a capacity, which is particularly favoured by lesser extent electricity) policy thinking. private sector power generators. The Russia-Ukraine dispute in January 2009 exacerbated these concerns. Other import Gas supply infrastructure includes two LNG terminals, the 7 bcm South Caucasus pipeline which Turkey has a high level of dependence on started delivering Azeri gas in 2007 and a imported energy. Only lignite, some oil, 10 bcm pipeline from Iran. and a very small amount of gas and hydro are domestically produced. Security of In absolute terms, gas imports were supply thus features highly in Turkey’s multiplied by 2.5 from 2000 to 2008, and energy policy priorities. Virtually all gas notwithstanding the current recession, is imported, a circumstance unlikely to energy demand is expected to grow change over the forecast period. Given strongly, and gas imports to double again

Figure 27 Turkey’s long-term contracts vs. demand

60

bcm 50

40

30

20

10

0 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 2020 2022 2024 Russia (West) Algeria (LNG) Nigeria (LNG) Iran Russia (West 2) Russia (Blue Stream) Azerbaijan Demand

Key point: New contracts or extension of the existing ones is needed

Source: BOTAS¸.

15. According to BOTAS¸’ scenario. 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 171

between 2008 and 2030. Meeting this Turkey’s gas sector is in the process of demand for imported gas to 2020 will liberalisation, started in 2001. But progress require very heavy investment in additional remains very slow in contrast to the pipeline and LNG terminal capacity, plus electricity sector, although there have been extra commercial storage. Current total some recent important changes. While storage amounts to only 1.6 bcm at two this may have been because of unrealistic facilities, too small for current demand, let goals in 2001, revitalised gas reform is alone to meet the increase in the power now urgent if necessary investments are sector, with its potentially sharp variations to be made and new gas supply secured. in demand. Even allowing for much slower Progress has been made in allowing prices growth over 2009 and into 2010, this new to move to more market-oriented levels, supply infrastructure is still needed quite with prices rising in 2007, and increasing soon, given the lead times in the sector. In some 80% in 2008. BOTAS¸, the state- addition, some existing supply contracts owned vertically integrated gas utility, begin to expire in coming years, meaning continues to occupy a dominant position new ones need to be concluded again in in the wholesale market, with at least 90% the next few years (see fi gure 27). of the market. The situation has slightly improved with the removal of restrictions Fortunately, Turkey is well placed with on importing LNG, effective use of the respect to major gas reserves in Russia, Iran, second LNG terminal (still underutilised), Iraq, Egypt, the Caspian region (Azerbaijan) and allowing third parties to import into and Central Asia (Turkmenistan). LNG LNG terminals. These provisions were supplies are also potentially available, as a hurting security of supply; their removal is near 50% increase in global LNG output is a positive step. But the market dominance anticipated in the next few years, notably of BOTAS¸, and in particular its de facto from Qatar (and indeed spot LNG supplies monopoly with regard to pipeline imports were one important means used to alleviate and its control over the transmission the impact of the interruption to gas system, are likely to render these reforms supplies in January 2009). Pipelines bringing insuffi cient. According to the 2001 law, gas from Middle East or Central Asian BOTAS¸’ share of imports was supposed to sources could be extended further, to meet be limited to 20% by 2009, to be achieved growing demand in Eastern and Western through a gas release program. After the Europe, and diversify supply sources for release which was postponed several all countries concerned. Indeed Turkey is times, to 2006, only 4 bcm (around 10% of a logical, potentially very signifi cant gas the market) was released. transit country. Gas from the Turkish grid already fl ows to Greece as of late 2007. Thus, Fortunately, market circumstances present looking at the Turkish gas scene, priority a major opportunity to press ahead, needs to be given to stimulating timely addressing market reform and security of investment, from diverse supply sources, supply concerns simultaneously. Growing and from a diverse range of entities. demand, plus declining contracted import supplies, should allow large new market entrants, such as major Turkish industrial 2009 OECD/IEA, © Natural Gas Market Review 2009 • OECD countries and regions 172

companies, international or national above trading conditions are met, namely energy companies. There is some surplus multiple sources (including storage) and capacity at existing LNG terminals, but markets, easy access to transport, and low terminal capacity would need to be transaction costs, within a stable, non- expanded to realise the full diversity and discriminatory regulatory framework. security benefi ts that LNG could provide. In short, non-commercial risks must be For any new entrants to appear, barriers to minimised, and the differences between entry need to be reduced, and new entrants gas and oil clearly recognised. will need to have complete confi dence in third-party access to an independently Under these circumstances, it should be operated transmission network (hitherto possible to address long-term security not available). This implies the full legal of supply in Turkey through the classical separation of BOTAS¸ import and trading means of diversity of sources and routes; operations from its transmission/pipeline short-term security issues should be operations, a step envisaged in 2001, but addressed through a suite of emergency yet to be enacted. style measures. Other OECD countries have utilised these approaches very successfully, Leaving aside LNG imports, additional such as Spain, limiting the market share of pipeline capacity will be necessary. individual suppliers, and rapidly developing Building large long distance pipelines is a diverse group of LNG suppliers and capital intensive, and requires long lead terminals, supplementing existing and times. Such investment will obviously be expanded pipelines, giving a resilient, diffi cult in the next few years in current fl exible, secure, competitive supply base. fi nancial circumstances. Attracting pipeline Incentives for LNG terminal development investment is most successful where gas (possibly through the regulatory system) regulations, laws and policies are stable, might assist this process in Turkey. Short- transparent, with the greatest degree term loss of supply should be met through of regulatory harmonisation along the measures such as using the fuel switching pipeline route. This is especially true where fl exibility in the power or industrial sector, pipelines cross multiple national frontiers or interruptible supplies, or spot LNG. (e.g. pipelines crossing Georgia or Syria) Increased commercial storage could also or those transiting to Greece, Bulgaria be important here. Careful evaluation of or further afi eld. Distortions between the large-scale interruption in January 2009 pipelines serving domestic needs and would yield further insights into how Turkey transit should be avoided. Pipeline tariffs might cope in the future. In particular, need to be cost based, kept to a minimum, advance preparation by the government, and third-party access available to facilitate large users (such as the power sector), multiple market-based entrants and distribution companies and all interested users. In addition, Turkey has legitimate parties is an important lesson from January aspirations to create a liquid gas trading 2009. A fl exible power sector which can market, (supplementing its role in oil) switch fuel in response to market or other with the fl exibility and competitiveness signals, is especially useful; thus Turkey’s benefi ts that that would entail. Such high level of gas-fi red power can be turned operations are most successful where the from a vulnerability to an opportunity. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Annex 1 173

ANNEX 1: ABBREVIATIONS

ABS Asset-backed securities E&P Exploration and production ADP Annual delivery program EBRD European Bank for ALNG Angola LNG project Reconstruction and AUD Australian dollar Development b/d Barrels per day ECA Export credit agency BBL Balgzand-Bacton Line EFET European Federation of Energy bbl Barrel Traders bcf Billion cubic feet EIA Energy Information bcm Billion cubic metres Administration, the United boe Barrels of oil equivalent States bp Basis points EPC Engineering, procurement and Btu British thermal unit, construction 1 Btu =1 055 joule, ERGEG The European Regulators’ 0.0002931 kWh Group for electricity and CBM Coalbed methane gas, set up by the European CCGT Combined-cycle gas turbine Commission CCS Coal capture and storage ETS Emission Trading Scheme CDO Collateralized debt obligation EU European Union CEGH Central European Gas Hub EUR Euro (virtual trading point in FEED Front-end engineering and Austria) design CHP Combined production of heat FERC Federal Energy Regulatory and power Commission, the United States CIF Cost, insurance and freight: a FID Final investment decision term of sales where the selling FOB Free-on-board: a term of sales price includes cost of goods, where the selling price that insurance and freight does not include shipping, CNG Compressed natural gas indicating the one at the CNOOC Chinese National Offshore Oil loading port. Buyers arrange Corporation shipping transportation. CNPC Chinese National Petroleum FSRU Floating storage and Corporation regasifi cation unit CNY Yuan (Currency of China) FSU Former Soviet Union CRE La Commission de régulation GBP Pounds (Currency of the United de l’énergie = national energy Kingdom) regulator of France GDP Gross Domestic Product CREG Commission de Régulation de GECF Gas Exporting Countries Forum l’électricité et du gaz = national GEODE European independent energy regulator of Algeria distribution companies of gas or national energy regulator of and electricity Belgium GHG Greenhouse gas CSM Coal seam methane = CBM GGP Guidelines of Good Practice DOE Department of Energy (US) GRI Gas Regional Initiative 2009 OECD/IEA, © Natural Gas Market Review 2009 • Annex 1 174

GSE Gas Storage Europe mtpa Million tonnes per annum GTE Gas Transmission Europe MW Megawatt (106 watts) GTL Gas-to-liquids MWh Megawatt hour GW Gigawatt (109 watts) NBP National Balancing Point (a GWh Gigawatt hour virtual trading point for gas in HDD Heating degree-days the United Kingdom) HOA Heads of Agreement NCS Norwegian Continental Shelf IEA International Energy Agency NDRC National Development and IFIEC International federation of Reform Commission, China industrial energy consumers NELP New Exploration Licensing IOC International oil company or Policy Indian Oil Corporation NGL Natural gas liquid IOGC International oil and gas NGV Natural gas vehicle company NIGC National Iranian Gas Company IPE International Petroleum NIMBY Not in my backyard Exchange, based in the United NIOC National Iranian Oil Company Kingdom NNPC Nigerian National Oil Company IPI Iran-Pakistan-India Pipeline NOC National oil company or Libya’s IPP Independent power producer National Oil Company ISO Independent system operator NOK Norwegian Krone IUK Interconnector UK NWS North West Shelf (an Australian JCC Japan Crude Cocktail, the LNG venture) average price of crude oil NYMEX New York Mercantile Exchange, imported into Japan in the United States kb/d Thousand barrels per day OCGT Open-cycle gas turbine kW Kilowatt (103 watts) OECD Organisation for Economic kWh Kilowatt hour Cooperation and Development LDC Local distribution company Ofgem Offi ce of Gas and Electricity LNG Liquefi ed natural gas Markets, the United Kingdom LPG Liquefi ed petroleum gas OGP International Association of Oil (propane, butane) & Gas producers LSTK lump-sum turn-key OPEC Organisation of Petroleum mb/d Million barrels per day Exporting Countries MBtu Million British thermal units OTC Over-the-counter Mcm Million cubic meter PEG Point d’Echange de Gaz (French mcm Thousand cubic meter gas hub) MENA Middle East and North Africa PNOC Philippine National Oil MJ Megajoule Company MOU Memorandum of PSA (PSC) Production Sharing Understanding Agreement (Contract) MPSC Model Production Sharing PSV Punto di Scambio Virtuale Contract (Italian gas hub) Mtoe Million tonnes of oil equivalent SCP South Caucasus Pipeline 2009 OECD/IEA, © Natural Gas Market Review 2009 • Annex 1 175

SDFI State’s direct fi nancial interest TSGP Trans Sahara Gas Pipeline SEIC Sakhalin Energy Investment TSO Transmission system operator Company TTF Title Transfer Facility SPA (SPC) Sale and Purchase TWh Terawatt hour Agreement (contract) UAE United Arab Emirates SSO Storage system operator USD United States dollar TAP Trans Adriatic Pipeline VP Virtual point TAPI Turkmenistan Afghanistan WAGP West African Gas Pipeline Pakistan India Pipeline WCSB Western Canada Sedimentary Tcf Trillion cubic feet Basin Tcm Trillion cubic meters WEO World Energy Outlook (IEA TENP Trans Europa Naturgas Pipeline publication) Toe Tonne of oil equivalent WTI West Texas Intermediate TPA Third-party access (benchmarkcrude oil in the United States) TPES Total primary energy supply 2009 OECD/IEA, © © OECD/IEA, 2009 Natural Gas Market Review 2009 • Annex 2 177

ANNEX 2: 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-load capacity Capacity of liquefaction plant or regasifi cation terminal that is expected to be processed in a year.

Base-load power Power supplied by generation units that run continuously.

Brownfi eld project Expansion project to an existing plant, or renewal project at existing plant.

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

Coalbed methane A type of unconventional natural gas, formed in the coalifi cation (CBM) or Coal seam process and found on the internal surfaces of the coal. To extract methane the gas water must be removed from the coalbed to reduce partial pressure. The large quantities of water, sometimes saline, produced from CBM wells pose an environmental risk if not disposed properly.

Combined Cycle Gas A system to generate electric power through a combination Turbine (CCGT) of steam and gas turbines. It burns fuel gas in compressed air and runs gas turbines with the resulting high-temperature combustion. The very high temperature exhaust gas from the gas turbines is suitable for input into a heat-recovery boiler, which in turn provides steam to the steam turbines. A gas turbine can reach its full running capacity in ten minutes from ignition, whereas a simple steam turbine needs more time to reach required temperature from steam. By combining the two, the CCGT system can start operations quicker than a steam-turbine power generation plant.

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

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

Dry gas Gas that does not contain heavier hydrocarbons or that has been

treated to remove heavier hydrocarbons. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Annex 2 178

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

Feedstock gas Gas used as raw material 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.

Heating Degree Day The number of degree days for one day is the difference between 65°F (18.3°C) and the average daily temperature for this day. They are a measure of the energy needed to heat buildings and helps comparing how much colder/milder a period is compared to the previous years.

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.

Hub Physical or virtual location where multiple natural gas pipelines interconnect or natural gas is assumed 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.

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, i.e. 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. 2009 OECD/IEA, © Natural Gas Market Review 2009 • Annex 2 179

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

Play A set of known or supposed accumulations of hydrocarbons sharing similar geologic properties, such as source rock, migration path, trapping mechanism, and hydrocarbon type.

Shale gas Natural gas that is produced from reservoirs predominantly composed of shale (a fi ne-grained sedimentary rock), rather than from more conventional sandstone or limestone reservoirs.

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 the indicator are slowed outside of a certain indicator range so that both buyers and sellers are partially protected from moves of the indicator outside a certain range.

Sour gas Natural gas that contains signifi cant amount of hydrogen sulphide.

Take-or-pay A clause in a gas (or an LNG) supply contract that dictates the seller shall receive payments from a buyer for a minimum quantity of gas (or LNG), irrespective of whether the buyer takes delivery.

Unconventional gas Unconventional gas is gas that is more technologically diffi cult or more expensive to produce than conventional gas. Unconventional gas resources can be divided into coalbed methane, tight gas, shale gas and methane hydrates. 2009 OECD/IEA, © © OECD/IEA, 2009 Natural Gas Market Review 2009 • Annex 3 181

ANNEX 3: CONVERSION FACTORS

Table 22 Conversion factors for natural gas price To: USD /MBtu USD /1 000 m3 USD / tonne USD / MWh USD / TJ From: USD /MBtu 1 37.912 51.56032 3.412 0.0009478 USD /1 000 m3 0.02638 1 1.3600 0.09000 0.00002500 USD / tonne 0.01939 0.7350 1 0.06615 0.00001838 USD / MWh 0.2931 11.11 15.11 1 0.0002778 USD / TJ 1 055 40 000 54 400 3 600 1 Note: Based on gas with 40 MJ/m3

Table 23 Conversion factors for natural gas volumes 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. 2009 OECD/IEA, ©

MEDIUM-TERM OIL MARKET REPORT

This fourth edition of the IEA Medium-Term Oil Market Report (MTOMR) reflects an economic landscape unrecognisable from that seen at the release of the summer 2008 edition. At writing, crude prices were 55% below summer 2008 levels as financial and economic meltdown have slashed demand, with worldwide contraction in oil use at levels not seen since the early 1980s. But how long will the downturn last? And what is the likely profile of global and regional demand recovery when economic rebound eventually takes root? Has almost a decade of rising prices and costs changed the demand- side blueprint and forced the world onto a lower oil intensity path for the period through 2014? Equally importantly, the report identifies the impact that weaker demand, low prices and a credit squeeze are having on supply- side investment – in upstream OPEC/non-OPEC supply, biofuels capacity and refining infrastructure alike. The 2009 edition of the MTOMR also delves into the issues of oil products supply, FSU crude exports, evolving crude and product qualities, the importance of petrochemical markets and perceptions on oil price formation in Order from our website: the down-cycle. Summary oil balances highlight how OPEC spare / capacity could develop during 2008-2014. www.iea.org books or The MTOMR remains required reading for policy makers, market e-mail: [email protected] analysts, industry participants and anyone with an interest in oil market trends. Alongside its monthly sister publication, the Oil Market Report, the MTOMR is a cornerstone of the IEA commitment to enhancing oil market transparency.

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