European 33 Gas Market Profiles 2006

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European 33 Gas Market Profiles: Q1 2006 Update

Current Trends and Future Prospects

The report comprises comprehensive analysis of the gas markets in the 25 EU member states and 8 related markets. Each country profile looks at market structures, regulatory

environments, supply/demand balances, storage, imports and, where appropriate, wholesale markets.

Reference Code: DMEN0414

Publication Date: 02/06

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European 33 Gas Market Profiles: Q1 2006 Update DMEN0414

© Datamonitor (Published 02/2006) Page 2 This report is a licensed product and is not to be photocopied

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Regional Overview


© Datamonitor (Published 02/2006) Page 3

This report is a licensed product and is not to be photocopied

CHAPTER 1 REGIONAL OVERVIEW

Regulatory climate

Liberalization and market reform have long been key themes in the European energy sector with the creation of a single European energy market high on the agenda of the European Union for many years.

The first steps towards this process took place in the early 1990s with the passing of Directive 90/377/EC, which aimed to make gas and power prices more transparent. This was followed by Directives 91/296/EEC and 90/547/EEC which were aimed at making trading energy between different European Union members more efficient.

Liberalization began in earnest in late 1996 when the EU passed the electricity directive (Directive 96/92/EC) setting out common rules for power production, transmission and distribution throughout the EU. The directive also legislated for gradual market opening with a target of 33% of all power markets meant to be opened to competition by February 2003.

The electricity directive was followed in June 1998 by the passing of the first gas directive (Directive 98/30/EC), which came into legal force on 10th August 1998 and was meant to have been adopted into the national legislation of all member states within 2 years. The directive established common rules for the operation of gas markets as well as outlining a market opening schedule. Under the terms of the directive, consumers of more than 25 mcm per year and all gas fired power stations were immediately able to choose their supplier, whilst phase 2 set a 28% market opening target by mid 2003 and 33% by mid 2008.

At the time the first directive was criticized, mainly by gas consumers, who described it as toothless and lacking in substance for having what they saw as a slow and undemanding market opening schedule.

In June 2003 the EU passed revised legislation accelerating the opening of both the gas and power markets by passing Directive 2003/54/EC for the electricity markets and Directive 2003/55/EC for gas. The new directives laid out a timetable to fully open both markets in two phases – phase 1 came into force on 1st July 2004 and opened the non-residential market, whilst phase 2 will come into effect on July 1st 2007 and will bring in 100% market opening.

Regional Overview




In addition to the market opening timetable, this second gas directive contained additional market reforms. These were:

Legal unbundling of transport and trading – the directive requires all member states to separate their gas transportation and trading functions into separate companies.

Regulated TPA – access must be granted to all gas grids with grid owners publishing rates which have been approved by the national regulator.

Creation of a Regulator – all markets without a gas regulatory body were required to create one.

Public service obligations – various obligations were placed on gas companies requiring them to protect the interests of consumers and to ensure the right to switch their gas supplier.

These obligations also apply to the 10 accession countries that joined the European Union on 1st May 2004.

The willingness, and success, with which the EU 25 members have adopted the terms of the directive varies widely. Some markets have not only met, but also exceeded, the timetable set out by the EU whilst others have still not complied with the deadlines. In mid October 2004 the European Commission issued formal letters to 18 members censuring them for not having met all of the requirements set out by the directive. Subsequently in July 2005 the EU announced its intention to take legal action against Estonia, Ireland, Greece, Spain and Luxembourg for not having fully transcribed the directives into national law.

Market development

Europe’s gas markets are at widely varying stages of development. Some markets, such as Germany and the UK, have sophisticated market structures reflecting their long histories as gas consumers. Conversely, some markets such as Spain and Portugal, are comparatively new consumers of gas and have immature infrastructures and markets. Significant differences also exist in terms of gas self sufficiency, the role gas plays in each country and in future demand growth rates.

Despite these differences, all markets in Europe are united by the fact that gas demand over the short to medium term is certain to increase as economic growth,

Regional Overview




greater supply availability, environmental concerns and legislation and a concerted movement towards gas fired power generation all combine to drive demand.

As this demand grows, and as indigenous supply becomes increasingly depleted, Europe will become more dependent on other sources of supply. North African and Russian gas will increasingly penetrate the European market, whilst gas from further afield, in the form of LNG, will also significantly gain market share.

Figure 1: Gas Penetration vs Absolute Demand

Austria

BelgiumCzech

Denmark

Finland

France

Germany

Greece

HungaryIreland

Italy

Lithuania

Netherlands

Poland

Portugal

Slovakia

Spain

Sweden

United Kingdom

0

20

40

60

80

100

120

0% 10% 20% 30% 40% 50% 60%Role of Gas In Primary Energy Mix

2004

Dem

and

(bcm

)

Source: Datamonitor D A T A M O N I T O R




TABLE OF CONTENTS

CHAPTER 1 REGIONAL OVERVIEW 3

Regulatory climate 3

Market development 4

CHAPTER 2 ALGERIA 28

Market summary 28

Supply and demand balance 29

Supply overview 30

Demand overview 31

Regulatory structure 33

Infrastructure 33

Pipelines 33

LNG 34

CHAPTER 3 AUSTRIA 36

Market summary 36


Supply overview 38

Demand overview 39


Wholesale environment 41

Overview 41

Infrastructure 42




Pipelines 42

Storage 43

CHAPTER 4 BELGIUM 45

Market summary 45


Supply overview 47

Demand overview 48



Infrastructure 51

Pipelines 51

LNG 52

Capacity deals signed 52

Storage 53

CHAPTER 5 BULGARIA 54

Market summary 54


Supply overview 56

Demand overview 56


Infrastructure 58

CHAPTER 6 CROATIA 60

Market summary 60





Supply overview 62

Demand overview 62


Infrastructure 64

CHAPTER 7 CYPRUS 66

Market summary 66

CHAPTER 8 CZECH REPUBLIC 67

Market summary 67


Supply overview 69

Demand overview 70


Infrastructure 73

CHAPTER 9 DENMARK 74

Market summary 74


Supply overview 76

Demand overview 77



Infrastructure 81

Pipelines 81




Storage 81

CHAPTER 10 ESTONIA 82

Market summary 82


Supply overview 84

Demand overview 84


Infrastructure 85

CHAPTER 11 FINLAND 87

Market summary 87


Supply overview 89

Demand overview 89


Infrastructure 91

Pipelines 91

CHAPTER 12 FRANCE 93

Market summary 93


Supply overview 95

Demand overview 96


Key factors limiting the development of competition in France 99





Infrastructure 101

LNG 101

Pipeline infrastructure 101

CHAPTER 13 GERMANY 105

Market summary 105


Demand overview 108



Infrastructure 112

CHAPTER 14 GREECE 115

Market summary 115


Supply overview 117

Demand overview 118


Infrastructure 120

LNG 120

CHAPTER 15 HUNGARY 121

Market summary 121


Supply overview 123




Demand overview 124


Infrastructure 127

Pipelines 127

Storage 127

CHAPTER 16 IRELAND 128

Market summary 128


Supply overview 130

Demand overview 132


Infrastructure 134

CHAPTER 17 ITALY 136

Market summary 136


Supply overview 138

Demand overview 139



Infrastructure 143

Pipelines 143

LNG infrastructure 144

Storage sites 146




CHAPTER 18 LATVIA 147

Market summary 147


Supply overview 149

Demand overview 149


Infrastructure 151

Pipelines 151

Storage 151

CHAPTER 19 LITHUANIA 152

Market summary 152


Supply overview 154

Demand overview 154


Infrastructure 156

Pipelines 156

CHAPTER 20 LUXEMBOURG 157

Market summary 157


Supply overview 159

Demand overview 159





Infrastructure 161

Pipelines 161

CHAPTER 21 MALTA 162

Market summary 162

CHAPTER 22 THE NETHERLANDS 163

Market summary 163


Supply overview 165

Demand overview 167



Infrastructure 170

Pipelines 170

Storage 170

LNG 171

CHAPTER 23 NORWAY 172

Market summary 172


Supply overview 174

Demand overview 175


Infrastructure 177




CHAPTER 24 POLAND 180

Market summary 180


Supply overview 182

Demand overview 183


Infrastructure 185

Pipelines 185

CHAPTER 25 PORTUGAL 187

Market summary 187


Supply overview 189

Demand overview 190


Infrastructure 192

LNG 192

Storage 192

CHAPTER 26 ROMANIA 194

Market summary 194


Supply overview 196

Demand overview 197





Infrastructure 199

CHAPTER 27 RUSSIA 200

Market summary 200


Supply overview 202

Demand overview 203


Industry restructuring 205

Competitive intensity 206

Market framework factors 207

Supplier push factors 207

Customer pull factors 208


Infrastructure 208

Upstream 208

Unified Gas Supply System 209

Export infrastructure 210

CHAPTER 28 SLOVAKIA 212

Market summary 212


Supply overview 214

Demand overview 215





Infrastructure 218

Pipelines 218

Storage 218

CHAPTER 29 SLOVENIA 220

Market summary 220

Supply overview 222

Demand overview 222


Infrastructure 224

Pipelines 224

CHAPTER 30 SPAIN 225

Market summary 225


Supply overview 227

Demand overview 228



Infrastructure 232

LNG 232

Pipelines 233

Pipeline developments 233

Storage 234

CHAPTER 31 SWEDEN 236




Market summary 236


Supply overview 238

Demand overview 239


Infrastructure 241

Pipelines 241

CHAPTER 32 SWITZERLAND 243

Market summary 243


Supply overview 245

Demand overview 245


Infrastructure 247

CHAPTER 33 TURKEY 249

Market summary 249


Supply overview 251

Demand overview 252


Infrastructure 254

CHAPTER 34 UNITED KINGDOM 256

Market summary 256





Supply overview 258

Demand overview 259



Infrastructure 263

Transmission and distribution 263

Offshore infrastructure 263

LNG 265

Storage 266

CHAPTER 35 APPENDIX 268

Data sources 268

Data Adjustments 268

Definitions 269

Future readings 270

SPP writing team 270

How to contact experts in your industry 271




LIST OF TABLES

Table 1: Algeria, Supply and Demand Balance 29

Table 2: Austria, Supply and Demand Balance 37

Table 3: Austria, Storage Sites 43

Table 4: Belgium, Supply and Demand Balance 46

Table 5: Belgium, Interconnector Ownership 51

Table 6: Belgium, Storage Sites 53

Table 7: Bulgaria, Supply and Demand Balance 55

Table 8: Croatia, Supply and Demand Balance 61

Table 9: Czech Republic, Supply and Demand Balance 68

Table 10: Czech Republic, Storage Sites 73

Table 11: Denmark, Supply and Demand Balance 75

Table 12: Denmark, Storage Sites 81

Table 13: Estonia, Supply and Demand Balance 83

Table 14: Finland, Supply and Demand Balance 88

Table 15: France, Supply and Demand Balance 94

Table 16: France, LNG Infrastructure 101

Table 17: France, LNG Infrastructure 103

Table 18: Germany, Supply and Demand Balance 106

Table 19: Germany, Storage Sites 114

Table 20: Greece, Supply and Demand Balance 116

Table 21: Hungary, Supply and Demand Balance 122

Table 22: Hungary, Storage Sites 127




Table 23: Ireland, Supply and Demand Balance 129

Table 24: Italy, Supply and Demand Balance 137

Table 25: Italy, LNG Infrastructure 145

Table 26: Italy, Storage Sites 146

Table 27: Latvia, Supply and Demand Balance 148

Table 28: Lithuania, Supply and Demand Balance 153

Table 29: Luxembourg, Supply and Demand Balance 158

Table 30: Netherlands, Supply and Demand Balance 164

Table 31: Netherlands, Storage Sites 170

Table 32: Norway, Supply and Demand Balance 173

Table 33: Gassled Shareholders 178

Table 34: Poland, Supply and Demand Balance 181

Table 35: Portugal, Supply and Demand Balance 188

Table 36: Romania, Supply and Demand Balance 195

Table 37: Russia, Supply and Demand Balance 201

Table 38: Russia, Age of high-pressure pipelines, 2004 209

Table 39: Slovakia, Supply and Demand Balance 213

Table 40: Slovakia, Storage Sites 218

Table 41: Slovenia, Supply and Demand Balance 221

Table 42: Spain, Supply and Demand Balance 226

Table 43: Spain, LNG Infrastructure 232

Table 44: Spain, Storage Sites 235

Table 45: Sweden, Supply and Demand Balance 237

Table 46: Switzerland, Supply and Demand Balance 244




Table 47: Turkey, Supply and Demand Balance 250

Table 48: UK, Supply and Demand Balance 257

Table 49: UK, LNG Infrastructure 266

Table 50: UK, Storage Sites 267




LIST OF FIGURES

Figure 1: Gas Penetration vs Absolute Demand 5

Figure 2: Algeria, Gas Production 30

Figure 3: Algeria, Pipeline Gas Export Destinations 31

Figure 4: Algeria, Sectoral Demand 32

Figure 5: Algeria, Historical Demand 32

Figure 6: Algeria, Gas Infrastructure 35

Figure 7: Austria, Gas Production 38

Figure 8: Austria, Imports By Source 39

Figure 9: Austria, Sectoral Demand 40

Figure 10: Austria, Historical Sectoral Demand 40

Figure 11: Austria, Gas Grid 44

Figure 12: Belgium, Supply Source 47

Figure 13: Belgium, Sectoral Demand 48

Figure 14: Belgium, Historical Sectoral Demand 49

Figure 15: Bulgaria, Historical Demand 57

Figure 16: Bulgaria, Sectoral Demand 57

Figure 17: Bulgaria, Gas Grid 59

Figure 18: Croatia, Gas Production 62

Figure 19: Croatia, Sectoral Demand 63

Figure 20: Croatia, Historical Demand 63

Figure 21: Croatia, Gas Grid 65

Figure 22: Czech Republic, Import Sources 69




Figure 23: Czech Republic, Gas Production 70

Figure 24: Czech Republic, Sectoral Demand 71

Figure 25: Czech Republic, Historical Sectoral Consumption 71

Figure 26: Czech Republic, Czech Republic Distribution Grid 73

Figure 27: Denmark, Supply Sources 76

Figure 28: Denmark, Gas Production 77

Figure 29: Denmark, Sectoral Demand 78

Figure 30: Denmark, Historical Sectoral Demand 78

Figure 31: Estonia, Sectoral Demand 84

Figure 32: Estonia, Gas Distribution Grid 86

Figure 33: Finland, Sectoral Demand 90

Figure 34: Finland, Historical Sectoral Demand 90

Figure 35: Finland, Gas Grid 92

Figure 36: France, Gas Production 95

Figure 37: France, Import Sources 96

Figure 38: France, Sectoral Demand 97

Figure 39: France, Historical Sectoral Demand 97

Figure 40: France, Transmission Grid 104

Figure 41: Germany, Gas Production 107

Figure 42: Germany, Imports By Source 108

Figure 43: Germany, Sectoral Demand 109

Figure 44: Germany, Historical Sectoral Consumption 109

Figure 45: Greece, Indigenous Production 117

Figure 46: Greece, Sectoral Demand 118




Figure 47: Greece, Historical Sectoral Demand 119

Figure 48: Hungary, Gas Production 123

Figure 49: Hungary, Imports By Source 124

Figure 50: Hungary, Sectoral Demand 125

Figure 51: Hungary, Historical Sectoral Demand 125

Figure 52: Ireland, Gas Production 131

Figure 53: Ireland, Imports By Source 131

Figure 54: Ireland, Sectoral Demand 132

Figure 55: Ireland, Historical Sectoral Demand 133

Figure 56: Ireland, Transmission Grid 135

Figure 57: Italy, Gas Production 138

Figure 58: Italy, Imports By Source 139

Figure 59: Italy, Sectoral Demand 140

Figure 60: Italy, Historical Sectoral Demand 140

Figure 61: Italy, Gas Infrastructure 146

Figure 62: Latvia, Sectoral Demand 150

Figure 63: Lithuania, Sectoral Demand 155

Figure 64: Luxembourg, Sectoral Demand 159

Figure 65: Luxembourg, Historical Sectoral Demand 160

Figure 66: Luxembourg, Gas Grid 161

Figure 67: Netherlands, Gas Production 166

Figure 68: Netherlands, Imports By Source 166

Figure 69: Netherlands, Sectoral Demand 167

Figure 70: Netherlands, Historical Sectoral Demand 168




Figure 71: Norway, Gas Production 174

Figure 72: Norway, Gas Export Destinations 175

Figure 73: Norway, Sectoral Demand 176

Figure 74: Norway, Historical Sectoral Demand 176

Figure 75: Norway, Gas Export Infrastructure 179

Figure 76: Poland, Gas Production 182

Figure 77: Poland, Imports By Source 183

Figure 78: Poland, Sectoral Demand 184

Figure 79: Poland, Historical Sectoral Demand 184

Figure 80: Poland, Gas Transmission System 186

Figure 81: Portugal, Imports By Source 189

Figure 82: Portugal, Sectoral Demand 190

Figure 83: Portugal, Historical Sectoral Demand 191

Figure 84: Romania, Gas Production 196

Figure 85: Romania, Import Sources 197

Figure 86: Romania, Sectoral Demand 198

Figure 87: Romania, Historical Demand 198

Figure 88: Russia, Gas Production 202

Figure 89: Russia, Gas production by producer type 203

Figure 90: Russia, Sectoral Demand 204

Figure 91: Russia - The state is planning to increase its stake in Gazprom to 51% and to expand the open market 206

Figure 92: Russia, gas market competitive intensity 2005-08 207

Figure 93: Russia, Gas reserves 209

Figure 94: Russia, Main existing and planned export pipelines 211




Figure 95: Slovakia, Gas Production 214

Figure 96: Slovakia, Imports By Source 215

Figure 97: Slovakia, Sectoral Demand 216

Figure 98: Slovakia, Historical Sectoral Demand 216

Figure 99: Slovakia, Gas Grid 219

Figure 100: Slovenia, Imports By Source 222

Figure 101: Slovenia, Sectoral Demand 223

Figure 102: Slovenia, Gas Grid 224

Figure 103: Spain, Gas Production 227

Figure 104: Spain, Imports By Source 228

Figure 105: Spain, Sectoral Demand 229

Figure 106: Spain, Historical Sectoral Demand 229

Figure 107: Spain, Gas Grid 234

Figure 108: Sweden, Sectoral Demand 239

Figure 109: Sweden, Historical Sectoral Demand 240

Figure 110: Sweden, Gas Grid 242

Figure 111: Switzerland, Import Sources 245

Figure 112: Switzerland, Sectoral Demand 246

Figure 113: Switzerland, Historical Sectoral Demand 246

Figure 114: Switzerland, Gas Grid 248

Figure 115: Turkey, Gas Production 251

Figure 116: Turkey, Imports by Source 252

Figure 117: Turkey, Sectoral Demand 253

Figure 118: Turkey, Historical Sectoral Demand 253




Figure 119: Turkey, Gas Grid 255

Figure 120: UK, Gas Production 258

Figure 121: UK, Imports By Source 259

Figure 122: UK, Sectoral Demand 260

Figure 123: UK, Historical Sectoral Demand 260




CHAPTER 2 ALGERIA

Market summary

Algeria is a significant exporter of gas and accounts for around 18% of the gas imports into the EU 25, making it Europe’s second largest supplier after Russia.

This role is set to continue in the longer term given the country's significant reserves and the fact that large areas of the country are yet to be explored.

Gas is extensively used in Algeria, with the power generation sector being the main end user. Demand levels have remained relatively unchanged in recent years, though over the next five years demand has been forecast to grow significantly as a result of economic growth.

Recently new legislation has been passed which has significantly liberalised the sector and ended Sonatrach’s monopoly.

Algeria is a significant LNG exporter and in 1964 became the world’s first LNG producer. Two major export lines allow Algerian gas to be exported to Europe with a third line, known as Medgas, due for completion in 2009.




Supply and demand balance

Table 1: Algeria, Supply and Demand Balance BCM 2003 2004 CAGRSUPPLY Production 82.80 82.00 -1.0%Pipeline Imports Total Pipeline Imports 0.000 0.000 - LNG Imports 0.000 0.000 -Total LNG Imports 0.000 0.000 - Total Imports 0.000 0.000 - Gross Supply 82.800 82.000 -1.0% Pipeline Exports Italy 21.45 23.60 10.0%Portugal 2.50 2.25 -10.0%Slovenia 0.44 0.44 0.0%Spain 6.40 7.53 17.7%Morocco 0.60 - -Tunisia 1.69 1.30 -23.1%Total Pipeline Exports 33.08 35.12 6.2% LNG Exports USA 1.51 3.41 125.8%Belgium 3.15 2.85 -9.5%France 9.20 6.72 -27.0%Greece 0.55 0.55 0.0%Italy 2.02 2.10 4.0%Spain 7.48 6.58 -12.0%Turkey 3.86 3.24 -16.1%South Korea 0.23 0.30 30.4%Total LNG Exports 28.00 25.75 -8.0% Statistical Diffs 0.32 -0.07 -Stock Change 0.00 0.00 - Net Supply 21.40 21.20 -0.9%DEMAND Residential 4.92 4.88 -0.9%Non Residential 2.57 2.54 -0.9%Power Generation 13.91 13.78 -0.9%Total Demand 21.40 21.20 -0.9%Source: IEA / Datamonitor D A T A M O N I T O R




Supply overview

With proven reserves of 4,550 bcm, an R/P ratio of 55 years and considerable future reserve additions potential, Algeria is certain to maintain its role as one of the world’s leading gas producers. Over the past decade production has been growing steadily at around 3.4% per annum. Currently around three quarters of production is exported, both as pipeline gas and LNG. The main markets for Algerian gas exports are in southern Europe, though LNG is exported further north with small volumes also going to Asia. Sonatrach hopes to increase exports to around 100 bcm per year by 2015.

At 25.75 bcm per year, LNG exports are significant and make Algeria the world’s third largest LNG producer after Indonesia and Malaysia. Algeria accounts for around 18% of the gas imports to the EU 25, making it Europe’s second largest supplier after Russia.

Figure 2: Algeria, Gas Production

Indigenous Gas Production

0.010.020.030.040.050.060.070.080.090.0

100.0

1970 1974 1978 1982 1986 1990 1994 1998 2002

BC

M

Source: IEA / Datamonitor D A T A M O N I T O R




Figure 3: Algeria, Pipeline Gas Export Destinations

Exported gas via pipleine

Spain21%

Tunisia4%

Italy68%

Portugal6%

Slovenia1%


Demand overview

Algeria’s significant natural resource endowments mean that gas has long played a role in the Algerian energy mix. At 63% natural gas is currently the most important fuel in the primary energy mix and represents one of the highest gas penetrations in the world.

Current annual demand levels of 23 bcm have remained surprisingly constant in recent years having remained largely unchanged since the late 1980s. However, estimates made by Sonatrach indicate a rapid increase in demand between now and 2010, by which time it expects annual demand to have reached 30 bcm.

Power generation is by far the largest end use sector accounting for nearly two thirds of consumption.




Figure 4: Algeria, Sectoral Demand

Sectoral Consumption

Pow er Generation

65%

Non Residential

12%

Residential23%


Figure 5: Algeria, Historical Demand

Gas Demand

0

5

10

15

20

25

1965 1969 1973 1977 1981 1985 1989 1993 1997 2001

BC

M





Regulatory structure

The Algerian government exerts considerable influence on the gas sector through its control of two fully state owned companies - Sonatrach which dominates the production and wholesale distribution of gas and Sonelgaz which controls distribution.

In 1996 legislative changes allowed foreign companies to set up commercial joint stock companies with Sonatrach, giving the government the right to acquire majority stakes in hydrocarbon ventures. Subsequently Sonatrach’s acquisition rights were reduced to a maximum of 30%. The Algerian government has been successful in attracting foreign investors, including Statoil, BP and around 30 others, into the upstream arena under partnership agreements. Efforts were made in 2005 to attract foreign investors into the retail market through liberalising domestic gas prices, though this proved unpopular with consumers and future developments in this area remain unclear.

In March 2005 a new hydrocarbons law was approved, effectively ending the monopoly of Sonatrach and further promoting foreign investment in the sector. Until recently the majority of regulation was undertaken by the government through the Ministry of Energy and Mining, though under the May 2005 law two new bodies were created.

The first of these new bodies is ALNAFT (Agence pour la valorisation des ressources en hydrocarbures) which was created to run the tendering process for E&P licensing rounds and administer the state’s upstream activities. The other, the HRA (autorite pour la regulation des hydrocarbures) was created to oversee the regulatory aspects of the upstream and downstream sectors and to administer TPA to pipeline and storage facilities.

Infrastructure

Pipelines

Given that one field, Hassi R’Mel, which accounts for about 25% of the country’s gas production, is the largest gas source in the country, it lies at the heart of the gas infrastructure network.

Algeria has two main gas exporting lines:-

Transmed – at 670 miles long, Transmed is the country's longest exporting pipeline. It runs from Hassi R’Mel via Tunisia and Sicily into mainland Italy. It currently exports around 23 bcm per annum, though has capacity to export up to 27 bcm per year.




Pedro Duran Farell pipeline - formerly known as the GME or Maghreb-Europe line, it exports gas to the south of Spain via Morocco. In 2004 a large capacity expansion was undertaken, increasing throughput to close to 12 bcm per annum.

One other significant export pipeline is currently under development. The Medgas pipeline is currently being developed by a consortium including Spanish oil company Cepsa, Sonatrach, BP, GdF, Endesa and Iberdrola. The partners signed an agreement in 2001 to construct an 8 bcm per annum link between Algeria and Spain to supplement the existing connection. Financing difficulties have resulted in delays to the start up of construction work, though following the granting of final regulatory approval in June 2005, construction is due to start in July 2006. Initial flows are now likely by early 2009.

Two other significant export projects have been mooted. Firstly Sonatrach signed a deal in 2002 with Italy’s Enel and Germany’s Wintershall to build a new pipeline, known as Galsi, crossing the Mediterranean to Italy. Tendering plans are currently underway with initial flows of the 10 bcm link possible by 2008.

Secondly, also in 2002, Sonatrach signed an agreement with Nigeria’s NNPC, forming the Trans-Saharan Natural Gas Consortium (known as NIGEL), to build a link between the Hassi R’Mel field in order to facilitate pipeline exports of Nigerian gas to Europe via Transmed, the Pedro Duran Farell and Medgaz.

LNG

Having become the world’s first LNG producer in 1964, Algeria has a long and well established history as a world leading LNG player. The Algerian transmission system takes gas from the producing areas to the country's LNG terminals at Arzew, Skikda and Algiers.

The national gas grid, both owned and operated by Sonelgaz, consists of a 4,675 kms transmission network and a 22,111 kms long distribution network.




Figure 6: Algeria, Gas Infrastructure

Source: Sonatrach D A T A M O N I T O R




CHAPTER 3 AUSTRIA

Market summary

At 26% gas plays an important role in the Austrian primary energy mix. In common with many other parts of Europe, gas is gaining market share by backing out coal.

Austria’s main significance in the European gas sector is in its role as a transit country for Russian gas. Currently around a fifth of Russian gas exports are routed through Austria, giving it an added element of security of supply. Continued demand growth in all European markets, combined with maturing indigenous production in a number of markets, means that this transit role will continue to grow.

Austria is heavily import dependent, with indigenous production meeting less than a quarter of demand.

Compared with other EU members, storage capacity in Austria is limited. However, work is currently underway to double existing capacity.





Table 2: Austria, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 2.091 1.963 -6.1% Pipeline Imports Germany 0.979 1.078 10.1% Norway 0.980 0.862 -12.0% Russia 6.091 6.467 6.2% Total Pipeline Imports 8.050 8.407 4.4% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 8.050 8.407 4.4% Gross Supply 10.141 10.370 2.3% Exports Hungary 1.130 0.756 -33.1% Poland 0.000 0.378 - Slovenia 0.000 0.128 - Total Pipeline Exports 1.130 1.262 11.7% Statistical Diffs 0.000 0.060 - Stock Change -0.200 -0.065 -67.5% Net Supply 8.811 8.983 1.9% DEMAND Residential 1.872 1.886 0.8% Non Residential 4.059 4.090 0.8% Power Generation 2.981 3.004 0.8% Total Demand 8.912 8.981 0.8% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Indigenous production in Austria is limited with little or no prospect of any significant increase in the coming years. Production is dominated by Rohol Aufsuchungs AG (RAG) through its acreage in the Upper Austria and Salzburg areas, and OMV.

All Austrian production is non associated. Following a decline in production in the late 1970s there has been a slow increase in output, though indigenous production is still only sufficient to meet less than a quarter of demand.

In 1968 OMV became the first Western country to sign a gas supply contract with Russia. Russian gas, the key source of imports, is imported via 4 long term contracts delivered at Baumgarten.

In February 2006, OMV discovered gas in the Austria’s Vienna basin at its Ebenthal Tief well. Reserve are estimated at around 1.5 bcm and are due onstream in 2007. Production rates are likely to be between 100,000 and 150,000 cubic metres per year giving a field life of up to 15 years.

Figure 7: Austria, Gas Production


0

1

2

3

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000

BC

M

Source: Datamonitor / IEA D A T A M O N I T O R




Figure 8: Austria, Imports By Source

Import Supply Sources

Germany13%

Norw ay10%

Russia77%


Demand overview

In line with both global and European trends, the power generation sector has been the key source of demand growth in recent years. Average annual growth in this sector has averaged over 6.5% since 2000, nearly twice the growth rate seen in the Residential sector and three times that of the non-residential sector.

Various investments in gas fired power are continuing to take place including Energie AG’s new 400 MW CCGT at Timelkam in Upper Austria which is due to produce around 2.5 TWh per year of gas fired power from late 2008.

Total gas demand has increased steadily at an average of 1.8% per year in the decade to 2004.




Figure 9: Austria, Sectoral Demand

Sectoral ConsumptionPow er

Generation33%

Non Residential

46%

Residential21%


Figure 10: Austria, Historical Sectoral Demand

0

2

4

6

8

10

bcm

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004


Pow er Generation Residential Non-Residential






Austria translated the original 1998 EU gas directive into national law on 10 August 2000 through the passing of the Gas Management Act, known as the GWG.

The opening of the market was accelerated through the inauguration of the Energy Liberalization Act on 1st March 2001 and the revision to the GWG in 2002.

These changes to the pace of liberalization included the formation of E-Control, a regulatory body charged with monitoring, supporting and regulating the Austrian power and gas sectors.

Other legislative catalysts to market opening ahead of EU deadlines resulting from the GWG 2002 Amendment were regulated grid access for all consumers, the formation of regulatory zones, the creation of balance groups and a clearing system to facilitate the pricing and payment amongst the balance groups.

From October 2002, Austria’s gas market became (at least in theory) fully liberalized.

As part of their competitive response to the liberalisation of the Austrian market, six leading gas market players (BEGAS, EVN, Linz AG, OÖ Ferngas, OMV and WIEN ENERGIE) formed EconGas with the intention of selling gas and gas services to large industrial gas users (those with an annual consumption in excess of 500,000 cubic meters).

In order to prevent a possible dominance of EconGas and as a method of further encouraging competition, E-control directed EconGas to auction 250 mcm of gas each year until an effective and liquid hub emerges at Baumgarten. So far 3 auctions have been held. A total of 21 market players took part in the first auction, with 8 successfully obtaining gas. The second auction in July 2004 attracted 31 interested players with 12 companies successfully buying the 250 mcm sale volume. The third auction in July 2005 resulted in 10 of the 28 bidders acquiring all of the 270 mcm available volume.

Wholesale environment

Overview

Baumgarten, in eastern Austria, plays a key role in transiting Russian gas to the west. Its significance as a hub lies in the fact that it is the single largest delivery point for Russian gas shipped into western Europe. OMV set up a hub operator company, the




Central European Gas Hub GmbH (CEGH), in 2001 but it has failed to make any significant impact. Wholesale trading has not yet developed at Baumgarten, despite its potential as a hub, given Gazprom’s long standing refusal to remove destination clauses, which disallowed its gas to be onwardly traded, from its long term contracts.

In May 2004, OMV renegotiated its long term contract with Gazprom. Continuing the precedent set in a supply renegotiation deal agreed with Eni in late 2003 and following continued pressure from the EU, Gazprom agreed to remove the destination clause thus allowing the gas it supplied to be onwardly traded and consequently removing a major obstacle to the development of a meaningful wholesale market at Baumgarten.

Currently Baumgarten remains largely a physical hub though the removal of the destination clauses bring the development of a spot and forwards market a step closer. From 1st October 2005 CEGH began offering a standard contract and title transfer services for short term deals which 13 players signed up to. However it is unlikely that liquidity will develop to any meaningful degree in the short to medium term.

Infrastructure

Pipelines

Given Austria’s role as a key transit country for eastern gas going west, it is sometimes difficult to draw a distinction between transmission and distribution infrastructure.

Transit infrastructure consists of the following key pipelines:

Trans-Austria Gasleitung (TAG) has a maximum capacity of 26 bcm and transits gas to Italy. It runs from Baumgarten on the Austrian / Slovakian border to Tarvisio in northern Italy and is jointly owned by OMV and Eni which also leases the majority of capacity. In February 2006, Eni announced plans to bring forward the planed expansion of the pipeline’s capacity by 3.2 bcm per year by October 2008 and a further 3.3 bcm by April 2009. The increase was formerly scheduled for 1st October 2011.

Western Austria Gasleitung (WAG) is a key transit route for Russian gas to the German border. It connects with the Megal system at Oberkappel on the German / Austrian border for onward transit. The line’s capacity is 5 bcm and it is owned by OMV (51%), Gaz de France (44%) and Ruhrgas (5%).

Hungary-Austria Gasleitung (HAG) connects Baumgarten with the Hungarian border at Gattendorf, to the south of Baumgarten. Current capacity is around 4.5 bcm per annum. HAG is owned and operated by OMV.




Penta West is a 3 bcm per annum spur line from the WAG pipeline at Oberkappel to Burghausen transiting the northwestern corner of Austria. Penta West is owned and operated by OMV.

The Sud-Ost Leitung (SOL) is another spur line. It feeds off of the TAG pipeline and transits gas to the Slovenian border. It has a 3.3 bcm per annum capacity and is owned and operated by OMV.

A report issued in November 2004 by Austrian Gas Grid Management, an operationally independent part of OMV responsible for gas network coordination, warned that capacity in the east of the country was insufficient to meet long term needs.

Storage

Gas storage in Austria is made up of depleted gas field in or around Baumgarten.

Ownership of gas storage is dominated by OMV, which owns and operates around three quarters of current capacity with the remainder owned by RAG.

A new storage facility at Haidach is being planned by RAG. The first phase of the project will have a 1.2 bcm per year capacity from mid 2007 with plans to double this in the second phase of the project.

Table 3: Austria, Storage Sites Name Type Operator Capacity Peak Deliverability (mcm) (mcm / day) Punchkirchen Depleted field RAG 700 6.96 Schoenkirchen / Reyersdorf Depleted field OMV 1,570 17.80 Tallesbrun Depleted field OMV 300 3.84 Thann Depleted field OMV 250 3.12 Total 2,820 31.72





Figure 11: Austria, Gas Grid

Source: OMV D A T A M O N I T O R




CHAPTER 4 BELGIUM

Market summary

Despite not having any indigenous production and comparatively low consumption levels, Belgium is a key player in the European gas market.

In addition to playing a key role as a transit state, Belgium is also home to Europe’s second most liquid trading hub, an LNG import terminal and the UK / Continental Europe Interconnector.

With various sources of pipeline gas and an LNG terminal, Belgian supplies are well diversified and very secure.

With different regulatory bodies and market conditions in each of the three main regions of the country, Belgium is in some senses three distinct markets.





Table 4: Belgium, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.000 0.000 - Pipeline Imports Netherlands 6.067 7.302 20.4% Norway 5.427 4.503 -17.0% UK 0.000 0.114 - Other 2.017 1.876 -7.0% Total Pipeline Imports 13.511 13.795 2.1% LNG Imports Algeria 3.184 3.082 -3.2% Total LNG Imports 3.184 3.082 -3.2% Total Imports 16.695 16.877 1.1% Gross Supply 16.695 16.877 1.1% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs -0.119 -0.174 - Stock Change 0.186 -0.040 - Net Supply 17.000 17.011 0.1% DEMAND Residential 4.219 4.221 0.0% Non Residential 8.146 8.150 0.0% Power Generation 4.635 4.637 0.0% Total Demand 17.000 17.008 0.0% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

With no indigenous production, Belgium is entirely dependent on imported gas.

Given its role as a transit country, and the fact that an LNG terminal and various pipeline infrastructure is available (see Infrastructure section), Belgian supplies are amongst the most secure and well diversified in Europe.

In February 2005 another long term LNG supply deal was agreed. Under the terms of the deal, Distrigas will buy up to 2 million tonnes per year of LNG for a 20 year period from Qatar.

Figure 12: Belgium, Supply Sources


Other11%

Algeria LNG18%

UK1%

Norw ay27%

Netherlands43%





Demand overview

Growth in the power generation sector has been the key driver of Belgian gas demand growth in the past decade. Over the 10 years to 2004 demand in this sector grew by an average of 6.9% per year. Between 2003 and 2004 there was a particularly large increase in gas use in power generation of over 1 bcm or 29%.

Total demand has grown by an average of 3.1% per annum over the past decade with growth of 2.3% and 1.4% in the non-residential and residential sectors respectively.

Figure 13: Belgium, Sectoral Demand


Generation27%

Non Residential

48%

Residential25%





Figure 14: Belgium, Historical Sectoral Demand

0

5

10

15

20bc

m

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004


Non Residential Pow er Generation Residential



Belgium incorporated the original Gas Directive into federal legislation in April 1999 by passing the Amendment to the Federal Gas Act 1999. This legislation was an amendment to existing legislation covering the industry passed in 1965.

Further regulatory developments were made by the Amendment to the Federal Gas Act 2001, which accelerated the market opening process by replacing negotiated Third Party Access with regulated Third Party Access.

Regulation in Belgium is split between federal and local regulatory bodies. The three regions (Flanders, Wallonia and Brussels) control liberalisation policy and distribution in their individual areas whilst transmission, LNG and storage are regulated at a Federal level by the Commission de Régulation de l’Electricité et du Gaz (CREG).

In the Flanders region, which accounts for close to 60% of end users in the country, the regional regulator the Vlaamse Reguleringsinstantie voor de Electriciteits-en Gasmarkt, oversaw complete market opening by the middle of 2003. Currently there are 11 licensed gas suppliers in the region selling to 1.6 million end user sites.

In the Wallonia and Brussels regions, market opening is somewhat slower. Wallonia has had an open market for consumers using more than 1 mcm per annum since




January 2004 and is due to implement full market opening on January 1st 2007. In the Brussels area legislation was passed on the 1st October 2003 bringing the area into compliance with the second Gas Directive by opening the market to non-residential users from 1st July 2004 and all customers from 1st July 2007.

In February 2005 a gas exchange was launched at Zeebrugge by APX (formerly known as the Amsterdam Power Exchange), Endex (the European Energy Derivatives Exchange) and Huberator (the hub services subsidiary of Fluxys). The exchange currently offers only short term contracts up to and including Working Days Next Week, though longer term contracts are planned for the near term future.


The Zeebrugge market was the second wholesale market to emerge in Europe following the UK’s NBP. Zeebrugge’s emergence as a hub has been driven by the wide variety of infrastructure located in Belgium. The trading hub came into being in 1999 and, whilst used as a hub in its own right, relies on arbitrages with the NBP for a significant amount of its liquidity. Gas is usually priced at a differential to the NBP market.

The Zeebrugge hub is operated by Huberator, a subsidiary of Fluxys, the Belgian grid company. Following the service agreement signing in February 2006 of the Dutch company Eneco, there are 47 players signed up to trade with Huberator, a significant reduction on the 60 or so members registered in 2004 under the previous hub service agreement. Like the NBP, these customers come from a wide variety of areas in the value chain and include shippers, utilities, gas companies and banks. Liquidity on the hub rose by 2% in 2005, with hub firmness increasing to 99%.

Zeebrugge has a trading to physical flow ratio of around 4.5:1, meaning that four and a half times as much gas is traded than actually flows. Although this is somewhat lower than the NBP’s 10:1 ratio, it remains much higher than many of Europe’s other hubs.

In June 2004 Huberator, the APX (formerly known as the Amsterdam Power Exchange) and Endex (the European Energy Derivatives Exchange) signed an agreement to set up a gas exchange at Zeebrugge. The exchange, known as APX Gas ZEE, was launched in early February as a screen based trading platform offering both financial and physical products, initially on just a prompt basis though with longer term contracts planned at a later date. The exchange now has nine members and Huberator and Fluxys are investigating ways to increase the current low levels of liquidity.




Infrastructure

Pipelines Given its role as a transit country, Belgium’s pipeline infrastructure is dominated by transmission infrastructure, which is also interconnected with the distribution grid. Both the transmission and distribution grids are operated by Fluxys.

Belgium is connected to the UK via the UK-Belgium Interconnector running between Bacton on the east coast of the UK and Zeebrugge. Opened in 1998 the pipeline has the ability to operate in both forward and reverse flow modes thus allowing Belgium to both import and export gas as market conditions and demand dictate. The Interconnector has a capacity of 20 bcm per annum in forward flow (exporting gas from the UK to Zeebrugge) and 16.5 bcm per annum in reverse flow (exporting gas from Zeebrugge to the UK).

Table 5: Belgium, Interconnector Ownership Shareholder % BG Energy Holdings 25 ConocoPhillips (UK) 10 Distrigas 16.41 Eni International 5 E.ON Ruhrgas 17.38 OAO Gazprom 10 Total 10 Source: Interconnector UK

The 16.5 bcm per year reverse flow capacity came into effect in November 2005 following the upgrading from the original 8.5 bcm per year capacity. Further expansion work is currently underway which will increase capacity to 23.5 bcm per year from December 2006.

Key transit pipelines in Belgium include:

Zeepipe – an offshore line from the Norwegian North Sea to Zeebrugge where it interfaces with other transit lines and the Fluxys transmission grid.

RTR pipeline – runs from Zeebrugge through the centre of Belgium to Eynatten on the German border with a spur connection to the Netherlands near Zelzate.




Finpipe – runs from Zeebrugge to Blaregnies on the French border.

Gas distribution in Belgium is controlled by the country’s municipalities who have awarded distribution rights in the 20 distribution zones to two companies, Electrabel Customer Services and Luminus.

Belgium is one of the few countries in Europe to have both high and low calorific value gas infrastructure. The low calorific pipelines are fed by gas from the Dutch Groningen field which, due to its highly flexible nature, provides a useful source of swing capacity.

Much of Belgium’s infrastructure revolves around its role as a gas transit country. In late 2004 Distrigas and Gazexport, the export division of Russia’s Gazprom, continued their transit relationship by agreeing a deal under which Distrigas will move Russian gas from the Germany / Belgian border to Zeebrugge. The agreements allow Gazexport to move up to 2.5 bcm per year to Zeebrugge until 2018. The deal will allow Gazprom to sell gas at the Zeebrugge hub and, given its stake in the Interconnector, to the UK where it has ambitious expansion plans.

In November 2004 CREG issued a report concluding that EUR 500 million of investment in pipeline capacity will be needed between 2005 and 2014 to meet growing demand and related transport capacity requirements.

LNG Belgium has played an increasingly important part in Europe’s growing LNG sector. Through its subsidiary Fluxys LNG, Fluxys owns and operates the 4.5 bcm per annum Zeebrugge LNG terminal. All of the terminal’s capacity is allocated to Distrigas until late 2006 to service its long term supply deal with Algeria’s Sonatrach.

In early 2003 Fluxys LNG undertook an “open season” exercise where LNG companies could express potential interest in booking capacity at Zeebrugge following the end of the existing Distrigas / Sonatrach contract in late 2006. Interest in securing the available capacity was strong, leading Fluxys to announce its decision to invest €165 million in doubling the capacity of the terminal to 9 bcm per annum.

All of the capacity from the beginning of 2007 has now been secured via three separate agreements.

Capacity deals signed

In late June 2004 Qatar Petroleum and ExxonMobil together signed an agreement for 4.5 bcm (3.3 million tonnes) of LNG per annum for a 20-year period. The capacity will be used to regasify gas from the Ras Laffan project which is 70% owned by Qatar Petroleum and 30% by ExxonMobil.




The Qatar Petroleum / ExxonMobil deal was closely followed by a deal with Distrigas for 2.5 bcm (1.8 million tonnes) per annum for 20 years.

In early July 2004, Tractebel Global LNG agreed to purchase 2.1 bcm (1.5 million tonnes) per annum of capacity.

Storage With its LNG infrastructure, swing capacity in contracts with the Netherlands and access to storage in Germany and France, Belgium has a lesser need for storage than other markets.

The two storage sites in Belgium are operated by Fluxys who then reinject the gas into their network as required.

An amendment to the Belgian Federal Gas Act in July 2001 regulated storage tariffs according to a cost based formula. Fluxys is required to submit its budget and cost proposals to the Federal Regulator for approval each year.

Table 6: Belgium, Storage Sites Name Type Operator Capacity Peak mcm) (mcm) Deliverability (mcm / day)Dudzele LNG Peak Shaver Fluxys 53 8.9Loenhout Aquifer Fluxys 580 10 Total 635 18.9 Source: Datamonitor D A T A M O N I T O R

In January 2006, Russian Ambassador to Belgium Vadim Lukov announced a site in Belgium was under consideration as a gas storage facility, with Dutch and Belgian companies expressing interest in the project; the facility is expected to be operational by 2010, to coincide with the opening of the Northern European Gas Pipeline (NEGP).




CHAPTER 5 BULGARIA

Market summary

Unlike many other markets in the Central and Eastern European region, gas does not play an overly significant role in the Bulgarian primary energy mix with demand levels remaining relatively modest. In recent years demand levels have fallen owing to economic downturn. Only a small percentage of demand is accounted for by the residential sector, indicating considerable medium term demand growth potential.

Despite various movements made towards market liberalisation, the state owned player, Bulgargaz, remains dominant. Full market opening is expected by 2007.

Indigenous production levels are minimal creating a significant degree of import dependency on Russian gas. The security of supply issues created by this import dependency will be eased from 2010 when the NABUCCO pipeline brings a much needed degree of supply diversity to Bulgarian gas supplies.





Table 7: Bulgaria, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.010 0.010 0.0%Pipeline Imports Russia 2.800 2.900 3.6% Total Pipeline Imports 2.800 2.900 3.6% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 2.800 2.900 3.6% Gross Supply 2.810 2.910 3.6% Exports 0.000 0.000 - -Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.000 0.000 -Stock Change 0.000 0.000 - Net Supply 2.810 2.910 3.6% DEMAND Residential 0.169 0.175 3.6%Non Residential 1.658 1.717 3.6%Power Generation 0.984 1.019 3.6% Total Demand 2.810 2.910 3.6% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

With minimal indigenous production, Bulgaria is almost entirely dependent on gas imports with all but a small proportion of gas supply coming from Russia under the terms of a long term Take or Pay contract that expires in 2010.

This reliance on one source of supply does create security of supply issues, though these are mitigated, at least to a certain extent, by the fact that Bulgaria acts as a transit state for Russian gas supplied to Turkey, Macedonia and Greece. Russia is currently considering transporting greater volumes of gas through Bulgaria, and of adjusting the infrastructure to enable another, separate import route into western Europe.

An additional element of short term supply security is provided by the country's 360 mcm underground storage facility at Chiren in the north west of the country

Demand overview

At less than 15% of primary energy demand, gas plays a relatively small role in Bulgaria. Somewhat unusually, demand levels have fallen in recent years. Demand peaked at 6.3 bcm in 1989 and currently stands at just half that figure owing to economic decline in the early and mid 1990s. Over the past decade demand has fallen by an average of 5% per year. The economy began to recover in 1997, though gas demand growth has remained both weak and erratic. More recently demand has shown signs of growth, though absolute levels of gas demand and demand growth remain modest. Continued economic recovery and development of the distribution system are likely to catalyse demand growth in the coming years.

Given that the non-residential sectors are by far the largest end users of gas, demand is particularly sensitive to the economic cycle. The vast majority of gas is sold by state-owned Bulgargaz selling directly to industrial customers with only a small percentage sold through distribution companies to residential and smaller industrial customers.




Figure 15: Bulgaria, Historical Demand

01234567

bcm

1965 1970 1975 1980 1985 1990 1995 2000

Consumption

Source: BP Statistical Review D A T A M O N I T O R

Figure 16: Bulgaria, Sectoral Demand


Pow er generation

35%

Non-Residential

59%

Residential6%

Source: Datamonitor / National Sources D A T A M O N I T O R





The Bulgarian energy sector is regulated by the State Energy and Water Regulatory Commission (SEWRC) which was formed in 1999 and assumed responsibility for the water sector in 2005.

The main tenet of energy law is the Bulgarian Energy Law which seeks to bring the market in line with the principles of the EU gas directive. Market opening began in 2004 and currently users of more than 20 mcm per year of gas are eligible to choose their supplier with full market opening planned by 2007.

The market is dominated by state owned Bulgargaz which owns the infrastructure grid and is present throughout the value chain. As such the company controls the importation of gas and also arranges for onward transmission through its grid to Turkey, Macedonia and Greece.

Infrastructure

State owned Bulgargaz is the owner and operator of the Bulgarian transmission grid through which it supplies gas directly to major industrial end users and to independent distributors. The main transmission pipeline for distribution usage is about 1,700 kms long. There is also a 945 kms transmission pipeline used to transit gas through Bulgaria to Turkey, Greece and Macedonia, with a ten-year extension to the contract, due to expire in 2010, currently under discussion.

The distribution network is around 1,150 kms in length and supplies gas to 30 municipalities. The private distribution companies sell gas to end users as well as owning and operating the distribution grid. During 2006 one distributor, Overgas, plans to construct another 138 kms of distribution infrastructure and increase its residential customer base by around 300%.

Bulgaria has one underground gas storage site at Chiren, built in 1974. The facility is owned and operated by Bulgargaz, and has a capacity of 360 mcm.

Various major infrastructure projects are currently at various stages of development. In 2002 the major Bulgarian, Turkish, Romanian, Hungarian and Austrian gas companies agreed to construct a transmission grid through their territories from the Caspian region and Central Asia, including Iran, Azerbaijan, Turkmenistan and Kazakhstan, to Central, Eastern and Western Europe. Aside from transit fees, the project, known as NABUCCO, will provide an opportunity for Bulgaria to further diversify its gas supplies. The pipeline should be operational by 2010 and have a total length of about 3,380 kms.




Figure 17: Bulgaria, Gas Grid

Source: Bulgargaz D A T A M O N I T O R




CHAPTER 6 CROATIA

Market summary

Since gas was first discovered in Croatia in 1918, the country has had a strong degree of self sufficiency. Until 1978 the country was completely self sufficient, though rising demand meant that imports began to be necessary.

All imports are currently made from Russia and meet around a quarter of end use demand. Considerable investments have been made in the upstream sector and production has increased strongly in recent years. As such, levels of self sufficiency are likely to remain high.

Since 2001 considerable progress has been made towards restructuring the industry. Full market opening is likely to occur by the end of 2006, though INA, the former monopoly player, still remains dominant.





Table 8: Croatia, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 1.750 2.199 25.7%Pipeline Imports Russia 1.050 1.053 0.3% Total Pipeline Imports 1.050 1.053 0.3% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 1.050 1.053 0.3% Gross Supply 2.800 3.252 16.1% Exports Italy 0.342 0.348 1.8% Total Pipeline Exports 0.342 0.348 1.8% Statistical Diffs -0.100 0.095 -Stock Change 0.225 0.200 -11.1% Net Supply 2.783 3.009 8.1% DEMAND Residential 0.742 0.776 4.6%Non Residential 0.806 0.921 14.3%Power Generation 1.235 1.312 6.2% Total Demand 2.783 3.009 8.1% Source: Datamonitor / National Sources D A T A M O N I T O R




Supply overview

Indigenous production makes a significant contribution to meeting Croatian gas demand. Current production levels are growing rapidly and sufficient to meet around three quarters of demand. Russian imports began in 1978, before which the country was entirely self sufficient. Until the end of the 1990s all production was onshore. In 1999 the country’s first offshore production facility, known as Ivana A, came on line.

The key player in the Croatian upstream sector is INA, though a significant role is also played by Italy’s Eni. Considerable investments have been made in the upstream sector and, as such, indigenous production is likely to continue increasing.

Figure 18: Croatia, Gas Production


0

0.5

1

1.5

2

2.5

1986 1990 1994 1998 2002

BC

M


Demand overview

Despite accounting for around 26% of the Croatian primary energy mix, absolute levels of gas demand in Croatia remain low at around 3 bcm per annum. Over the past decade demand has grown at an annualised average rate of around 2.1%.

In common with many other small gas markets, both end use demand levels and demand growth are very much driven by the power generation sector. End use demand patterns in other sectors have remained relatively constant in recent years.




Figure 19: Croatia, Sectoral Demand


Generation43%

Non Residential

31%

Residential26%


Figure 20: Croatia, Historical Demand

0

0.5

1

1.5

2

2.5

3

3.5

bcm

1986 1989 1992 1995 1998 2001 2004







The Croatian energy sector is regulated by the Croatian Energy Regulatory Agency, known as CERA. The liberalisation process within the market began in July 2001 following a concerted policy decision by the government to reform the market. New energy laws were passed covering the gas, power and oil markets.

The 2001 gas market reforms legislated for gas supply and distribution activities being carried out on the basis of free market principles.

In 2001 a new company, Plinacro, was established to take over responsibility for the country’s gas transmission activities from INA, the former monopoly incumbent. Currently users of more than 100,000 cubic metres per year are eligible to choose their supplier, though full market opening is considered likely to occur by the latter part of 2006 or early 2007.

INA was privatised in October 2003 when 25% and 1 share of the company were acquired by Hungary’s MOL. The remainder of the company is still in Government hands.

Infrastructure

The first transmission pipeline in the country, from Janja Lipa to Zagreb, was constructed in 1956. Today the Croatian transmission grid is about 1,660 kms long and mainly located in the east and north eastern parts of the country.

Gas imports from Russia form a key part of gas supply. These imports are made via the SOL line through Austria and Slovenia.

The distribution grid is owned and operated by 38 distribution companies, mainly owned by the local municipalities. Currently the distribution grid is around 14,200 kms in length.




Figure 21: Croatia, Gas Grid

Source: PLINARCO D A T A M O N I T O R




CHAPTER 7 CYPRUS

Market summary

Cyprus is not currently a consumer of natural gas, however this situation will change when plans to build an LNG reception terminal at Vasiliko near Limassol materialise. The technical and commercial bidding process is currently underway meaning that the project could potentially start up in 2009. In July 2005 an agreement was reached with Egypt concerning the supply of LNG as well as joint exploration activity.

A planned gas fired power plant near Limassol will be the initial focus of the gas imports, though the arrival of gas will also catalyse development of a mass market distribution grid.

Cyprus has also been mentioned as a possible destination point for a future extension to the EU-Arab pipeline which currently delivers Egyptian gas to Jordan and has expansion plans to extend to Syria and Lebanon. Despite these plans, the Cyprus extension is far from certain and LNG remains the most likely source of gas into Cyprus at the present time.




CHAPTER 8 CZECH REPUBLIC

Market summary

Until 1996, gas consumption in the Czech Republic consisted of town gas as well as natural gas. Since then all gas consumption has been of natural rather than manufactured gas.

Gas demand growth has been strong in recent years. Demand growth has averaged 4.3% per annum over the past decade. Despite this growth, coal is still the dominant fuel in the Czech economy accounting for around 46% of primary energy use. Coal is slowly being backed out of the energy mix by growing gas consumption.

With reserves of less than 4 bcm, the Czech Republic is heavily dependent on imported gas to meet demand.

The Czech Republic has long played a role as a transit route for Russian gas going to Western Europe.





Table 9: Czech Republic, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.168 0.216 28.6% Pipeline Imports Norway 2.504 2.335 -6.7% Russia 7.021 6.486 -7.6% Total Pipeline Imports 9.525 8.815 -7.5% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 9.525 8.815 -7.5% Gross Supply 9.693 9.031 -6.8% Exports Austria 0.051 0.088 72.5% Total Pipeline Exports 0.051 0.088 72.5% Statistical Diffs 0.000 0.000 - Stock Change 0.016 0.657 - Net Supply 9.658 9.600 -0.6% DEMAND Residential 2.958 2.940 -0.6% Non Residential 5.139 5.108 -0.6% Power Generation 1.561 1.552 -0.6% Total Demand 9.658 9.600 -0.6% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Town gas was widely used in the Czech Republic until it was finally phased out in 1996. Although the Czech Republic is a gas producer, production volumes are very small and meet less than 2.5% of demand. Russia has been exporting gas to the Czech Republic since 1967 and until 1992 was the sole source of supply, though since then imports have been diversified following the signing of a supply deal with Norway in 1997.

The Czech Republic’s geographical position and status as a transit route for Russian gas coming west makes supplies comparatively secure. Reliance on Russian gas is likely to continue to grow.

Figure 22: Czech Republic, Import Sources


Norw ay26%

Russia74%





Figure 23: Czech Republic, Gas Production


0

0.2

0.4

0.6

0.8

1

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004

BC

M


Demand overview

Unlike elsewhere in Europe, the power generation sector, at just 16% of 2004 consumption, plays a comparatively small role in energy demand.

The non-residential sector is the key end use sector accounting for more than 53% of total consumption. At an average of 4.3% per annum, the residential sector has been the key driver of demand growth over the past decade, a rate of growth more than twice that seen in the market overall.




Figure 24: Czech Republic, Sectoral Demand


Generation16%

Non Residential

53%

Residential31%


Figure 25: Czech Republic, Historical Sectoral Consumption

0

2

4

6

8

10

bcm

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004


Non Residental Pow er Generation Residential






The Czech energy sector is regulated by the Energy Regulatory Office (ERO) which was founded in January 2001 under Act 458/2000. An amendment to the Act was officially passed in January 2005 relating to the unbundling of transmission and distribution infrastructure as well as full market opening by 2007 in order to comply with the gas directive.

Compliance with the first gas directive was covered by the Czech Energy Act of 2000 which included legislation that originally intended to open 20% of the market by January 2005 and 33.3% by August 2008. This legislation was superseded in April 2004 by legislation that opened the market to industrial customers with advanced metering equipment from 1 January 2005. Under the terms of the amendment officially passed in January 2005, other industrial customers will become eligible to choose their supplier from 1st January 2006 with full market opening from January 2007. Transmission and distribution operations are due to be unbundled by 2007.

Under the terms of Act 458/2000, the ERO sets the maximum price at which Transgas can sell gas to distributors as well as the maximum price end users pay.

The Czech gas market is dominated by Transgas which is responsible for gas importation, transmission and storage. Transgas was under state control until May 2002 when 96.9% of the company’s stock was bought by RWE with the remainder acquired in 2003. At the same time RWE acquired the majority stake in Transgas it also acquired majority shareholdings in 6 of the country’s 8 regional gas distributors as well as near majority stakes in the remaining two. Since then a 54 new players have been awarded gas distribution licenses including E. On, Wingas, SPP, Shell as well as Gazprom which acquired a 37.5% stake in Gas-Invest in February 2005.




Infrastructure

The Czech pipeline system is controlled by Transgas. The country is supplied by, and transits, gas delivered from Russia via the Brotherhood line.

Table 10: Czech Republic, Storage Sites Name Type Operator Capacity Peak mcm) (mcm) Deliverability (mcm / day) Dolní Dunajovice Depleted Gas Field Transgas 700 12 Tvrdonice Depleted Gas Field Transgas 460 7 Štramberk Depleted Gas Field Transgas 420 7 Lobodice Aquifer Transgas 150 3.3 Tianovice Aquifer Transgas 240 4.2 Háje Salt Cavern Transgas 55 6 Total 2025 39.5 Source: Datamonitor / Transgas D A T A M O N I T O R

Figure 26: Czech Republic, Czech Republic Distribution Grid

Source: Ministry of Industry & Trade D A T A M O N I T O R




CHAPTER 9 DENMARK

Market summary

Denmark’s indigenous production capabilities mean that gas plays a significant role in the country’s energy mix and accounts for nearly a quarter of energy demand. However at just over 5 bcm, gas consumption is low by European standards.

Danish gas is exported to Germany and Sweden, and since July 2004, to the Netherlands.

The Danish gas sector has been outpacing the market opening demands of the EU for some time and has had a fully open market since the beginning of 2004, some three and a half years ahead of EU requirements.





Table 11: Denmark, Supply and Demand Balance BCM 2003 2004 SUPPLY Production 7.965 9.430 Pipeline Imports 0.000 0.000 Total Pipeline Imports 0.000 0.000 LNG Imports 0.000 0.000 Total LNG Imports 0.000 0.000 Total Imports 0.000 0.000 Gross Supply 7.965 9.430 Exports Germany 1.896 2.200 Netherlands 0.000 0.921 Sweden 0.972 0.978 Total Pipeline Exports 2.868 4.099 Statistical Diffs -0.004 -0.032 Stock Change 0.053 -0.220 Net Supply 5.154 5.143 DEMAND Residential 0.753 0.751 Non Residential 1.822 1.818 Power Generation 2.579 2.573 Total Demand 5.154 5.143 Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Denmark has been a gas producer since the late 1970’s. Since then production has risen steadily, with peak production of 9.43 bcm reached in 2004. Between 2003 and 2004 production grew by more than 18%.

Around a quarter of Danish gas production is reinjected into wells in order to optimise oil production.

Gas is produced by both the state oil company Dansk Olie og Naturgas and by the Danish Underground Consortium which is owned by DONG (50%), Shell (23%), Mærsk (19.5%), and ChevronTexaco (7.5%).

Figure 27: Denmark, Supply Sources

Production96%

German Imports4%

Production96%

German Imports4%





Figure 28: Denmark, Gas Production


0123456789

10

1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004

BC

M


Demand overview

At just over 5 bcm, gas demand in Denmark is comparatively small, despite the country’s role as an important gas producer. At 27% of primary energy, gas has made a significant penetration into the country’s energy mix though is still a long way away from overtaking oil which makes up around half of primary energy demand.

Power generation is the largest sector, both in terms of absolute consumption and demand growth. Over the past decade, gas demand in power generation has grown by an average of 6.6%, nearly twice the growth rate of the overall market.




Figure 29: Denmark, Sectoral Demand


Generation50%

Non Residential

35%

Residential15%


Figure 30: Denmark, Historical Sectoral Demand

0

1

2

3

4

5

6

bcm

1983 1986 1989 1992 1995 1998 2001 2004








The Danish gas market is regulated by the Danish Energy Regulatory Authority which was formed on 1st January 2000. The upstream is overseen by the Danish Energy Agency.

Key aspects of Danish gas legislation are laid out in the Natural Gas Supply Act no 449 which was passed in May 2000. Amendments were made in May and June of 2002, with the timetable for market opening governed by an Executive Order agreed on 20 May 2003.

Reform and restructuring of the gas market began in 2000. From January 2003 consumers of more than 25 mcm per year were able to choose their supplier. Later in the year this threshold was reduced to 12 mcm. The final stage of this process took place on 1st January 2004 on which date the full opening of the market took place, exceeding the market opening terms of the gas directive by three and a half years.

Since market opening took place DONG, the state-owned energy company, has increasingly been internationalising and diversifying. In late 2004 it acquired a 10.34% stake in Norway’s Ormen Lange gas field from BP as well as a 20% stake in Nova Naturgas, one of the two main players in Sweden’s gas market. It also spent the early part of 2005 buying stakes in various regional distributors. In late 2004 Dong agreed to merge with Elsam, the Dutch power utility, in which it already holds a 65% stake. Completion of the proposed merger remains far from clear following objections by Vattenfall, one of Sweden’s other power utilities and a 35% shareholder in Elsam.

The division of Elsam's assets between Vattenfall and DONG is currently being debated by EU competition authorities and it remains unlikely that the issue will be resolved before the middle of 2006. The need to finalise the current series of investments and acquisitions mean that plans to privatise up to 50% of Dong in 2005 have been postponed until 2006.





Danish wholesale market activity is a very recent occurrence currently at the very earliest stages of development. Towards the end of 2003 Gastra and the Nord Pool set up a joint project to examine the possibility of developing a Danish gas exchange. Shortly afterwards the prospects for wholesale trading in Denmark took a step forward when DONG set up a title transfer system allowing gas to be sold amongst parties using its pipeline system.

The feasibility study set up by DONG and the Nord Pool concluded that there was insufficient liquidity to justify an exchange but resolved instead to set up a trading hub. Since 1st May 2004 facilities such as a standard tradable contract and trading boards have been in place, though liquidity is still very much in its infancy, and interest has been largely limited to balancing related deals by the ten registered players.

Gastra had intended to officially launch the new hub, to be known as Gashub, in the latter part of 2004, however this was subsequently postponed owing to a lack of interest amongst players. The ongoing lack of liquidity in the market means that it remains unclear when the hub will be launched.

From the start of the gas year on October 1st 2004 Gastra has been offering short term capacity trading and on the day gas transfer.




Infrastructure

Pipelines DONG Transmission was legally unbundled to comply with the gas directive in early 2004 and was renamed Gastra.

Gas produced in the Danish North Sea is shipped through DONG’s infrastructure to the Nybro gas processing facility, both of which are open to third parties.

In July 2004 Denmark began exporting gas to the Netherlands, a new destination for its exports which previously consisted of just Germany and Sweden. A new 100 km pipeline was constructed between the Tyra West field in the Danish North Sea to the NOGAT pipeline which then moved the gas onwards to den Helder on the Dutch coast. The pipeline is operated by Maersk and is owned by the DUC. Capacity rights in the pipeline are allocated according to the partner’s shareholdings in the DUC.

Gastra is currently working with Nova Naturgas of Sweden and Statnett of Norway to construct a pipeline system linking Denmark, Sweden and Norway, which would extend the existing interconnections between the countries into a so called gas ring. If the project is successfully agreed and financed, start up of the system can be expected around 2011.

Storage

Table 12: Denmark, Storage Sites Name Type Operator Capacity Peak (mcm) Deliverability (mcm / day) Stenlille Aquifer DONG 330 6 to 11 LL Torup Salt Cavern DONG 420 6 to 12 Total 750 12 to 23 Source: DONG D A T A M O N I T O R




CHAPTER 10 ESTONIA

Market summary

With a population of just over 1.4 million and a primary energy mix more than half accounted for by coal, the Estonia gas market is unsurprisingly small.

Supply is sourced exclusively from Russia, though barring any unexpected political or economic disputes, be relatively secure.

Economic growth will continue to drive gas demand in the short to medium term – though with the dominance of coal and the small size of the potential market, Estonia will remain a marginal gas consumer.





Table 13: Estonia, Supply and Demand Balance BCM 2003 2004 (est) CAGR SUPPLY Production 0.000 0.000 - Pipeline Imports Russia 0.754 1.400 85.7% Total Pipeline Imports 0.754 1.400 85.7% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 0.754 1.400 85.7% Gross Supply 0.754 1.400 85.7% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.000 0.000 - Stock Change 0.000 0.000 . Net Supply 0.754 1.400 85.7% DEMAND Residential 0.114 0.21 85.7% Non Residential 0.434 0.81 85.7% Power Generation 0.206 0.38 85.7% Total Demand 0.754 1.400 85.7% Source: Datamonitor / National Sources D A T A M O N I T O R




Supply overview

Coal is the dominant component of the Estonia energy mix, meaning that gas accounts for a comparatively small proportion of demand. The role of gas in the power generation sector is curtailed by the widespread use of oil shale for generation purposes.

With no indigenous production, Estonia is entirely import dependent. Currently the only source of supply is Russia, from which gas is sourced via a long term supply contract with Gazprom that was extended in 2003 for at least another 12 years.

Demand overview

The non-residential sector accounts for the largest proportion of gas demand. Between 2003 and 2004 gas demand grew strongly, though remained very modest in absolute terms at less than 1.5 bcm.

Both demand levels, and the sectors this demand occurs in, are unlikely to change significantly in the short to medium term, despite ongoing expansion and upgrade work being undertaken to the distribution network.

Figure 31: Estonia, Sectoral Demand


Residential15%

Non Residential

58%

Pow er Generation

27%






The Estonian gas industry is regulated by the Estonian Energy Market Inspectorate (EMI), also known as the Energiaturu Inspektsioon. The EMI was formed by the Ministry of Economic Affairs and Communication in February 2003.

The majority of legislation governing the gas market is contained in the Natural Gas Act 2003 which came into effect on 1st July 2003. The Act gave consumers using more than 200,000 cubic metres per annum the right to choose their supplier. Existing legislation means that around 95% of the market is open to competition.

Eesti Gaas is the dominant player in the gas market and operates the transmission network and much of the distribution infrastructure. It was privatised in 1993 and is owned by Gazprom (37.02%), E.ON Ruhrgas (33.60%), Fortum (17.72%), Itera (9.75%) with the remaining 1.91% of stock held by various individuals and institutions.

Infrastructure

Russian gas imports enter Estonia via two pipelines, one in the south east near the Russian city of Pskov and one in the north east near Narva. Gas then enters the 2,200 kms of distribution pipelines.

Finland's Gasum and Eesti Gaas are currently developing plans to construct a pipeline between Helsinki and Tallinn. The project will allow Estonia to act as a transit point for Russian gas exports to Finland. The project has a target start up date of 2010.




Figure 32: Estonia, Gas Distribution Grid

Source: Eesti Gaas D A T A M O N I T O R




CHAPTER 11 FINLAND

Market summary

In order to meet its small, but growing, gas demand, Finland is entirely dependent ion imported Russian gas.

Finland has applied for, and been awarded, a derogation from the market opening requirements of the gas directive on account of its reliance on one single supply source and the fact that it is not connected to the main European transmission grid.

The penetration of gas into the country’s energy mix is low by European standards. Consumption is heavily dominated by the industrial and commercial, and power generation sectors.

Fortum, one of Scandinavia’s leading power market players, has been increasing its role in the Finnish gas market and now owns 31% of Gasum, Finland's main gas company and operator of the national gas grid.





Table 14: Finland, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.000 0.000 - Pipeline Imports Russia 5.023 4.866 -3.1% Total Pipeline Imports 5.023 4.866 -3.1% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 5.023 4.866 -3.1% Gross Supply 5.023 4.866 -3.1% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.012 0.006 - Stock Change 0.000 0.000 - Net Supply 5.011 4.860 -3.0% DEMAND Residential 0.031 0.030 -3.1% Non Residential 1.298 1.257 -3.1% Power Generation 3.682 3.567 -3.1% Total Demand 5.011 4.854 -3.1% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Finland’s lack of gas resources mean that it is entirely dependent on imported Russian gas. This already weak security of supply situation is exacerbated by the fact that Finland is not currently connected to the European gas grid and is thus unable to diversify supplies unless new infrastructure is constructed.

All of Finland’s gas is delivered under various long term agreements with Gazprom. These contracts date back to 1973. In September 2005 these contracts were extended until 2025, with the amount imported increasing by 15%.

Deliveries are made via two 32 inch pipelines, one of which came on line in 1973 with the other built in 1998.

Demand overview

At just 14% of primary energy demand, gas plays a less dominant role in the Finnish energy mix that it does in many other European countries.

The undeveloped nature of both the market and the distribution infrastructure means that power generation and industrial and commercial users of gas are by far the dominant off-takers, making up 99% of demand. In the industrial and commercial sector, the pulp and paper industry is the most significant user of gas.




Figure 33: Finland, Sectoral Demand


Generation73%

Non Residential

26%

Residential1%


Figure 34: Finland, Historical Sectoral Demand

0

1

2

3

4

5

6

bcm

1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004








Finland's gas market is regulated by the Energy Market Authority, known as the Energiamarkkinavirasto. Originally the Energiamarkkinavirasto was created to regulate the power sector, though the passing of the Natural Gas Act on 1st August 2000 widened its remit to include gas.

The sector is governed by the Natural Gas Act, which came into force in August 2000. Under the terms of the Natural Gas Act, eligible players are allowed to trade on a secondary gas market operated by Kaasupörssi Oy. Eligible parties are defined as those that have annual consumption levels in excess of 5 mcm, are connected to remote meter reading equipment and have agreed their pricing structures after the Natural Gas Act took effect.

Finland has been given a derogation on the requirement to open its gas market under the terms of the directive. Countries that have only one source of supply and are not connected to the main European transmission grid can claim this derogation.

The market opening derogation awarded by the EU means that the prime focus for the restructuring of the gas market relates to the unbundling of the transmission network.

Currently the Finnish gas market is dominated by Gasum Oy, the sole importer and supplier of gas as well as the owner and operator of the gas grid. Gasum Oy is owned by Fortum (31%), Gazprom (25%), the Finnish government (24%) and E.ON Ruhrgas (20%).

Fortum, one of Scandinavia’s leading power companies, has recently been developing its role in the Finnish gas sector. In late 2004 it acquired an additional 6% stake in the Finnish gas grid, and in January 2006 purchased the City of Espoo’s 34% holding in E.ON Finland.

Infrastructure

Pipelines Finland’s gas infrastructure is concentrated in the southern part of the country.. Currently the country’s only import point is on the Russian border, close to Imatra. Plans are being developed to create another import point, also near Imatra, to import further volumes of Russian gas from the Shtokmanovskoye development in the Barents Sea. This project will merely serve as a way of importing increased gas volumes and will not do anything to reduce Finland’s over reliance on Russian gas.




The transmission grid is around 1,000 kms in length whilst the distribution network consists of 1,145 km of pipeline. Gasum Oy is considering extending gas distribution within the country, with the prospect of Turku being supplied with gas by 2008 provided this is likely to be profitable.

Gasum and Eesti Gaas of Estonia are in the early stages of developing plans to construct a ‘Balticconnector’ pipeline line between Helsinki and Tallinn (not Paldiski to Turku, as some early reports claimed) . If this project materialises it would connect Finland to the Baltic network thus creating a second route for Russian gas imports. Security of supply would also be boosted by the fact that such a pipeline would allow Finland direct access to Latvia’s Inculkans gas storage site allowing storage withdrawals to be made if pipeline supplies are interrupted. Connecting the Estonia-Finland pipeline to the North European pipeline, on which construction began in 2005, has not been ruled out. A decision on the ‘Balticonnector’ project is expected in 2006, but the pipeline is unlikely to be completed before 2010.

Figure 35: Finland, Gas Grid

Source: Gasum Oy D A T A M O N I T O R




CHAPTER 12 FRANCE

Market summary

The dominance of nuclear power in France means that gas has traditionally played a comparatively minor role in the French energy mix. However, this role is growing at a slow but steady rate, with gas now accounting for 15% of primary energy consumption. Frances’ already low levels of gas production continue to decline, meaning that imports will become increasingly important in the coming years.

The prospects for gas use in the power generation sector remain unclear, particularly following the French Government’s White Paper on energy policy in late 2003 which resulted from a national debate on energy policy earlier in the year. The paper recommended the promotion of increased energy efficiency and a significantly greater role for renewable energy, but most significantly recommended the option to maintain the right to build new nuclear powered electricity generation capacity. If this were to happen, it would significantly curtail future gas demand. The White Paper stated that any decision to adopt gas as a power generation fuel would be dependent on the evolution of gas prices over the following 10 to 20 year period and pointed out that any tax on greenhouse gas emissions would give nuclear power a comparative advantage. A memorandum presented by France at a meeting of EU finance ministers in early 2006 re-emphasised the importance of nuclear power, and also of increasing gas supplies and infrastructure, for Europe as a whole.

The development of competition in France, particularly in the south of the country, is currently being hampered by a lack of interconnections with other countries. The LNG projects currently being undertaken will go some way towards easing this problem, though serious efforts should be made to create a link with Italy and to supplement the existing connection with Spain. Without this, there is a danger that France will become two distinct markets – a northern market where the connections with Norway, Belgium and Germany allow competition to develop efficiently and a southern market lagging someway behind.





Table 15: France, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 1.583 1.390 -12.2% Pipeline Imports Netherlands 7.818 8.714 11.5% Norway 12.584 11.597 -7.8% Russia 10.561 9.217 -12.7% Unspecified 3.418 9.028 164.1% Total Pipeline Imports 34.381 38.556 12.1% LNG Imports Algeria 9.040 5.422 -40.0% Total LNG Imports 9.040 5.422 - Total Imports 43.421 43.978 1.3% Gross Supply 45.004 45.368 0.8% Exports Unspecified 0.946 0.395 -58.2% Total Pipeline Exports 0.946 0.395 -58.2% Statistical Diffs 0.039 1.040 - Stock Change 0.575 0.506 -12.0% Net Supply 44.594 44.439 -0.3% DEMAND Residential 22.628 23.058 1.9% Non Residential 17.798 18.136 1.9% Power Generation 4.166 4.245 1.9% Total Demand 44.592 45.439 1.9% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

France’s very low levels of indigenous production mean that it is heavily dependent on imports to meet its gas needs. Current reserves are estimated at just 13 bcm, giving a Reserves to Production ratio of less than a decade. Around 70% of indigenous production is accounted for by Total’s Lacq field in the south west of the country (the Aquitaine region as a whole accounts for 95% of domestic production), though this meets just a small percentage of national demand. Lacq has been in decline for a number of years and is expected to become depleted in the near term.

With increasing demand, declining production and little or no prospect of any significant discoveries in the foreseeable future, France is set to continue its import dependency in the coming years. With well diversified sources of supply, various pipeline connections, two existing LNG import terminals and one at the advanced development stage, both current and future supply is very secure.

In July 2005 France imported its first cargo of Egyptian LNG, further diversifying LNG imports from Algerian, Nigerian and Oman.

Figure 36: France, Gas Production


01

23

45

67

89

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004

BC

M





Figure 37: France, Import Sources


Other8%

Algeria (LNG)21%

Netherlands18%

Norw ay29%

Russia24%


Demand overview

The penetration of gas into the French energy mix has been curtailed by the strong dominance of nuclear power. The role of nuclear has grown substantially in France over the past 30 years, and now accounts for 38% of primary energy consumption – the highest proportion in the world. The increased reliance on nuclear power has backed both oil and coal out of the energy mix and has limited gas to a penetration of 15%.

Despite the strong dominance of nuclear power, natural gas consumption has been increasing steadily, with annualised growth of 3% over the past decade. Much of this growth has been driven by a steady, movement towards gas as a power generation fuel. Over the decade to 2004, gas use in power generation grew by an average of 21% per year. More recently this growth has slowed, though still remains strong having grown by 5% between 2003 and 2004.




Figure 38: France, Sectoral Demand


Generation9%

Non Residential

40%

Residential51%


Figure 39: France, Historical Sectoral Demand

0

10

20

30

40

50

bcm

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004








France has shown a marked reluctance to embrace energy market liberalisation and as such has lagged far behind many of its neighbours in opening its markets. The first EU Gas Directive (98/30/EC) was only incorporated into French law at the beginning of 2003 through the passing of National Law 2003-8, some three years past the deadline set by the EU.

Despite this reluctance, and the continued dominance of Gaz de France (GdF), some degree of progress has been made and a greater willingness to embrace liberalisation is now perceptible. In August 2000, GdF opened its grid to Third Party Access to consumers using in excess of 25 million cubic metres per annum. Although this threshold only included about 100 large industrial users, it did equate to a market opening of around 20% in volume terms. In August 2003 this threshold was reduced to include companies using more than 15 million cubic metres per annum, boosting market opening to a theoretical 28%.

Now that the second Directive is in force, all non-residential users are able to choose their supplier, which equates to a market opening of around 70% in volume terms and more than 640,000 sites. However, switching has been much slower than in other markets with just 16% of eligible volume having switched.

France’s energy sector is regulated by the Commission de régulation de l'Energie (CRE). It was formed in 2000 to regulate the power sector and took on responsibility for gas regulation in 2003. Much of the progress made towards liberalisation can be attributed to the momentum provided by the CRE.

GdF still has an extremely strong control on the French market, despite the loss of its monopoly on gas importation and distribution in January 2003. The entry to the market of firms such as Distrigas, BP and E.ON Ruhrgas does not seem to have had an overly negative effect on GdF’s dominance up to now, despite the market share they are slowly but steadily gaining amongst large industrial gas users. In November 2005 Gazprom entered the markets and has stated its aim to secure 10% of the market.

Despite the apparent softening in the anti-liberalisation stance adopted by the French Government, the planned privatisation of the two monopoly energy players, Electricité de France and Gaz de France, has faced strong opposition, particularly from the unions. Power and gas supplies have been disrupted by various strikes caused by Unions voicing their position to the privatisation. The Gaz de France IPO was launched in July 2005 when 22% of the company was floated raising EUR4.5 billion of which around EUR2.5 billion was received by the French government with the remainder going to the company itself. However, the government has capped GDF’s




regulated gas tariff increases since the privatisation. While beneficial to consumers, this has impacted on GDF’s profitability.

Key factors limiting the development of competition in France

A marked dichotomy exists between northern and southern France in the conditions allowing competition to develop and take hold. This is largely due to the fact that the majority of entry points for “competitive” gas are in the north and east of the country rather than the south. The CRE sought to combat this barrier to competition by introducing various measures to make pipeline capacities more transparent, a reduction in the number of balancing zones, a three year series of annual gas release programmes by both GdF and Total in the south of the country and by encouraging the development of import facilities in the south.

Under the terms of the gas release programme GdF are required to auction 15 TWh per year and Total 1.1 TWh per year for three years. At the first auction in October 2004 GdF sold all its required volume whilst Total was able to sell only half its volume. Subsequently in February 2005 GdF sold a further 5 TWh per year to BP and Gas Natural. The three year auction cycle is intended to help develop competition until the start up of the Fos II LNG project which will catalyse competition by introducing competitive supply into the area.

Limited demand exists in the short and medium terms for gas in the power generation sector owing to the dominant role of nuclear in French electricity generation. The results of the White Paper on energy policy issued in late 2003 indicate that nuclear power is likely to remain dominant with few signs of a “dash for gas” towards gas fired power of the type seen in the UK and elsewhere.

France’s short to medium term gas requirements are already being met by existing long term contracts from sources such as Russia, the Netherlands, Norway as well as Nigerian and Algerian LNG. On average these contracts still have around 15 years left to run. Consequently, the scope for new supply sources and spot gas to break into the market is diminished, particularly given the decision by GdF in 2003 to sign new contracts with the Netherlands and Egypt as well as extending an existing contract with Russia until 2015. To combat this problem the CRE has indicated that it regards making it easier for large industrial users to secure gas at European hubs such as the TTF and Bunde as being a high priority.





A very limited wholesale market exists, at least in theory, in France following the creation of notional trading zones, known as Points d’Echange de Gaz or PEGs, in 2004. So far the limited volumes that have been traded by the fifteen registered players have seen deals transacted at levels close to Zeebrugge levels. The PEG market is operated by GRT Gaz, previously known as GdF transport.

Despite being small, volumes are growing rapidly having reached surpassed the 800 transactions per month stage in November 2005, though this equates to a total volume of less than 0.5 bcm.

So far the majority of trading activity has taken place in one of the northern PEGs owing to the fact that this is the only area where sufficient supply diversity exists to create liquidity.

This reflects the fact that, in many ways, France is actually two distinct markets – the northern half of the country is home to the majority of entry points for “competitive” gas with its pipelines connections importing gas from Norway, Belgium, Russia, the Netherlands and the UK. In contrast the southern half of the country has just one entry point for gas imports – the Fos-sur-Mer LNG terminal near Marseille.

This north / south divide in the availability of competitive gas will continue to hold back and restrain the development of the French wholesale gas market, though the situation will be eased to some degree when an additional LNG terminal, a joint project between Total and GDF, comes on line at Fos-sur-Mer (Fos Cavaou) in 2007. The Euskadour pipeline, which imports gas from Algeria via Spain into south west France, began to give further impetus to reducing this north / south divide following its inauguration in November 2005. Its current capacity is 0.5 bcm per year, but studies are under way to assess the feasibility of raising this to 3 bcm per year.

In December 2004 a standardised trading agreement for PEG deals was devised by the European Federation of Energy Traders. These standardised terms will facilitate easier trading and are likely to give a boost to liquidity.




Infrastructure

LNG After Spain, France is Europe’s largest importer of LNG. LNG is an important element in meeting French gas demand and ensuring security of supply. The vast majority of LNG supply is sourced from Sonatrach in Algeria, though small volumes are also supplied by Nigeria and Oman.

Currently there are 2 operational regasification terminals in France, with another planned. The new capacity will not only introduce new supplies to the market but will also help catalyse the liberalisation process by bringing new entrants to the market. The Fos II project is particularly necessary given that the existing Fos terminal cannot accept the new generation of large modern tankers and is already operating at full capacity. In October 2004 Total agreed to buy 2.25 bcm of the project's 8.25 bcm capacity. In order to facilitate greater competition, the CRE has recommended that no individual supplier be allowed to have access to more than two thirds of the new regasification capacity and that at least 10% of the new capacity be used for short-term spot supplies. The current status of ExxonMobil’s projected facility (Fos III) is not clear.

Table 16: France, LNG Infrastructure Name Operator Size Status Fos GdF 4.5 bcm Existing Montoir GdF 10 bcm Existing Fos II GdF 7 bcm Under construction expected start up 2007Fos III ExxonMobil 7 bcm At planning/development stage Source: Datamonitor / National Sources D A T A M O N I T O R

Pipeline infrastructure

Through its previous monopoly status, GdF controls all pipeline import capacity. To drive competition the CRE has introduced various gas release schemes.

Key French pipelines include:




Franpipe – the inauguration of the Franpipe in late 1998 was a key milestone for the French gas industry: for the first time France had had a direct pipeline link with a foreign source of supply. The 16 bcm per annum pipeline connects the Norwegian Draupner platform with Dunkirk on the northern French coast, 521 miles away. Franpipe is operated by Gassco and owned by the Gassled partners. As France’s import dependency grows due to increased demand and an imminent plateau in production, Franpipe will play an increasingly large role in supplying the market.

MEGAL – jointly owned by GdF and Ruhrgas, MEGAL delivers Russian gas to France and the French / German border via the Czech Republic and Austria.

Belgian transit lines – various pipelines carry Dutch, Norwegian and occasionally UK gas into northeastern France.

Les Marches du Nord-Est – a transit pipelines in eastern France routing Norwegian gas to Italy.

Trans-Pyrenean Pipeline – a transit pipeline delivering Norwegian gas to Calahorra in northern Spain.

Pipelines

In mid 2003, the CRE (along with the Spanish and Portuguese regulators) openly declared their intention to offer incentives to encourage increased pipeline interconnections between France and Spain. Investment of this type is central to redressing the imbalance between the import capabilities of northern and southern France which is causing pipeline system congestion and curtailing the development of competition in the south.

Subsequent to this, the CRE announced its decision to allow a 12% pre-tax rate of return (as opposed to the usual 9%) to the Euskadour 1 project which began importing Algerian gas via Spain to south west France in November 2005, thus easing the north / south divide and stimulating the gas markets in the south of the country.

In October 2004 the EU Competition Authority approved plans for Total to acquire various pipeline assets in south west and central France from GdF. In an attempt to mitigate the monopoly on gas transport and storage in the south west that the deal will give Total, the CRE imposed a series of conditions relating to the provision of effective TPA. The deal is part of the dissolution of cross-shareholdings Total and GdF hold in two network operators - Compagnie Française du Méthane and Gaz du Sud-Ouest. The deal will see Total will absorb GdF’s 30% stake in Gaz du Sud-Ouest, various transmission lines, the Izaute storage site, various Compagnie Française du Méthane customers in central France and a 33.3% stake in the Fos II LNG site. Part of the financial element of this deal involves GdF adding Total’s 45% stake in CFM to its existing 55% stake, thus giving it full ownership of the company. Estimates made by




the CRE indicate that the deal will give GdF 85% of the French market, Total 11% and new entrants 4%.

Table 17: France, LNG Infrastructure Name Type Capacity (mcm) Etrez Salt Cavity 430 Manosque Salt Cavity 260 Tersanne Salt Cavity 200 Beynes profons Aquifer 350 Beynes superior Aquifer 190 Cere-la-Ronde Aquifer 350 Cerville-Velaine Aquifer 650 Chemery Aquifer 3.45 Germignysur Colombs Aquifer 760 Gournaysur – Aronde Aquifer 1,000 Izaute Aquifer 1,250 Lussagnet Aquifer 720 St Claire sur Epte Aquifer 410 Saint-Illiers Aquifer 580 Soings-en-Sologne Aquifer 220 Source: Datamonitor D A T A M O N I T O R




Figure 40: France, Transmission Grid

Source: CRE D A T A M O N I T O R




CHAPTER 13 GERMANY

Market summary

Despite being Europe’s second largest gas market in consumption terms, Germany has been particularly slow, not to mention reluctant in some quarters, to liberalise its gas market.

The threat of legal sanctions by the European Commission has encouraged a more proactive approach to adopting and complying with the terms required by the gas directive, though it was only as recently as July 2005 that a key piece of legislation was officially adopted bringing the liberalisation process in line with EU legislation.

Germany is a complex gas market with a number of players active in the ownership and operation of distribution, transmission and storage infrastructure. Distribution is particularly fragmented with around 700 regional distribution companies known as Stadtwerke.





Table 18: Germany, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 22.217 20.559 -7.5% Pipeline Imports Netherlands 19.350 22.486 16.2% Norway 23.918 25.140 5.1% Russia 37.287 39.111 4.9% Others 3.923 3.372 -14.0% Total Pipeline Imports 84.478 90.109 6.7% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 84.478 90.109 6.7% Gross Supply 106.695 110.668 3.7% Exports Unspecified 7.681 8.810 14.7% Total Pipeline Exports 7.681 8.810 14.7% Statistical Diffs -0.882 -0.876 - Stock Change 1.076 -2.395 - Net Supply 100.972 100.339 -0.6% DEMAND Residential 33.986 33.773 -0.6% Non Residential 44.161 43.884 -0.6% Power Generation 22.825 22.682 -0.6% Total Demand 100.972 100.339 -0.6% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Indigenous production is a key element of German gas supply and accounts for 20% of total consumption. At 200 bcm Germany currently has an R/P ratio of 12 years. All of Germany’s fields, with the exception of one, are located onshore.

The majority of production is located in the north west of the country in Lower Saxony, close to the Dutch border. This means that German gas production shares many of the geological and geophysical characteristics of Dutch supply – namely a high degree of flexibility and a combination of both low and high calorific value reserves.

LNG does not currently play a role in the German energy mix, though may do so if E. On’s plans to develop a terminal at Wilhemshaven are successful.

Figure 41: Germany, Gas Production


0

5

10

15

20

25

30

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004

BC

M





Figure 42: Germany, Imports By Source

Import Supply SourcesOthers

4% Netherlands25%

Norw ay28%

Russia43%


Demand overview

In consumption terms, Germany is the biggest gas market in the EU with the exception of the UK. At 23% of total demand, gas consumption in the power generation sector is comparatively low owing to the fact that the majority of gas fired power in the country is used only for peak rather than baseload generation.

As the German government seeks to phase out nuclear power by 2021, the role of gas in the German power generation market will grow significantly in the short to medium term. Over the past decade gas use in power generation has been the fastest growing sector, increasing at an annualised average rate of 3.5% compared with grown of less than 2% in the market overall.




Figure 43: Germany, Sectoral Demand


Residential34%

Non Residential

43%

Pow er Generation

23%


Figure 44: Germany, Historical Sectoral Consumption

0

20

40

60

80

100

120

bcm

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004








Germany's gas sector is governed by three main pieces of legislation:

The Energy Industry Act, known as the Energiewirtschaftsgesetz, which outlines the principle concepts relating to gas distribution, transportation, storage and supply.

The Federal Mining Act (Bundesberggesetz) relates to E & P activity as well as underground storage.

The Act Against Restraints to Competition (the Gesetz gegen Wettbewerbeschränkungen) relates to general competition law applicable to the gas sector.

Despite its well developed gas sector in terms of consumption, supply diversity and infrastructure development, Germany’s gas industry has lagged behind many other markets by lacking a regulatory body. Instead, the sector has traditionally been governed by general competition law, mainly by the Federal Cartel Office, with a high degree of self regulation owing to the Verbändevereinbarung agreement signed in July 2000.

In the past, attempts to reform the German market have relied on negotiated access with little, if any, emphasis placed on mandatory access. The Government delegated the task of improving the system to the industry rather than setting out legislation itself. In 2002 the industry steering groups agreed a system under which pipeline and storage site owners were obliged to offer available capacity to third parties on an open and non-discriminatory basis. Whilst theoretically a step forward in liberalisation terms, the agreement failed to make a significant impact because it lacked legal backing, meaning that refusals to offer available capacity could only be appealed against under the Act Against Restraints to Competition legislation.

Germany’s lack of pro-action in liberalising its energy market resulted in the European Commission threatening to invoke legal proceedings in 2001 if the process of liberalisation was not initiated. This threat did catalyse some action, but Germany has still been noticeably reluctant to embrace the gas directive. The threat of sanctions resulted in the German government proposing a Bill to amend and update the Energiewirtschaftsgesetz, though it took until May 2003 for the legislation to come into force following long and drawn-out (legislative) delays in the German parliament.

The updated legislation required the German Ministry of Industry to undertake a monitoring report analysing the progress made in reforming the market in accordance with the terms of the gas directive. The report was delivered in August 2003 and concluded that progress made so far towards liberalising the market had been minimal.




The report found that a lack of transparency in available pipeline capacity data and the fact that standardised contracts were not being used meant that competition was being stifled. The Monitoring Report also concluded that virtual trading should be introduced by merging the broad based ownership of pipelines into a small number of balancing zones and that an entry-exit model be introduced.

In April 2004 the German cabinet passed a draft law confirming various previously discussed liberalisation measures, including the widening of the remit of the postal and telecoms regulator to include the energy sector and the unbundling of companies in the gas sector. The new law came into force in July 2005, officially establishing the energy regulator and bringing Germany into full compliance with the EU directive.

Following the results of a legal challenge by Marathon regarding refused network access, the European Commission, BEB and E.ON Ruhrgas collectively agreed to the introduction of an entry-exit model. A 3 zone entry–exit model became operational on the BEB system in July 2004, with E.ON Ruhrgas introducing a 5 zone entry-exit model in November 2004. In May 2005 RWE replaced its point-to-point access system with an entry-exit model whilst Wingas followed suit in June 2005.

In May 2004 E.ON Ruhrgas held its second gas auction where 35 of the 39 lots totalling 3.6 bcm for delivery at Waidhaus were sold to seven parties. This second auction was much more successful than the country’s first auction where just two buyers bought gas for delivery at Emden. The 1.7 bcm left unsold from the first auction was carried over into the second, whilst the 0.4 bcm left unsold from the second auction was carried over to the 2005 sale. The 2005 auction was held in May with a total of 39 TWh sold to seven players. The next auction is scheduled for May 17th 2006.


The Bunde market was an early attempt to facilitate continental gas trading. The Bunde hub is located on the Dutch / German border at Oude Statenzijl and takes its name from the closest town on the German side of the border. Two hub operators were originally set up to facilitate trading – NWE Hubco to run the German operations and Eurohub on the Dutch side of the border. The services offered by the two companies also covered the Emden area where gas from Norway was landed via the Europipe and Norpipe pipelines. Although showing potential in the early days following its launch in 2002, the Bunde hub has subsequently been very slow to develop with progressively negligible volumes traded, largely as a result of difficulties in gaining access to pipeline capacity in Germany. The formation of the TTF in November 2002 provided stiff competition and further diminished both the liquidity and attractiveness of the Bunde hub.




In April 2004, NWE Hubco and Eurohub joined forces to create EuroHub GmbH. This deal means that the new company is now effectively one third owned by Gas Transport Services B.V (see TTF section) with the remaining two thirds held equally by E.ON Ruhrgas, Statoil, BEB and Wingas. Interest at the EuroHub has been lacklustre with just four players signing up for the pilot service agreement in June 2005. The pilot service agreement period has now been extended until the end of 2005.

The Bunde and Emden area contains the landing sites for gas from the NGT, Europipe and Norpipe pipelines. Assuming access to pipeline capacity can be obtained, gas can be moved to a number of destinations in Germany, the Netherlands and surrounding areas.

Infrastructure

Gas imports, and hence import infrastructure, are key aspects of the German gas sector. Russian gas is received at import points on the Austrian, Czech and Polish borders, whilst Norwegian gas comes ashore near Emden on the north coast of Germany. Gas from the UK and the Netherlands is imported via a border crossing in the northwest at the Dutch border whilst Danish gas is imported on the border near Flensburg. In addition to being a gas importer, Germany also plays an important role as a transit state for Russian gas going further west.

The size, magnitude and ownership of the German grid make it one of the most complex pipeline networks in the world. Germany has a number of TSO’s including Ruhrgas, Wingas, BEB and VNG. Of these, Ruhrgas is the main TSO in that it carries more than two thirds of all gas consumed in the country. Germany differs from many other markets in that the ownership of the gas grid is spread amongst a number of players. This reflects the fact that in the past market development was driven by a number of players who enjoyed legal protection of their investments rather than the emergence of a single, dominant monopoly required to grant access to third parties. In January 2006 Vattenfall announced that it would revive its German gas trading arm, which had been frozen since 2004.

Distribution is undertaken by around 700 regional distribution companies known as Stadtwerke. Usually the Stadtwerke are owned by the relevant municipality.

Key pipelines in Germany include:

MEGAL - co-owned by GdF and Ruhrgas, MEGAL’s 22 bcm annual capacity delivers Russian gas in Germany as well as acting as a conduit for onward transmission to France.




TENP - runs from the Netherlands into Germany and then onwards to both Switzerland and Italy. Current capacity is around 19 bcm. TENP is also used to import UK gas via the Netherlands.

STEGAL - brings Russian gas into Germany via the Czech Republic. 8 bcm annual capacity.

NETRA - an internal pipeline moving gas from Wilhelmshaven in the north to Bernau.

MIDAL - moves gas from Emden, close to the Dutch border to Ludwigshafen in southwest Germany.

JAGAL - owned by Wingas, JAGAL moves Russian gas into and around Germany from the Polish border.

Norpipe – Norwegian gas is imported to Germany at Emden via the Norpipe.

Europipe – Like Norpipe, the Europipe brings Norwegian gas into Germany, slightly north of Emden at Dornum.

Polish Link - In early 2005 Poland’s PGNig and VNG agreed to construct a 1.5 bcm per annum pipeline between Germany and Poland. Work is likely to begin in the second part of 2006.

NEGP (Baltic Piepline) - Two of Germany’s largest suppliers, BASF and E.On along with Gazprom are jointly developing a new pipeline link between Russia and Germany. The project, known as the North European Gas Pipeline Project or the Baltic pipeline, is scheduled for completion in 2010. BASF and E. On collectively own 49% with Gazprom holding the remaining 51%. The 27.5 bcm pipeline is being constructed underneath the Baltic Sea and will transit Russian gas directly into northern Germany, bypassing the traditional Eastern European transit routes. Plans have also been mooted to double capacity to 55 bcm by 2012.




Table 19: Germany, Storage Sites Name Type Operator Capacity Peak (mcm) Deliverability (mcm / day) Bad Lauchstadt Depleted Gas Field VNG 426 5.7 Bierwang Depleted Gas Field Ruhrgas 28.8 1.3 Breitbrunn Depleted Gas Field RWE 550 6 Dotlingen Depleted Gas Field BEB 2.025 20.2 Inzenhan West Depleted Gas Field RWE 500 6.7 Rehden 1 Depleted Gas Field Wingas 4.2 57.6 Reitbrook Depleted Gas Field Preussaa 283 8.4 Uelsen 1 Depleted Gas Field BEB 380 5.4 Wolfersberg Depleted Gas Field RWE DEA 320 5 Berlin Aquifer Gasag 570 7.2 Bad Lauchstadt 2 Salt Cavity VNG 661 20 Bremen Lesum 1 Salt Cavity SW Bremen 81 3.17 Epe 1 Salt Cavity Thyssengas 192 7.7 Epe 2 Salt Cavity Ruhrgas 1.528 36 Etzel Salt Cavity Ruhrgas 500 31.4 Harsefeld Salt Cavity BEB 140 7.2 Huntorf 1 Salt Cavity EWE 60 8.4 Krummhorn Salt Cavity Ruhrgas 116 6 Nuttermoor 1 Salt Cavity EWE 910 24 Ronne bei Kiel Salt Cavity SW Kiel 62 3.6 Stassfurt 1 Salt Cavity KSS 22 2.4 Xanten Salt Cavity Thyssengas 195 6.7 Source: Datamonitor / National Sources D A T A M O N I T O R




CHAPTER 14 GREECE

Market summary

With minimal gas reserves, Greece is heavily dependent on imports to meet its gas demand.

Until relatively recently Russia was the only source of gas imports, raising some important security of supply issues. The issues surrounding this over-reliance on a single import source has since diminished to a degree with the arrival of Algerian LNG and the decision to construct a pipeline link with Turkey to allow the importation of Azeri gas, due on stream by the end of 2006.

Greece’s geographical location means that it has a potential role in the future as a transit state to take gas from eastern supply sources to markets in the west. The completion of a pipeline link with Italy will be a key part of this development when it comes on line in 2010.

With low levels of gas penetration and the increased availability of new gas, demand growth in Greece is likely to be strong in the future.





Table 20: Greece, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.027 0.023 -14.8% Pipeline Imports Russia 1.863 2.172 16.6% Total Pipeline Imports 1.863 2.172 16.6% LNG Imports Algeria 0.555 0.469 -15.5% Total LNG Imports 0.555 0.469 -15.5% Total Imports 2.418 2.641 9.2% Gross Supply 2.445 2.664 9.0% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.000 0.000 - Stock Change -0.005 0.029 . Net Supply 2.440 2.693 10.4% DEMAND Residential 0.023 0.025 10.4% Non Residential 0.635 0.701 10.4% Power Generation 1.782 1.967 10.4% Total Demand 2.440 2.693 10.4% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Greece has one gas field from which production levels are negligible. This means that imports form the core of gas supply. Greek gas imports first began in 1997 when Russian gas was imported via Bulgaria. Currently over 80% of gas is sourced from Russia, with the remainder of imports arriving from Algeria in the form of LNG. Gas is supplied from Gazprom under a long term contract that runs until 2016, although discussions are currently underway regarding the extension of this contract.

On going pipeline projects mean that Greece has considerable future potential to act as a gas transit state acting as a conduit for Iranian and Azeri gas going to southern Europe and beyond (see Infrastructure).

Following completion of the currently under construction link with Turkey, Greece will begin importing 0.75 bcm per year of gas from Azerbaijan.

Figure 45: Greece, Indigenous Production


00.010.020.030.040.050.060.070.080.090.1

0.110.120.13

1982 1986 1990 1994 1998 2002

BC

M





Demand overview

Over the past decade Greek gas demand has grown at an almost unprecedented 54% per annum. However, despite this strong growth, the market remains very small at less than 3 bcm per annum.

Greece’s undeveloped market means that demand is accounted for almost entirely by the power generation and non-residential sectors.

As the distribution structure expands, demand in the residential sector will grow rapidly. At just 6% of the primary energy mix, there is enormous potential for Greek gas demand to grow in the short to medium term.

Figure 46: Greece, Sectoral Demand

Sectoral ConsumptionResidential

1%Non

Residential26%

Pow er Generation

73%





Figure 47: Greece, Historical Sectoral Demand

0

1

2

3bc

m

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The Regulatory Authority for Energy (RAE) is responsible for the regulation of the Greek gas and power markets. The RAE was created under Law 2773/22-12-99, and the subsequent amendment to article 5 of Law 2837/2000.

The Greek gas market is heavily dominated by DEPA, which is 35% owned by Hellenic Petroleum and 65% by the Greek government. In 2003 Spain’s Gas Natural was awarded the right to buy a 35% stake in the company, though no deal has yet been finalised and the deal appears to be increasingly unlikely following a change of government in Greece.

Greece has a derogation from the terms of the gas directive, due to expire in November 2006, awarded as a result of its status as an emerging market, though is still required to transpose the terms of the directive into national law. In November 2005 the Greek government submitted to the EU a bill outlining its planned timetable for deregulating the market when the derogation expires. The bill proposed to unbundle DEPA into separate legal entities and to facilitate customer switching.




In February 2006, the European Investment Bank (EIB) granted Greece €95 million to support its gas diversification objective, including an allowance for the construction and operation of the Greece-Turkey pipeline.

Infrastructure

The future development of the Greek gas market is heavily dependent on the construction of new import infrastructure to meet growing demand levels. Various projects to meet this aim have been mooted in recent years.

In March 2002 a memorandum of agreement was signed concerning the construction of a link between Karacabey in Turkey and Komotini in northern Greece which will allow the importation of Azeri (and potentially Iranian) gas. Following a series of delays, construction work has now begun with completion expected in the latter part of 2006. When complete, the project will give a much needed added element of security of supply. So far DEPA has agreed to import 0.75 bcm per year under a contract signed in late 2003. Initial capacity of the line will be 3.4 bcm per year with the potential to upgrade to 11 bcm being built into the project. By virtue of its geographical location, Greece may be able to transform itself into a transit state by acting as a conduit for eastern gas going to western markets. If it manages to achieve this, the link with Turkey will be upgraded to the potential 11 bcm capacity.

The possibility of a link between Greece and Italy has been examined via a feasibility study completed in early 2005. This was followed in November 2005 by the signing of a governmental agreement. Edison and Depa are understood to be involved in the 8 bcm project, known as IGI. When developed, the link will provide another way in which Greece could act as a transit country for eastern gas going to western markets: Russia has already discussed the possibility of transporting Russian gas through this pipeline. Completion of the project is expected by 2010.

LNG The arrival of Greece’s first LNG shipment in November 1999 removed the precarious total import dependence on Russia. The LNG arrived under the terms of a 21 year supply deal agreed between DEPA and Algeria’s Sonatrach. The LNG is imported to DEPA’s 0.65 bcm regasification terminal at Revithoussa near Athens.

In November 2004 DEPA announced plans to expand capacity at the terminal in order to meet demand growth. Work to expand the terminal's regasification capacity to 1,000 cubic metres per hour from the current 267 cubic metres per hour will begin in late 2006.




CHAPTER 15 HUNGARY

Market summary

Hungary has a very high level of gas penetration, far in excess of its Eastern European neighbors and even ahead of many much more developed gas markets. The high levels of gas penetration mean that the market is either at, or close to, saturation point, thus limiting future demand growth prospects.

Hungary’s indigenous gas production has traditionally supplied a small, but important, proportion of gas demand. However, since a peak in production was reached in 1986, the subsequent decline in production means that as demand continues to grow, a greater role will need to be played by imports

As import dependency rises, the need to diversify supply sources will grow. Currently Hungary’s role as a transit state and its location close to the Brotherhood pipeline, one of the key export routes for Russian gas going to western markets, gives it an added element of supply security.





Table 21: Hungary, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 2.945 2.963 0.6% Pipeline Imports France 0.412 0.413 0.2% Germany 0.719 0.720 0.1% Kazakhstan 0.000 0.395 - Russia 11.045 9.217 -16.6% Turkmenistan 0.000 0.369 - Uzbekistan 0.000 0.304 - Total Pipeline Imports 12.176 11.418 -6.2% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 12.176 11.418 -6.2% Gross Supply 15.121 14.381 -4.9% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.127 0.125 - Stock Change -0.418 0.083 - Net Supply 14.576 14.339 -1.6% DEMAND Residential 4.764 4.687 -1.6% Non Residential 5.418 5.330 -1.6% Power Generation 4.394 4.323 -1.6% Total Demand 14.576 14.339 -1.6% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Hungarian gas production has been decreasing for a number of years, making the country increasingly dependent on gas imports, which come mainly from Russia.

With a disproportionately high amount of imports coming from one source, it could be argued that Hungary suffers a lack of supply diversity. However, Hungary’s location close to the Brotherhood pipeline, one of the key Russian export lines, does give an added element of supply security.

Figure 48: Hungary, Gas Production


0

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1965 1969 1973 1977 1981 1985 1989 1993 1997 2001

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Figure 49: Hungary, Imports By Source


Russia81%

Turkmenistan3%

Uzbekistan3%

France4%

Germany6% Kazakhstan

3%


Demand overview

At 49% of primary energy demand, Hungary has a notably high gas penetration, much in excess of both its eastern European neighbours and more mature gas markets such as the UK and Germany.

With more than 93% of urbanisations already connected to a gas supply, future demand growth is likely to be at a slower rate than has been seen in the past, particularly in the residential sector. Demand growth over the past decade has averaged 2.2%, driven primarily by the power generation sector.




Figure 50: Hungary, Sectoral Demand

Sectoral ConsumptionPow er Generation

30%

Non Residential

37%

Residential33%


Figure 51: Hungary, Historical Sectoral Demand

02468

10121416

bcm

1965 1968 1971 1974 1977 1980 1983 1986 1989 1992 1995 1998 2001 2004








The Hungarian gas market is regulated by the Magyar Energia Hivatal, known as the MEH, which was established in 1994. The MEH also regulates the power sector.

Plans for the reform of the Hungarian energy market (were begun) began in 2000. Subsequently, Act XLII was passed in 2003 which began the process of reforming the gas sector, leading to the first phase of market opening in January 2004 allowing large industrial buyers to choose their supplier. Hungary is in full compliance with the first phase of the gas directive with the non-residential market having been open from July 2004 and the residential market scheduled to be open before July 2007.

Switching activity amongst eligible consumers has been minimal, largely as a result of difficulties in obtaining access on transmission lines.

To comply with the terms of the directive, MOL (the incumbent monopoly) legally unbundled its supply, storage and transmission assets into three separate units in 2000. The three units, Foldgazellato (wholesale marketing and supply), Foldgaztarolo (storage), and Foldgazszallito (transmission), were originally 100% owned by MOL and were put up for sale in early 2004 as part of the liberalisation process.

In November 2004 a deal was signed with E.ON under which stakes in the unbundled units were sold for a total consideration of up to EUR 2.2 billion depending on the exercising of various options included in the deal. The assets acquired by E. ON were 75% minus one share in Foldgaztarolo, 75% minus one share in Foldgazellato and 25% plus one share in Foldgazszallito. Also included in the sale, subject to joint venture partner approval, was a 50% stake in Panrusgaz, a gas import joint venture with Gazprom. Completion of the deal was approved by the Hungarian Energy Office in June 2005.

In January 2006, MOL announced it had reached an agreement regarding the sale of Foldgazellato and Foldgaztarolo to the German company EON at a price between €900 million and €1.19 billion. EON will release up to 2bcm of gas to the free market annually (around 14% of total consumption), as required by the Commission.

Hungary’s six regional distribution companies have been privatised since 1995 with various foreign players, including RWE, E.ON Ruhrgas, GdF and Eni, making investments in the distribution companies.




Infrastructure

Pipelines Russian gas is imported to Hungary via a section of the Brotherhood pipeline. Since the inauguration of the Hungary-Austria Gasleitung (HAG) pipeline in 1996, small volumes of imports have been sourced from Austria.

Mol and Slovakia's SPP are exploring the possibility of developing another import pipeline to serve as a third entry point to the Hungarian market. The plans entail a link from Tupa-Sahy in Slovakia which will connect with MOL’s existing infrastructure at Vecses.

In 2000 an interconnection was built with Croatia, supplementing the existing interconnections with other surrounding countries.

The gas network totals around 73,000 kms and is connected to in excess of three million end users.

Storage In January 2006 the Hungarian government announced plans for a new 1.2 bcm capacity storage facility. The project should become operational by 2010.

Table 22: Hungary, Storage Sites

Name Operator Capacity Peak

Deliverability (mcm) (mcm/day) Pusztaederics Mol 3301 2.7 Zsana Mol 1300 18 Maros Mol 150 2.2 Kardoskut Mol 160 2.4 Hajduszoboszl Mol 1400 19.2 Source: Hungarian Energy Office D A T A M O N I T O R




CHAPTER 16 IRELAND

Market summary

Ireland is a comparatively new gas market with consumption only beginning in the late 1970’s. Since then the industry has progressed at a steady speed with the development of new import pipelines and significant investments being made in transmission and distribution infrastructure.

Demand growth has been consistent rather than spectacular, having averaged around 4.2% over the past decade. Continued economic growth, increased supply and the gasification of new areas of the country, mean that demand will continue to grow in the short to medium term.

Indigenous production is limited, meaning that around 80% of gas demand is met through imported supplies.

Levels of market opening in the past have far exceeded those required by the EU Gas Directives with full opening expected by October 2005, more than a year and a half ahead of the EU deadline.





Table 23: Ireland, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.673 0.855 27.0% Pipeline Imports UK 3.635 3.440 -5.4% Total Pipeline Imports 3.635 3.440 -5.4% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 3.635 3.440 -5.4% Gross Supply 4.308 4.295 -0.3% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs -0.029 -0.029 - Stock Change -0.029 0.000 - Net Supply 4.308 4.324 0.4% DEMAND Residential 0.630 0.632 0.4% Non Residential 0.924 0.927 0.4% Power Generation 2.754 2.764 0.4% Total Demand 4.308 4.324 0.4% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Ireland's first indigenous gas reserves were discovered off the south west coast in 1971 as a by-product of a search for oil.

Reserves, and hence production, are small in scale meaning that indigenous production has only ever met a small proportion of demand, currently around 20%. Despite the imminent start-up of new production facilities, this import dependency is set to grow as demand growth out accelerates indigenous supply availability.

Currently all production takes place in the southwest of Ireland, offshore of Cork. Current production facilities are:

Kinsale Head – In 1979 Marathon’s Kinsale Head became Ireland’s first producing gas field. In 1991 production was increased with the development of the Ballycotton satellite field and the Southwest Kinsale field in 1999. Despite these additions, Kinsale Head production is now in decline.

Seven Heads – Around 35 kms south west of Kinsale Head is the Seven Heads field. Seven Heads is operated by Ramco, with ownership split between Ramco and a consortium of partners. Gas from Seven Heads is transported and processed through Marathon's Kinsale Head infrastructure. The field came on stream in December 2003 but has been experiencing severe reservoir problems which have severely limited production. Initial production of 73 mcf per day was more than sufficient to meet the requirements of the 60 mcf per day contract Ramco had entered into with Innogy. The reservoir problems mean that production has fallen significantly forcing the partners to source gas elsewhere to comply with the terms of the contract. Recent estimates of recoverable reserves indicate that the field has another 19 bcf of reserves (in addition to the 9 bcf already produced), significantly down on the original estimate of 283 bcf. Ramco has stated that it believes this ultimate recoverable reserves figure could be increased to 83 bcf with further drilling and seismic work. However, the company is currently in the final stages of disposing of Seven Heads and is understood to have had extensive discussions with Marathon.

One other big gas development project is currently underway. The Corrib field, located 70 kms offshore the northwest coast, was first discovered in 1996 by Enterprise Oil and was the first significant new gas discovery in Irish wasters since Kinsale Head. In 2002 Enterprise Oil was acquired by Shell and the operatorship of Corrib transferred to Shell, with the project owned by Shell E&P Ireland Limited (45%), Statoil (36.5%) and Marathon (18.5%). The project has undergone various legislative and planning permission delays, though current indications point to initial gas flows by 2008. The field’s estimated reserves of 24 bcm would increase security of supply and reduce import dependency on the UK.




In March 2005 an exploration licensing round was launched for 15 year permits covering 25,000 square kms in the Slyne, Erris and Donegal Basins, located in the same vicinity as Corrib, off the northwest coast.

Figure 52: Ireland, Gas Production


0

1

2

3

1979 1983 1987 1991 1995 1999 2003

BC

M


Figure 53: Ireland, Imports By Source

Supply Sources

Production20%

UK Imports80%





Demand overview

Since consumption first began in 1979, gas demand in Ireland has been growing strongly at an average of 4.2% per year.

At 7.8% and 7.4% respectively, demand growth has been strongest in the power generation and residential sectors owing to an ongoing expansion to the distribution grid and the construction of new gas fired power capacity. Forecasts published by the regulator indicate demand growth of 7% per annum in the period to 2008 and between 4% and 6% thereafter.

Further expansion work to the distribution grid means that gas demand will continue to be strong and will continue to back LPG out of the energy mix.

Figure 54: Ireland, Sectoral Demand


Pow er Generation

64%

Non Residential

21%

Residential15%





Figure 55: Ireland, Historical Sectoral Demand

0

1

2

3

4

5bc

m

1979 1984 1989 1994 1999 2004





The Irish gas market is regulated by the Commission for Energy Regulation (CER) under the terms of the Gas (Interim) (Regulation) Act, 2002. Since its formation in April 2002, the CER has also been responsible for regulating the power market.

Competition was introduced to the Irish gas market in 1995 when users of more than 25 mcm per year were granted Third Party Access to the transmission network of Bord Gáis, the monopoly gas company. In addition to setting up the CER, the Gas (Interim) (Regulation) Act 2002 also reduced the eligibility threshold to include consumers using at least 2 mcm per annum and all gas fired power stations irrespective of size.

This threshold was subsequently reduced to 500,000 cubic metres per year from 1st January 2003 and equates to a market opening of 85% by volume. In compliance with the gas directive, the whole of the non-residential market became eligible from 1st July 2004. Full market opening is expected by mid 2006, exceeding the July 2007 timetable required by the gas directive.

Transmission, distribution and supply of gas are currently dominated by Bord Gáis, the national gas incumbent, which was set up under the 1976 Gas Act and is 100% owned by the Irish Government.




Infrastructure

Ireland’s 1,850 km transmission network and 8,400 kms of distribution infrastructure are owned and maintained by Bord Gáis.

Gas from the UK currently enters the Irish system via two Interconnectors owned and operated by BGE. The gas comes onshore in County Dublin and also at Inch in County Cork where gas from the Kinsale Head field is landed.

Another system entry point will be created in north west Ireland in around 2007 when the Corrib field is likely to come on-stream – see Supply overview.

Several significant pipeline development projects are underway. These include:

Pipelines to Northern Ireland - In 2002 Bord Gáis was granted permission to build, own and operate 2 pipelines linking the Irish transmission grid to Northern Ireland. The first of these pipelines, between Belfast and Derry, is currently under development and will supply gas to a power station and end users in the northern area of Northern Ireland. Work on the second pipeline is due to start in 2006 and will take supplies from the UK-Ireland Interconnector at Gormanston to Belfast.

Mayo to Galway Pipeline – Bord Gáis has unveiled plans to build a pipeline to transport gas from the Corrib field to Galway where it will connect with other transmission infrastructure. Development of this project is currently on hold until the development of the Corrib project is finalized.

Despite not currently having any formal commercially available gas storage infrastructure, some gas storage activity does take place in Ireland. Marathon Oil, operator of Ireland’s largest producing field, injects gas from its main Kinsale field into the Southwest Kinsale satellite to help meet peak winter demand.

In early 2004 the company entered into discussions with the Irish regulator regarding the possibility of creating the first commercially available storage in Ireland by converting the Southwest Kinsale field into a permanent storage site. Under the terms of the proposal, up to 170 mcm could be stored with injection rates of 1.4 mcm per day and a withdrawal rate of up to 2.5 mcm per day. After various delays there are now plans to make this storage commercially available from May 2006.




Figure 56: Ireland, Transmission Grid

Source: BGE D A T A M O N I T O R




CHAPTER 17 ITALY

Market summary

Italy is a significant consumer of gas, with consumption levels in excess of most other European countries.

The role of gas has increased considerably in recent years, and it now accounts for 36% of primary energy demand. A small amount of this demand is met by LNG, though as new regasification facilities are developed, this proportion will increase.

Italy has outpaced the speed of market opening required by the EU Gas Directive and has had a fully open market since January 2003.

Supply sources are well diversified: pipeline gas is sourced from the Netherlands, Russia, Norway and Algeria, as well as LNG delivered from Algeria and Nigeria.





Table 24: Italy, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 13.885 12.961 -6.7% Pipeline Imports Algeria 21.500 22.690 5.5% Libya 0.000 0.523 - Russia 19.426 21.343 9.9% Netherlands 7.443 8.091 8.7% Norway 7.474 8.175 9.4% Other 0.000 0.678 - Total Pipeline Imports 55.843 61.500 10.1% LNG Imports Algeria 2.020 2.010 -0.5% Nigeria 4.280 4.383 2.4% Total LNG Imports 6.300 6.393 1.5% Total Imports 62.143 67.893 9.3% Gross Supply 76.028 80.854 6.3% Exports Former Yugoslavia 0.005 0.396 - Total Pipeline Exports 0.005 0.396 - Statistical Diffs 0.052 -0.015 - Stock Change 1.383 0.135 - Net Supply 77.354 80.608 4.2% DEMAND Residential 20.901 21.780 4.2% Non Residential 30.707 31.999 4.2% Power Generation 25.746 26.829 4.2% Total Demand 77.354 80.608 4.2% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Despite having the fourth largest gas reserves in the EU, Italian production is comparatively limited at less than 13 bcm per annum, less than 16% of demand. At current production levels this gives a Reserves to Production ratio of around 13 years.

Production activity in Italy is almost entirely accounted for by Eni which produces over 90% of indigenous production, mainly through its reserves in the Adriatic and Ionian seas. Other players active in E and P in Italy include BG and Total.

Production reached a peak in 1995 and has been in decline ever since. Rather then reflecting a decline in geological conditions, this decrease in production may be more attributable to an over contracting of supplies and the fact that the regulator has placed market share limits on Eni, reducing the incentive for it to seek to maximise production. Despite this, a number of E and P projects are currently underway.

Figure 57: Italy, Gas Production


0

5

10

15

20

25

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000

BC

M





Figure 58: Italy, Imports By Source

Import Supply SourcesNorw ay

12%Other1%Netherlands

12%

Algeria (LNG)3% Nigeria (LNG)

6%

Algeria34%

Libya1%

Russia31%


Demand overview

Gas demand has seen continued growth in recent years, despite levels of economic growth being well below the EU average in both 2003 and 2004.

Total demand grew by an average of 4% per year in the decade to 2004, though in more recent years average growth has been only around half this rate.

A strong movement towards gas fired power in the mid to late 1990’s has seen the role of gas in the power generation sector grow particularly rapidly, averaging around 9% per annum over the past decade.




Figure 59: Italy, Sectoral Demand


33%

Non Residential

40%

Residential27%


Figure 60: Italy, Historical Sectoral Demand

0

20

40

60

80

100

bcm

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004








Regulation of both the gas and power markets is undertaken by the Autorita per l’energia elettrica e il gas (AEEG), set up in 1996.

In July 2004, the AEEG completed the regulatory framework for negotiable energy efficiency certificates (white certificates) due for full implementation at the end of February 2006. The certificates will require gas and power distributors to reach precise energy saving targets (155,000 toe in 2005) by carrying out specific projects throughout the supply chain. A successful project will be awarded a white certificate. Distributors will be allowed to meet their targets either through the purchase of the corresponding certificates via GME’s existing web platform, or through projects completed by specialized energy service companies. Any failure to comply will result in sanction by the AEEG.

The AEEG oversaw Legislative Decree 164/2000 (also known as the Letta Decree) in mid 2000, incorporating the terms of the first Gas Directive onto the Italian statute books. The Letta Decree took a very pro-liberalisation stance and exceeded the market opening timetable required under the EU Directive by implementing full market opening by January 2003 and introducing regulated Third Party Access to the gas grid.

The Decree also contained legislation aimed at promoting a competitive market and security of supply. namely that no single company be allowed to supply more than 75% of Italian demand (reduced to 61% by 2010).

The unbundling requirements set out by the Directive were also implemented by the AEEG through the Letta Decree and resulted in the unbundling of Eni.

Despite the unbundling of Eni and the full opening of the market, Eni remains dominant. In January 2005 the AEEG sent a list of recommendations to the Italian Government calling on them to introduce legislation to help further promote the development of competition. These recommendations included the following:

Eni’s stake in Snam Rete Gas should be reduced to less than 5%.

Eni should end its holding in Stogit, (the monopoly storage operator) and that consideration should be given to the merging of Stogit and Snam Rete Gas.

Snam Rete Gas should be given ownership of and transmission rights to the import and export pipelines in Italy.

A proportion of Eni’s long term import agreements and production capacity should be transferred to third parties.




The limit on the volume of gas Eni is allowed to import should be extended beyond the current 2010 expiry date.

In October 2003, the regulator launched the Punto di Scambio Virtuale (PSV), a virtual spot market trading hub, similar to the UK’s NBP. Traded volumes and liquidity so far remain modest though are likely to grow as the market liberalizes further. In October 2003, the regulator launched the Punto di Scambio Virtuale (PSV), a virtual spot market trading hub, similar to the UK’s NBP. Traded volumes and liquidity so far remain modest though are likely to grow as the market liberalizes further (see Wholesale Environment).

Eni has been ordered by the Antitrust Authority to undertake Italy’s first gas release programme in order to stimulate competition. The release process began in early September 2004 with Eni stating that it would release 62 mcm to 37 companies as a first phase of a 4 year, 63 bcm release programme at the Austrian / Italian border. Whilst the programme is a widely welcomed step towards introducing competition to the market, various industry players in Italy have criticised the plan for doing little to encourage new market entrants or benefiting end users. Opinions are also split regarding the degree to which the gas release will bring much needed liquidity to the PSV.

In July 2005 the AEEG allowed TPA to LNG terminals and related facilities, thus making it easier for new players to enter the market. It has also undertaken various courses of action to improve access to storage facilities for third parties.


The PSV (Punto di Scambio Vitruale, or virtual exchange point) came into existence on October 1st 2003. Like the Dutch TTF, it is largely modelled on the NBP and allows delivery to anywhere within its own system.

Activity at the PSV has been very modest since its inception owing to a lack of both liquidity and counter-parties. However, the gas release programme ordered by the Regulator, which will see Eni release a total of 23 bcm to 37 players over a 4 year period, will potentially help boost liquidity.

Currently there are around 30 players at the PSV, of which around half are active on a regular basis. The PSV is operated by Snam Rete Gas.




Infrastructure

Pipelines The main transmission and import lines in Italy are owned by Eni through its Snam Rete Gas subsidiary. Since late 2003 Third Party Access to the grid has been governed by a Network Code, meaning that Italy was the first European country, apart from the UK, to publish such a document. Nearly all imports are undertaken by Eni or under contracts that were originally entered into by Eni but subsequently acquired by other parties under the gas release programme. Distribution pipelines are operated at a local level.

Pipeline gas is imported to Italy via various entry routes:

Trans-Mediterranean Pipeline (Transmed) – imports the 21.5 bcm per annum imported from Algeria. With a full capacity of 27 bcm, scope exists to increase imports via this route.

TAG – importing Russian gas to the north east of Italy via Austria. The 26 bcm line is jointly owned by Eni and OMV. In February 2006, Eni announced plans to expand pipeline capacity by 3.2 bcm per year from October 2008 and a further 3.3 bcm from April 2009.

TENP – is the conduit for Norwegian and Dutch gas into northern Italy.

Transitgas pipeline – like TENP, Transitgas brings gas into the north of Italy at Passo Gries.

TTCP – transports Algerian gas to Italy through Tunisia. Eni also plans to increase the capacity of this pipeline by 3.2 bcm per year from October 2008 and a further 3.3 bcm from April 2009.

Greenstream – is a relatively recent pipeline, completed in the last quarter of 2004. It imports Libyan gas to Gela, on the southern coast of Sicily and then onwards to the rest of the Italian grid. All of the projects 8 bcm capacity has been contracted – 4 bcm by Edison and 2 bcm each to GdF and Energia.

There are currently two significant pipeline projects currently under consideration:

Galsi - a consortium consisting of Sonatrach (36%), Edison (18%), Enelpower (13.5%), Wintershall (13.5%), Hera (9%) and Progemisa (5%) and Sfirs (5%) are currently undertaking an economic and technical feasibility study regarding the possibility of linking the Hassi R’Mel gas field (Algeria’s main source of gas production) with the Italian mainland via Sardinia through a 10 bcm, 1,500 km connection which will be built in order to allow potential upgrading to 18 bcm. A decision on the pipeline's viability is




expected by the end of 2006. If the project materialises it will be become operational by mid 2009. In March 2005 Edison agreed to purchase up to 4 bcm of gas through the line, adding to the 2 bcm of delivery through the pipeline already agreed by the government of Sardinia. If developed, Galso will bring the first gas supplies to Sardinia (around 2 bcm per year) with the remaining gas going onwards to Italy.

Adriatic Link – The possibility of a link between Greece and Italy has been examined via a feasibility study completed in early 2005. This was followed in November 2005 by the signing of a governmental agreement. Edison and Depa are understood to be involved in the 8 bcm project, known as IGI. When developed, the link will provide another way in which Greece could act as a transit country for eastern gas going to western markets. Completion of the project is expected by 2010.

LNG infrastructure Although currently playing only a small role in meeting Italy’s energy needs (around 8.8% of gas demand in 2003), the role of LNG is set to expand considerably over the next decade. Italy’s only LNG regasification terminal is set to be supplemented by a number of new projects at various stages of development.

Italy has just one LNG regasification terminal currently in operation, at Pagnigaglia, with a capacity of approximately 3.5 bcm. However, a new plant in the Adriatic Sea, off Rovigo, is currently under construction while other projects (Brindisi, Tuscany offshore, Rosignano, Gioia Tauro, Taranto, Trieste onshore and offshore, and Porto Empedocle) at various states of completion or different stages in the authorization process.




Table 25: Italy, LNG Infrastructure Name Operator Size Status Panigaglia Snam Rete Gas 3.6 bcm In pre-construction phase. Expansion possible Isola de Porte Levante

Exxon-Mobil / Edison / Qatar Petroleum 8 bcm

Construction began in May 2005. Due on line 2007.

Brindisi BG 8 bcm

Attempting to gain approval. Possible start up late 2008.

Livorno Toscana 4 bcm

Possible start up in mid-2007.

Expansion possible. Trieste Gas Natural 8 bcm Construction due to begin

in 2006. Possible start up in 2009.

Taranto Gas Natural 8 bcm Construction due to begin in 2006. Possible start up in 2009.

Syracuse Shell / ERG Power & Gas

8 bcm At planning stage. Construction possible by 2007 with initial deliveries by





Storage sites

Table 26: Italy, Storage Sites Name Type Capacity Bordolano (not operational) Depleted Gas Field Brugherio Depleted Gas Field 0.30 Cellino Depleted Gas Field 0.11 Conegliano Depleted Gas Field 0.54 Minerbio Depleted Gas Field 0.96 Ripalta Depleted Gas Field 2.36 Sabbioncello Depleted Gas Field 1.58 S.Salvo Depleted Gas Field 0.85 Sergano Depleted Gas Field 2.89 Settala Depleted Gas Field 2.00 Source: Datamonitor D A T A M O N I T O R

Figure 61: Italy, Gas Infrastructure

Source: Snam Rete Gas D A T A M O N I T O R




CHAPTER 18 LATVIA

Market summary

Like its Baltic neighbours, Latvia is entirely dependent on Russian gas supplies.

Although heavily dependent on imported gas, which raises security of supply issues, the existence of the Inculkans storage facility does give Latvia more security of supply than is enjoyed by its Baltic neighbours.

The threat of supply interruptions is mitigated, at least to an extent, by Gazprom’s role as a major shareholder in the country’s main gas company.

Supply disruptions in early 2004 allowed Latvia to (very temporarily) become a gas exporter by utilising its storage facility. If plans to link the Baltic network to Finland materialise, further scope will exist to become an exporter, albeit of already imported gas and on a small scale.





Table 27: Latvia, Supply and Demand Balance BCM 2003 2004 (est) CAGR SUPPLY Production 0.000 0.000 -Pipeline Imports Russia 1.629 1.621 -0.5% Total Pipeline Imports 1.629 1.621 -0.5% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 1.629 1.621 -0.5% Gross Supply 1.629 1.621 -0.5% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.000 0.000 -Stock Change 0.000 0.000 . Net Supply 1.629 1.621 -0.5% DEMAND Residential 0.223 0.22 -0.5%Non Residential 0.429 0.43 -0.5%Power Generation 0.977 0.97 -0.5% Total Demand 1.629 1.621 -0.5% Source: Datamonitor / National Sources D A T A M O N I T O R




Supply overview

Oil and biomass are the dominant constituents of the Latvian energy mix, together accounting for over 60% of primary energy demand. Despite this, gas has a comparatively high level of penetration, accounting for 30% of the mix.

Like its neighbours, Lithuania and Estonia, the Latvian gas sector is entirely dependent on Russian imports of gas. The majority of gas is supplied by Gazprom, though smaller amounts of gas are supplied by Itera-Latvija through Gazprom owned infrastructure.

In February 2004, Latvia temporarily supplied neighbouring Lithuania with small volumes of gas taken from its storage site at Inculkans following a disruption to Baltic supply arising from a financial dispute between Gazprom and Belarus. Following this temporary export arrangement, the possibility of Latvia exporting gas to Lithuania on a more permanent basis was raised through discussions between the leading gas companies of the two countries.

In March 2005 plans were mooted by Itera Latvija for the construction of an LNG terminal, though this development remains at the planning stage.

Demand overview

Gas consumption in Latvia is heavily concentrated in and around the capital city of Riga, where around three quarters of national supply is consumed.

Demand is lead by the power generation and industrial sectors. The country’s three largest gas consumers, Latvenergo (the national power company), Rigas Siltums (a district heating company) and Liepajas Metalurgs (a metals processor), together account for nearly half of total demand.

Expansion to the gas grid and increased consumption in the industrial sector mean that gas demand is growing strongly compared with other more mature markets.




Figure 62: Latvia, Sectoral Demand


Residential14% Non

Residential26%

Pow er Generation

60%



The Lithuanian gas industry is regulated by the National Control Commission for Prices and Energy which was formed by Presidential decree in 1997. Various aspects of energy policy are also undertaken by the State Energy Agency, formed in 1993.

The National Energy Law of 1973, amended in 2002, set the framework for the liberalisation of the gas and power markets as well as the promotion of renewable energy.

The importation, transportation and distribution of gas has traditionally been dominated by Lietuvos Dujos, the former state gas company which was privatised in 2001. Currently the company is owned by E.ON Ruhrgas (38.9%), Gazprom (37.1%), the Lithuanian State Property Fund (17.7%) and various individuals (6.3%). New entrants to the market have decreased Lietuvos Dujos’ market share to around 29% of overall consumption.

Since 1992, companies other than Lietuvos Dujos have been free to import gas to Lithuania. The Energy Law of 2000 that came into effect on July 1st 2001 separated gas consumers into regulated and non-regulated customers. The non-regulated customers, namely power plants, consumers of more than 15 mcm per annum, and distribution companies were eligible to choose their supplier. Separate tariffs exist for regulated and non-regulated consumers.




In November 2003 a decree was passed lowering the eligibility threshold from 15 mcm to 1 mcm. In the period preceding its joining of the EU on May 1st 2004, Lithuania began the process of updating the 2000 Energy Law to take account of the terms of the gas directive. As such all non-residential consumers were free to choose their supplier from July 1st 2004. Full market opening will be implemented in accordance with the July 1st 2007 deadline.

Infrastructure

Pipelines Latvia’s pipeline infrastructure consists of around 1,200 kms of transit lines and 3,500 kms of distribution lines.

An interconnection exists with Lithuania, which was used in early 2004 to export gas from the Inculkans storage site after an interruption of supplies from Russia.

Storage Latvia has one storage site, known as Inculkans, with a capacity of 2.4 bcm. A decision is expected in 2006 as to whether Latvijas Gas will proceed with plans to increase capacity to 6.2 bcm. An on-going modernisation and improvement programme is being undertaken at Inculkans with assistance from E.ON Ruhrgas and DONG.

Gasum and Eesti Gaas of Estonia are in the early stages of developing plans to construct a pipeline line between Helsinki and Tallinn. If this project materialises it will allow Finland direct access to Inculkans. The project has a target start up date of 2010.




CHAPTER 19 LITHUANIA

Market summary

Lithuania’s small, but growing, gas demand is entirely dependent on Russian imports.

The role of gas in the residential sector is particularly small at just 9% of total demand. As the grid is expanded, we expect this role to grow, though increased penetration into the residential sector is likely to be a very slow process.

The already strong role the power generation sector plays in gas demand will increase further as nuclear capacity is decommissioned.





Table 28: Lithuania, Supply and Demand Balance BCM 2003 2004 (est) CAGR SUPPLY Production 0.000 0.000 -Pipeline Imports Russia 2.882 2.896 0.5% Total Pipeline Imports 2.882 2.896 0.5% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 2.882 2.896 0.5% Gross Supply 2.882 2.896 0.5% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.000 0.000 -Stock Change 0.000 0.000 . Net Supply 2.882 2.896 0.5% DEMAND Residential 0.257 0.258 0.5%Non Residential 1.258 1.264 0.5%Power Generation 1.367 1.373 0.5% Total Demand 2.882 2.896 0.5% Source: Datamonitor / National Sources D A T A M O N I T O R




Supply overview

Gas is playing an increasingly strong role in the Lithuanian energy mix and currently accounts for 31% of primary energy consumption.

Nuclear power has long been a dominant component in Lithuanian energy consumption, though gas is slowly backing this out of the energy mix.

With no indigenous production, LNG infrastructure or ability to import gas from anywhere else, Lithuania is entirely dependent on Russia to meet its gas demand.

A new supply contract was signed with Gazprom in March 2004 under which former state monopoly Lietuvos Dujos will import a flexible amount of gas equating to 70% of total gas demand excluding volumes used by two of the country’s biggest industrial consumers.

Demand overview

The power generation sector is the biggest consumer of gas in Lithuania accounting for 47% of total demand. The industrial and commercial sector is the other dominant gas consumer, making up 44% of demand. One company in particular, fertiliser producer AB Achema, accounts for around a quarter of national demand, thus heavily influencing demand in the industrial sector.

Gas demand will rapidly increase as the gradual decommissioning of the Ignalina nuclear power plant is compensated for by the conversion of parts of Ignalina to gas and also by the increased use of gas fired power at the Visaginas power plant. Depending on load factors, these two projects will add between 4 and 15 mcm to annual demand levels. When the final phase of Ignalina is decommissioned in 2010, incremental gas demand will exceed 105 mcm.




Figure 63: Lithuania, Sectoral Demand


Residential9% Non

Residential44%

Pow er Generation

47%



The Lithuanian gas industry is regulated by the National Control Commission for Prices and Energy which was formed by Presidential decree in 1997. Various aspects of energy policy are also undertaken by the State Energy Agency, formed in 1993.

The National Energy Law passed in 2002 legislated for a number of changes in the energy sector including the privatization of Latvian Gaze, the liberalization of the gas and power markets, and encouraging the use of renewable energy.

The importation, transportation and distribution of gas has traditionally been dominated by Lietuvos Dujos, the former state gas company which was privatized in 2001. Currently the company is owned by Ruhrgas (35.70%), Gazprom (34%), the Lithuanian State Property Fund (24.36%) and various individuals (5.94%). New entrants to the market have decreased Lietuvos Dujos’ market share to around 29% of overall consumption.

Since 1992, companies other than Lietuvos Dujos have been free to import gas to Lithuania. The Energy Law of 2000 that came into effect on July 1st 2001 separated gas consumers into regulated and non-regulated customers. The non-regulated customers, namely power plants, consumers of more than 15 mcm per annum, and distribution companies were eligible to choose their supplier. Separate tariffs exist for regulated and non-regulated consumers.




In November 2003 a decree was passed lowering the eligibility threshold from 15 mcm to 1 mcm. This significantly increased the number of eligible customers which, according to the latest information available, amounts to less than 25 customers.

In the period preceding its joining of the EU on May 1st 2004, Lithuania began the process of updating the 2000 Energy Law to take account of the terms of the gas directive.

Infrastructure

Pipelines The Lithuanian grid is directly linked to Russian export lines via an interconnection at Minsk in Belarus. Interconnections to Latvia and the Russian enclave of Kaliningrad run through Lithuania.

Lithuania’s pipeline system is also used to transit gas to the Russian enclave of Kaliningrad. In mid 2004 Lietuvos Dujos began construction work on an additional branch line to supplement the existing one in order to increase exports to the region from the current level of 600 mcm to in excess of 1 bcm.

Construction work is also underway by Lietuvos Dujos to build a new pipeline to the town of Visaginas, as well as to the Ignalina nuclear power plants which, as it is being decommissioned, is being converted to use natural gas.

Security of supply in Lithuania is significantly compromised by the fact that the country is entirely dependent on Russia for its gas supplies. This lack of security of supply was shown in February 2004 when a dispute between Gazprom and the Government of Belarus resulted in flows through Belarus being interrupted by Gazprom, consequently affecting Lithuania imports. Although the shortfall was made up by a rapid deal to import Russian gas via Latvia, the interruption highlighted the increasing need for an expansion to existing Lithuanian storage capacity which totals just 20 mcm, sufficient to cover only around 2 weeks of supply.

At the time of the disruption, Lietuvos Dujos was already undertaking an investigation into the possibility of developing a storage site near Vaskai. In addition to this, Lithuanian oil company Geonafta and gas utility Dujotekana began cooperating in April 2004 on a feasibility study relating to a proposed US$120 million storage site. The result of the feasibility studies were completed in late 2004, but financial issues have resulted in delays.




CHAPTER 20 LUXEMBOURG

Market summary

With a population of less than half a million people and an economy based on services rather than industry, the Luxembourg gas market in unsurprisingly very small in size.

Demand is heavily concentrated in the power generation and non-residential sectors.

The power generation sector has been expanding at the greatest rate in recent years, far outstripping demand growth in the other sectors.





Table 29: Luxembourg, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.000 0.000 - Pipeline Imports Belgium 0.603 0.628 4.3% Germany 0.600 0.733 22.1% Total Pipeline Imports 1.203 1.361 13.2% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 1.203 1.361 13.2% Gross Supply 1.203 1.361 13.2% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs -0.002 0.000 - Stock Change 0.000 0.000 - Net Supply 1.205 1.361 13.0% DEMAND Residential 0.267 0.302 12.9% Non Residential 0.450 0.508 12.9% Power Generation 0.488 0.551 12.9% Total Demand 1.205 1.361 12.9% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

With no indigenous production resources, Luxembourg is entirely dependent on imported gas. In 2004 imports were made from Belgium and Germany in approximately equal volumes.

With no indigenous production, or indeed any prospect of any, Luxembourg will continue to be entirely import dependent into the future.

Demand overview

Demand is heavily concentrated into the industrial and power sectors which together account for more than three quarters of total demand.

Gas use in Luxembourg was boosted in 2002 when the Esch-sur-Alzette CCGT, Luxembourg's first gas fired plant, came on line. In addition to creating an additional source of gas demand, the facility currently supplies around 20% of Luxembourg’s power, thus reducing dependency on imported power supplies.

Figure 64: Luxembourg, Sectoral Demand


41%

Non Residential

37%

Residential22%





Figure 65: Luxembourg, Historical Sectoral Demand

0.0

0.5

1.0

1.5bc

m

1970 1976 1982 1988 1994 2000





The Luxembourg gas market is regulated by the Institut Luxembourgeois de Régulation which also oversees the electricity and telecommunications markets.

The market is governed by the Gas Law of 6 April 2001, a Ministerial decree in August 2003 and subsequent amendments which have legislated for market opening in line with the terms of the gas directive and transferred the required legislation onto the statute books.

The Société de Transport de Gaz (SOTEG) is the key transmission company and importer of gas. The company is owned by the Luxembourg Government (21%), Ruhrgas (20%), Saar Ferngas (10%), Arbed (20%), Cegedel (19%) and SNCI (10%).




Infrastructure

Pipelines Luxembourg has two interconnections with Belgium and one each with France and Germany.

The transmission system is owned and operated by SOTEG. Article 24 of the Gas Law gives the company the right to refuse TPA to the network if it believes granting the access would interfere with its public service obligations or if insufficient capacity is available.

TPA to the SOTEG network is charged on a postalized basis with an access fee payable. Balancing is required on a daily basis with an hourly tolerance of 50% allowed based on daily nomination volumes. A daily balancing tolerance of 5% is allowed during summer and 3% during winter, after which penalty clauses are invoked.

Figure 66: Luxembourg, Gas Grid

Source: SOTEG / Datamonitor D A T A M O N I T O R




CHAPTER 21 MALTA

Market summary

Malta is not currently connected to any natural gas infrastructure and has no indigenous production, thus meaning it does not currently consume natural gas. Instead, it is a significant user of LPG.

Malta’s 571 MW of power generation capacity is run on distillate fuel oil.

Some limited E and P activity has been undertaken in the past, though this was hindered by a territorial dispute with Libya. Currently exploration activity is being undertaken by MedOil and Anadarko

Theoretically, Malta could become a gas consumer by building an interconnection with the Greenstream pipeline which runs between Libya and Sicily. However, the economics of this are likely to be difficult to make viable given the very small market potential. The most likely possibility of Malta becoming a gas consumer would be if commercially viable reserves were found within its territorial boundaries.




CHAPTER 22 THE NETHERLANDS

Market summary

Gas plays a key role in the Dutch primary energy mix, partly due to the presence of energy intensive industry such as chemicals, metal processing, refining and certain forms of agriculture.

Significant indigenous reserves mean that the country enjoys a position as a net gas exporter.

Aside from being a significant gas exporter, the Netherlands plays a crucial role as a transit state and also as a gas trading hub.





Table 30: Netherlands, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 72.896 85.983 18.0% Pipeline Imports Belgium 4.366 1.326 -69.6% Germany 9.015 7.792 -13.6% Norway 8.474 6.925 -18.3% UK 3.633 2.808 -22.7% Total Pipeline Imports 25.488 18.851 -26.0% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 25.488 18.851 -26.0% Gross Supply 98.384 104.834 6.6% Exports Belgium 8.810 8.064 -8.5% France 7.677 9.845 28.2% Germany 21.757 24.503 12.6% Italy 8.428 9.676 14.8% Switzerland 0.816 0.870 6.6% UK 0.623 0.602 -3.4% Total Pipeline Exports 48.111 53.560 11.3% Statistical Diffs 0.000 0.000 - Stock Change -0.013 0.028 - Net Supply 50.260 51.302 2.1% DEMAND Residential 11.190 11.422 2.1% Non Residential 23.078 23.556 2.1% Power Generation 15.992 16.324 2.1% Total Demand 50.260 51.302 2.1% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Current gas reserves are around 1,494 bcm, equating to a Reserves to Production ratio of 22 years.

Dutch gas has long played a key role in meeting European gas demand. The Groningen field is central to the Dutch gas production industry, not only as a result of its large size and the fact that it has the lowest technical cost of gas in Europe, but also as a result of its high swing flexibility.

In 2004 Groningen produced around 32 bcm, 37% of total national output. In the past it has produced as much as half of national production.

Groningen gas has a low calorific value and a 14% nitrogen content. To accommodate this, it has to be shipped through dedicated pipelines and burnt using a specific type of burner tip. Groningen gas can be blended with high calorific value gas, and this operation is undertaken at one of Gasunie’s three blending plants.

The majority of the Netherlands’ reserves are accounted for by Groningen. The country’s main producer is Nederlandse Aardolie Maatschappij (NAM) which is jointly owned by Shell and ExxonMobil. The majority of gas is then purchased by Gasunie (50% owned by the Dutch Government and 50% by Shell and ExxonMobil) for onward distribution.

In order to prolong the life of Groningen and protect its valuable swing capacity, the Government has placed a cap on the field’s production and also aims to encourage the development of smaller and more expensive fields.

The majority of other fields produce high calorific gas from reserves located offshore. Operators of these fields include ChevronTexaco, Gaz de France, Wintershall and Total.




Figure 67: Netherlands, Gas Production


0102030405060708090

100110

1960

1964

1968

1972

1976

1980

1984

1988

1992

1996

2000

2004

BC

M


Figure 68: Netherlands, Imports By Source

Import Supply SourcesBelgium

8%

Germany49%

Norw ay43%





Demand overview

At 0.6%, annualised average demand growth in the Netherlands over the past decade has exhibited much less spectacular increases than that seen in other, less mature, markets.

As such, the power generation sector is the only market to have increased in size over the past decade, having averaged 3% growth over the period compared with 0.1% and 0.5% annualised declines in demand in the non-residential and residential sectors respectively.

With a mature market, and high levels of gas penetration into the primary energy mix, the scope for future demand growth would appear to be limited.

Figure 69: Netherlands, Sectoral Demand


32%

Non Residential

46%

Residential22%





Figure 70: Netherlands, Historical Sectoral Demand

0

10

20

30

40

50

60bc

m

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004





The Dutch gas sector is regulated by the Dienst uitvoering en toezicht Energie (DTe), a part of the Netherlands Competition Authority (the NMa).

The Netherlands adopted the terms of the first Gas directive into national law through the passing of the 1998 Gas Act, with the terms of the second directive adopted by legislation passed on June 29th 2004. The Gas Act 2000 legislated for negotiated Third Party Access to transmission infrastructure and regulated Third Party Access for distribution.

The Dutch market officially became 100% open on 1st July 2004 with the DTe granting in excess of 50 licenses to new market entrants wanting to supply households and small businesses, the last category of consumers to be opened up to competition.

In June 2004 the DTe announced three new measures aimed at making the market more transparent. These were:

The inclusion of gas conversion costs (the costs associated with converting high calorific gas to low calorific gas) within transport tariffs.

A ruling that Gastransport Services, the transmission arm of Gasunie, must introduce a new balancing regime by 2006.




A requirement for Gastransport Services to provide gas suppliers with information on historical and future import capacity availabilities.

Before liberalisation, the Dutch gas sector was dominated by Gasunie. However, this dominance has since begun to be eroded. Very large consumers of gas have been able to choose their supplier since 1998, resulting in Gasunie losing market share to other players.

In 2002 Gasunie’s distribution and trade arms were operationally unbundled. In July 2004 this process was completed with the legal unbundling of the two divisions in order to comply with the terms of the second directive. Gasunie’s former transmission arm, Gas Transport Services, was replaced by a new company, Gas Transport Services B.V, which has taken on the role as transmission system operator.

In 2005, the DTe published a decision concluding that Gasunie Trade & Supply has a dominant position on a large part of the market for flexibility services, and explained how GTS should structure the supply of these services in order to stimulate the operation of competition, This regulation will apply to the services in which Gasunie Trade & Supply has a dominant position from 2006 up to and including 2008, after which the situation will be reviewed.


The Dutch TTF (Title Transfer Facility) market is largely modelled on the UK’s NBP and was launched in November 2002. Although volumes and liquidity at the TTF are much lower than both the NBP and Zeebrugge, it has seen much more activity than the nearby Bunde hub. Like the NBP, the TTF is a virtual hub allowing delivery anywhere within the TTF system rather than at a specific geographic location.

The TTF is operated by Gas Transport Services B.V, a company created from the legal unbundling of the former Gasunie subsidiary Gastransport Services. Gas Transport Services B.V is also the Dutch transmission system operator. Trading activity on the TTF is governed by a network code similar to that in the UK. Currently there are 40 registered players trading at the TTF.

At the end of May 2004, Gas Transport Services B.V and the APX (previously known as the Amsterdam Power Exchange) signed a Memorandum of Understanding concerning the setting up of a screen based Dutch gas exchange focused around the TTF. The exchange, known as APX Gas NL, was launched on February 3rd 2005 and currently has 15 registered members.

Plans by Endex to develop a gas futures contract have been postponed until at least 2006 owing to a lack of interest amongst traders.




Infrastructure

Pipelines The majority of imports arrive in the Netherlands via the Gasunie grid. The only exception to this is gas imported via Essent’s Zebra pipeline, which is used to supply gas to its distribution business in the Zeeland area with gas from the UK sent via the UK-Belgium Interconnector.

Gas pipelines in the Netherlands connect to terminals at Callantsoog, Uithuizen, Wijk aan Zee, and Maasvlakte. In July 2004 the Netherlands began importing gas from Denmark via a newly constructed 100 kilometre pipeline between the Tyra West field in the Danish North Sea to the NOGAT pipeline which then ships the gas to den Helder on the Dutch coast. The pipeline is operated by Maersk and is owned by the Danish Underground Consortium (DONG 50%, Shell 23%, Mærsk 19.5%, and ChevronTexaco 7.5%). Capacity rights in the pipeline are allocated according to the partner’s shareholdings in the DUC.

A consortium of Gasunie (60%), E. On Ruhrgas (20%) and Fluxys (20%) are in the process of constructing a link between the Netherlands and the Bacton terminal in the east of the UK to export Dutch gas. The Bacton to Balgzand project, known as BBL, will have sufficient capacity to export up to 16 bcm per annum of low calorific Groningen gas, equivalent to about 14 bcm of high cal gas.

Storage Traditionally, the swing flexibility provided by the Groningen field has allowed a lesser emphasis and priority to be placed on investment in storage capacity. However, the decline of Groningen gas, and resultant decline in swing flexibility, means that storage is set to play an increasingly important role in the future.

Table 31: Netherlands, Storage Sites Name Type Operator Capacity Peak (mcm) Deliverability (mcm / day) Alkmaar Depleted Gas Field BP 500 36 Grijpskerk Depleted Gas Field NAM 1500 55 Norg Depleted Gas Field NAM 3000 51 Maasvlakte LNG Peak Shaver Gasunie 78 31 Source: Datamonitor D A T A M O N I T O R




LNG In November 2005 Gasunie and Vopak announced their decision to construct a 6 to 8 bcm per year LNG terminal at Maasvlakte in Rotterdam. The project, known as GATE (Gas Access to Europe), is expected to be ready to accept cargoes by 2010 following the commencement of construction work in 2007. The decision to build the terminal represents further Dutch moves towards LNG. Currently ConocoPhillilips and Essent are exploring the feasibility of developing a project at Eemshaven whilst Petroplus has begun to develop a terminal at Rotterdam known as LionGas, which is due to become operational in late 2009.




CHAPTER 23 NORWAY

Market summary

Norway is a major gas producer, though has surprisingly low consumption levels. At less than 11%, gas plays only a minor role in the country’s primary energy mix.

Production levels continue to grow and, in 2004 reached a record 82 bcm. The vast majority of gas production is exported with Norway currently the source of around 16% of EU 25 consumption.

Norwegian exports to the UK will grow significantly following completion of the Langeled pipeline. Up to 20 bcm, around a fifth of current UK demand levels, will potentially be delivered through the pipeline from the Ormen Lange field. The first phase of the project is due on line in late 2006 with full completion expected by October 2007.

The Government plays a significant role in the gas industry both at a regulatory level and through its ownership stakes in the country’s main gas industry players.





Table 32: Norway, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 77.310 82.340 6.5%Pipeline Imports Total Pipeline Imports 0.000 0.000 - LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 0.000 0.000 - Gross Supply 77.310 82.340 6.5% Exports Belgium 6.549 7.500 14.5%Czech Republic 2.498 2.103 -15.8%Denmark 0.114 0.074 -35.1%France 13.334 15.931 19.5%Germany 24.826 24.720 -0.4%Italy 5.480 5.712 4.2%Netherlands 6.048 6.027 -0.3%Poland 0.416 0.466 12.0%Spain 2.423 2.373 -2.1%UK 8.204 10.952 33.5%Total Pipeline Exports 69.892 75.858 8.5% Statistical Diffs 2.837 0.937 -67.0%Stock Change 0.000 0.000 - Net Supply 4.581 5.545 21.0% DEMAND Residential 0.002 0.002 21.0%Non Residential 4.528 5.481 21.0%Power Generation 0.051 0.062 21.0% Total Demand 4.581 5.545 21.0% Source: Datamonitor . IEA D A T A M O N I T O R




Supply overview

Apart from the UK, Norway is the European region’s largest gas producer. Production in 2004 reached its highest ever level of 82 bcm. Given Norway’s low utilisation of gas, the vast majority of Norwegian gas production is exported and accounts for around 16% of EU 25 consumption.

Over the past decade production has grown at an annualised rate of over 10%. With an R/P ratio of over 30 years and ambitious plans to expand E and P activity, production is likely to continue growing in the foreseeable future. Currently Norway only produces natural, rather than liquefied, gas. However this situation will change in 2007 when the Snøhvit field starts producing gas which will be liquefied at the Hammerfest liquefaction plant.

Figure 71: Norway, Gas Production


0

20

40

60

80

100

1974 1978 1982 1986 1990 1994 1998 2002

BC

M





Figure 72: Norway, Gas Export Destinations

Gas Export Destinations

France21%

UK14%

Poland1%

Netherlands8%

Italy8% Germany

32%

Spain3%

Belgium10%

Czech Republic

3% Denmark0.1%


Demand overview

At just 10.5% of primary energy demand, gas has made a surprisingly low penetration into the energy mix given Norway’s role as a significant gas producer. At less than 6 bcm absolute demand levels are modest. Over the past decade demand growth has averaged 3.7%.

Gas has only been used in Norway since 1974 when it developed a role in the non-residential sector. Consumption of gas was constrained to this sector until 1993 when gas found a marginal role in power generation. The residential distribution grid remains very small and gas has only been used by a small number of households since 2001.




Figure 73: Norway, Sectoral Demand


Generation1.1%

Non Residential

98.8%

Residential0.04%


Figure 74: Norway, Historical Sectoral Demand

0123456

bcm

1974 1978 1982 1986 1990 1994 1998 2002





Government control and influence in the Norwegian energy sector, both at a corporate and regulatory level, is high. At a corporate level the government owns a 71% stake in Statoil, the main energy producer in the country and controller of around 60% of national production. One of the other main energy players in the country, Norsk Hydro, is 44% owned by the government.




Since 1985 the government has also exerted an influence over the sector through the State Direct Financial Interest (SDFI). Under the terms of the SDFI the government invests in upstream projects and in return receives a proportional return similar to that received by energy industry players investing in the same projects.

Despite the high degree of government involvement in the energy sector there is still a significant role played by foreign oil majors. These companies, who are legally required to partner with Statoil, include BP, ConocoPhillips and ExxonMobil.

The Ministry of Petroleum and Energy has overall responsibility for overseeing the Norwegian gas market. Within the Ministry there are two main departments – the Norwegian Petroleum Directorate (NPD) and the Petroleum Safety Authority. The NPD’s main role is to administer E and P activities from a legal and regulatory perspective. The PSA oversees a variety of health and safety issues within the industry.

The government also owns 100% of Gassco which administers key parts of the national gas network. Gassco itself is the operator of Gassled, a joint venture of energy producers, which operates the country's gas export infrastructure.

Key pieces of legislation governing the sector are the Petroleum Act and Regulations (Act 26 November 1996 No. 72; Regulation 27 June 1997 No. 653) which relates to upstream access to pipelines and the organisation of the gas sector in general. Downstream legislation is covered by the Natural Gas Act and Regulation (Act 28 June 2002 No. 61; Regulation 14 November 2003 No. 1342).

Gas exploration and production licenses are generally awarded through licensing rounds. The most recent of these licensing rounds, the 19th so far, was held in November 2005. In this round 24 applications were received, the results of which will be known by the end of the first quarter of 2006.

Infrastructure

The nature of the Norwegian gas supply / demand balance means that the onshore distribution grid remains limited whilst the transmission and export systems are well developed.

In 2001 the government recognised the importance of having a neutral and independent gas transport operator and created Gassco to operate the pipeline system. Prior to that, individual pipelines were owned and operated by various upstream players.




Gassled is owned by a number of oil and gas companies and by the government through its ownership of Petoro. Gassled serves a role as the formal owner of the Norwegian gas transport infrastructure.

Key Norwegian gas pipelines are as follows

Franpipe – connects the Draupner platform with Dunkirk on the northern French coast. Franpipe has a 16 bcm capacity and currently facilitates the export of 11.6 bcm of Norwegian gas each year.

Zeepipe - an offshore line from the Norwegian North Sea to Zeebrugge where it connects with various other transit lines and interconnects with the Fluxys transmission grid in Belgium.

Europipe 1 and 2 – exports gas into Dornum, Germany.

Norpipe – exports gas into gas Emden, Germany.

Langeled - Norwegian exports to the UK will be significantly increased following completion of the Langeled pipeline. Up to 20 bcm of gas from the new Ormen Lange field will be shipped through the pipeline. The project’s first phase will supply gas via the Sleipner platform from late 2006, with the second phase supplying gas from Ormen Lange by October 2007.

Table 33: Gassled Shareholders

Company Share

Petoro (Norwegian Govt) 38.29%

Statoil 20.38%

Norsk Hydro Produksjon 11.13%

Total E&P Norge 9.04%

ExxonMobil E&P Norway 5.18%

Norske Shell Pipelines 4.68%

Mobil Development Norway 4.58%

Norsea Gas 3.02%

Eni Norge 1.67% Source: Ministry of Petroleum and Energy D A T A M O N I T O R




Figure 75: Norway, Gas Export Infrastructure

Source: Norwegian Ministry for Petroleum and Energy D A T A M O N I T O R




CHAPTER 24 POLAND

Market summary

Poland is very heavily dependent on imports, particularly from Russia, to meet its gas needs.

Gas plays a minor role in the national energy mix, accounting for just 13% of primary energy consumption. Abundant reserves mean that the dominant fuel is currently coal.

Indigenous production levels are low and meet less than 40% of consumption. Production in recent years has remained relatively constant.

The pace of liberalisation has been slow, with various delays and legislative issues complicating the process.





Table 34: Poland, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 5.626 5.957 5.9% Pipeline Imports Germany 0.440 0.407 -7.5% Norway 0.513 0.506 -1.4% FSU 8.247 9.050 6.2% Total Pipeline Imports 9.200 9.963 8.3% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 9.200 9.963 8.3% Gross Supply 14.826 15.920 7.4% Exports Germany 0.047 0.046 -2.1% Total Pipeline Exports 0.047 0.046 -2.1% Statistical Diffs 0.169 0.177 - Stock Change 0.187 -0.206 - Net Supply 14.797 15.491 4.7% DEMAND Residential 4.023 4.212 4.7% Non Residential 9.334 9.772 4.7% Power Generation 1.440 1.508 4.7% Total Demand 14.797 15.491 4.7% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

With indigenous production meeting less than 40% of demand, gas imports play a key role in Polish supply. Current reserves are estimated at 116 bcm giving a reserves to production ratio of 26 years. Producing fields are mainly located in the south and west of the country. Production has remained flat in recent years, though began to buck this stable trend by increasing nearly 6% between 2003 and 2004. Funds from the privatisation of POGC in September 2005 have been allocated to increasing indigenous production levels.

Russian gas, the largest source of Polish imports, is imported under a 25 year Take or Pay contract signed in 1996. In late 2003 POGC and Statoil agreed to cancel a deal signed in 2001 under which Poland would receive up to 76 bcm of gas between 2008 and 2024 delivered through a newly constructed pipeline. In early 2004 a Memorandum of Understanding was signed concerning the possibility of Statoil supplying between 1 and 2 bcm per annum to POGC through a new pipeline, however the proposal has since been abandoned. Plans are however underway to develop an LNG terminal (see Infrastructure).

Figure 76: Poland, Gas Production


01

23

45

67

89

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004

BC

M





Figure 77: Poland, Imports By Source

Import Supply SourcesGermany

4%Norw ay

5%

FSU91%


Demand overview

Although it makes up just 10% of total demand, growth in the power generation sector has far outstripped that in other sectors. Various plant projects over the past decade have resulted in gas demand in power generation growing by an average of 23% in the decade to 2004. This growth, although starting from a very small base, has been sustained with 16% annualised demand growth seen since 2000.

Considerably lower demand growth levels have been seen in the non-residential and residential sectors which have grown by 2.6% and 0.6% per annum respectively since 2000.




Figure 78: Poland, Sectoral Demand


10%

Non Residential

63%

Residential27%


Figure 79: Poland, Historical Sectoral Demand

0

5

10

15

20

bcm

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004








The Polish energy sector is regulated by the Urząd Regulacji Energetyki or URE which was formed under the terms of the 1997 Energy Act.

Poland had originally applied for a derogation until 2006 in the requirement to open the gas market according to the terms of the gas directive. However this request was refused by the EU and the Polish non-household market (around 17,000 customers) was theoretically opened from July 1st 2004. Plans to open up the full market 2 years ahead of schedule were abandoned following legislative delays and the market will now be fully open from the July 1st 2007 deadline.

The Polish gas sector is currently dominated by POGC (also known as PGNiG), the state- owned oil and gas concern formed in 1976. In August 2002 the Government adopted a plan to restructure and privatise POGC. The original floatation was postponed owing to a lack of interest, though finally took place in September 2005.

Gas distribution is now carried out by 6 regional distribution companies, unbundled from POGC in January 2003. In early July 2004 the company launched a legally unbundled gas transmission subsidiary known as Gaz System in order to comply with the terms of the gas directive.

Infrastructure

Pipelines The Yamal-Europe pipeline transits Russian gas to Germany via Belarus and Poland. Yamal is currently the only conduit for Russian gas into western Europe that is not routed through the Ukraine. The Polish section of Yamal is 684 kms in length and is operated by EuRoPol Gaz, a company jointly owned by POGC and Russia’s Gazprom. In July 2005 two new compressor stations were opened on the line increasing its capacity from 22.8 bcm per year to 29 bcm.

Plans for a second Yamal pipeline have been mooted but no definite plans have yet been developed to progress the project.

Poland’s heavy reliance on Russian gas has raised a number of security of supply issues. The vulnerability of Poland to supply disruptions was highlighted in February 2004 when supplies to Poland were interrupted following a dispute between Gazprom and Belarus.




Various initiatives have been raised in recent years in an attempt to diversify Polish gas supplies and thus boost security of supply. The first of these plans was to construct a pipeline between Norway and Poland, though this plan has faltered due to questionably viable economics. More recently discussions have taken place regarding the possibility of importing LNG. GdF and PGNiG are understood to have begun a feasibility study, the results of which are due in late 2006.

In 1999 E.ON Ruhrgas and Bartimpex were developing proposals to build a pipeline between Bernau in Germany and Szczecin in Poland, though the plan stalled owing to a lack of support by both the Polish government of the time and PGNiG. In early 2005 the concept of the link between the two countries re-emerged following an agreement between PGNiG and VNG for a 1.5 bcm per annum pipeline, though it remains unclear when the project will be developed.

In September 2005 Naftohaz Ukrayiny of the Ukraine and POGC completed a pipeline link between Ustilug in the Ukraine and Hrubieszow in south-eastern Poland. Around 70 mcm will be supplied each year until 2007, after which the flow will increase to 200 mcm.

Figure 80: Poland, Gas Transmission System

Source: POGC D A T A M O N I T O R




CHAPTER 25 PORTUGAL

Market summary

Gas is a very new fuel to the Portuguese energy mix. Consumption began in 1997 with the arrival of Algerian gas delivered via Spain.

Consumption is largely confined to the power generation and industrial sectors, though as transmission and distribution infrastructure is expanded, consumption will also grow in other sectors.

Demand is growing rapidly and, between 2003 and 2004, grew by 25% - the highest rate of year on year growth in Europe.

A lack of indigenous resources makes Portugal entirely dependent on imports for its gas supply. Until late 2003 all gas imports were delivered via Spain due to a lack of suitable infrastructure in Portugal, although this situation has since changed with the completion of the Sines LNG terminal.

Despite being a gas market very much in its infancy demand growth is strong, and likely to remain strong, in the short to medium term.





Table 35: Portugal, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.000 0.000 - Pipeline Imports Algeria 2.481 2.376 -4.2% Total Pipeline Imports 2.481 2.376 -4.2% LNG Imports Nigeria 0.545 1.384 153.9% Total LNG Imports 0.545 1.384 153.9% Total Imports 3.026 3.760 24.3% Gross Supply 3.026 3.760 24.3% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.001 0.001 - Stock Change -0.008 -0.001 - Net Supply 3.017 3.758 24.6% DEMAND Residential 0.181 0.225 24.6% Non Residential 1.223 1.523 24.6% Power Generation 1.613 2.009 24.6% Total Demand 3.017 3.758 24.6% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Portugal does not have any direct pipeline connections with any gas exporters, thus all pipeline imports come via Spain.

Other than small volumes of Nigerian LNG, the only source of gas imports is Algeria. Gas is imported into Spain via the Pedro Duran Farell pipeline (formerly known as the GME or Maghreb Europe line) and then re-exported into Portugal at Badajoz.

The construction of the Sines LNG terminal (see Infrastructure section) gave an added element of security of supply and became the country's first direct link with gas exporters.

Figure 81: Portugal, Imports By Source


Nigeria (LNG)37%

Algeria63%





Demand overview

Portugal has only been consuming gas since 1997. As an emerging market starting from a very low base of absolute consumption, demand growth rates have been very strong in the past few years with total gas demand growing by an average of 57% per year since 1997. These high growth rates hide the fact that the market is still very small at less than 4 bcm.

Despite demand growth of around 97% per annum since 199, gas penetration into the household sector is still very low at just 6% of demand. As the distribution grid continues to expand, this proportion will grow rapidly in the short to medium term.

The decision in February 2005 to allow another 2,868 MW of gas fired power capacity in the country will be a key element driving (future) continued demand growth in the power generation sector.

Figure 82: Portugal, Sectoral Demand


6%

Non Residential

41%

Pow er Generation

53%





Figure 83: Portugal, Historical Sectoral Demand

0

1

2

3

4bc

m

1997 1998 1999 2000 2001 2002 2003 2004





In April 1999 the Government passed Decree Law No. 137-A/99 which created Petróleos e Gás de Portugal (known as Galp) as a holding company to manage the country’s oil and gas industries. The original main shareholders in Galp were the Portuguese government (25.77%), Eni (33.34%), Energias de Portugal (EdP) (14.27%), REN (18.3%), Iberdrola (4%), Parpública (4.23%) and Setgás and Portgás (0.04%) each.

Galp was given shares in Petrogal (the oil company), Gás de Portugal (the gas distribution) and Transgás (the gas importer and transmission company). In April 2003 a plan was approved by the Government to demerge and privatise Galp through transferring all of the company’s gas activities (including the gas transmission business of Transgás) to Gás de Portugal, with Galp retaining Petrogal’s overseas oil production assets and the country’s two oil refineries.

Agreement amongst the shareholders was reached in early 2004 under which EdP, Eni and Rede Eléctrica Nacional (the Portuguese power grid operator) agreed to purchase 100% of the new incarnation of GdP. Under the terms of the proposed deal, Rede Eléctrica Nacional would exit the consortium after 12 months in return for being given the Transgás business, with the subsequent shareholdings being given to EdP (51%) and Eni (49%).




Further to this, Eni and EdP also agreed to sell their holdings in Galp to a state-owned investment firm, whilst in July 2004 the Portuguese government agreed to sell its 33.34% holding in Galp to an investment consortium.

In early 2005 the European Commission blocked the EdP and Eni acquisition of Gas de Portugal on the grounds that it would result in undue market concentration and was anti-competitive. In October 2005 signals from within the company proposed an IPO of between 25% and 30% of Galp before the middle of 2006. Subsequently in December 2005, EdP sold its 14.3% stake in Galp to Americo Amorim, a Portuguese investment company. Americo Amerim has subsequently increased its share in Galp to 24.7%. On the 31st of December the Portuguese government reached an agreement with Eni regarding further share purchases in Galp which will now not exceed 33% (Eni’s stake is currently 24.7%, equal to that of Americo Amorim). In January 2006, Iberdrola announced that they would be divesting their 4% share in Galp, but neither Eni nor Americo Amerim will be purchasing it.

Gas distribution is undertaken by six regional and four local gas distributors in which Galp has shareholdings. In February 2005 EdP acquired 59.55% of Portgas and a 10.11% stake in Setgas by exercising EUR 153.3 million of options.

Infrastructure

LNG A lack of both import pipelines and LNG regasification terminals meant that since Portuguese gas consumption began, all supplies had to be imported via Spain. This included LNG which was regasified at the Huelva terminal in southern Spain and then shipped by pipeline to Portugal.

When the Sines LNG terminal in southern Portugal became operational in October 2003, the reliance on Spanish infrastructure was reduced, thus boosting both security and diversity of supply. Sines has a capacity of 5.8 bcm, close to half of current demand levels.

Storage Due to its complete dependence on imported gas, storage is a key issue in the future development of the Portuguese gas market if security of supply is to be achieved, and to facilitate the need for swing gas resulting from the growth in residential demand.

Currently the country’s only storage capacity is in the form of 240,000 cubic metres of LNG storage at the Sines terminal. However, an underground salt cavern facility at Carrico near the city of Pombal in central Portugal is currently being developed. The




project’s initial 80 mcm of capacity is due to become operational by the end of 2005 with the remaining 220 mcm due online in phases before 2007.

In line with other parts of the world, gas fired power generation is playing an important part in the development of the Portuguese gas industry and will continue to do so as gas supplies become more widely available throughout the country. Gas-fired power generation capacity was increased in April 2004 with the inauguration of the first of three turbines at the Centraltejo power station at Carregado. Another two turbines will be coming on line by March 2006, taking the plant’s total capacity to 1,200 MW.




CHAPTER 26 ROMANIA

Market summary

Although production has been declining in recent years, Romania remains the largest producer of gas in the Central and Eastern European region. To compensate for the decline in production, significant imports are made, mainly from Russia.

Demand growth has been erratic in recent years with consumption levels peaking in 1984 though subsequently entering a period of prolonged decline. Current demand levels are less than half the levels seen as recently as 1990.

Market opening began in 2001 with around half the market now open to competition. Full market opening is expected by July 2007.

A number of infrastructure developments are currently at various stages of development including plans to double storage capacity and to develop new cross-border interconnections with the Ukraine and Bulgaria.





Table 36: Romania, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 12.60 13.20 4.8%Pipeline Imports Russia 5.30 4.60 -13.2%Germany 0.50 1.30 160.0% Total Pipeline Imports 5.80 5.90 1.7% LNG Imports 0.00 0.00 - Total LNG Imports 0.00 0.00 - Total Imports 5.80 5.90 1.7% Gross Supply 18.40 19.10 3.8% Exports 0.00 0.00 - Total Pipeline Exports 0.00 0.00 - Statistical Diffs 0.40 0.60 -Stock Change 0.30 0.30 - Net Supply 18.30 18.80 2.7% DEMAND Residential 3.38 3.48 3.0%Non Residential 10.43 10.70 2.6%Power Generation 4.49 4.62 2.9% Total Demand 18.30 18.80 2.7% Source: Datamonitor / National Sources / BP Statistical Review D A T A M O N I T O R




Supply overview

Romania is a significant producer of gas, so much so that is the largest producer in the Central and Eastern European region by a significant margin. Current reserves are estimated at around 300 bcm giving an R/P ratio of 22 years. Production reached a peak in 1982 and has since been declining significantly. Over the past decade production decline has averaged 3.1% per year.

The production decline has meant that imports, particularly Russian, have played an increasing role in recent years thus reducing gas self sufficiency. In late 2005 the supply contract with Russia held by Wintershall was extended from the previous 2012 expiry date to 2030.

Figure 84: Romania, Gas Production


0

5

10

15

20

25

30

35

40

1970 1974 1978 1982 1986 1990 1994 1998 2002

BC

M





Figure 85: Romania, Import Sources


Russia78%

Germany22%


Demand overview

Romania is the largest consumer of natural gas in the whole of Central and Eastern Europe. At 43%, the penetration of gas into the energy mix is extremely high, even when compared to much more mature and larger gas markets in Western Europe.

Demand growth has been somewhat erratic in recent years. Consumption levels peaked in 1984 and subsequently went into a prolonged period of decline. Current demand levels are less than half the levels seen as recently as 1990.

Between 2003 and 2004 there was a very slight increase in demand levels, though demand remains far removed from the mid 1980s peaks.




Figure 86: Romania, Sectoral Demand


Generation25%

Non Residential

56%

Residential19%


Figure 87: Romania, Historical Demand

0

10

20

30

40

bcm

1965 1969 1973 1977 1981 1985 1989 1993 1997 2001

Consumption



Through the Romanian Gas Law no. 351/2004, published in Monitorul Oficial no. 679/July 28, 2004, the natural gas market in Romania is harmonized with the European Gas Directives. The National Regulatory Authority for Natural Gas Sector, the ANRGN, was established by the Romanian government in 2000 through the ordinance 41/2000, approved by Law no. 791/2001.




Until 2000 the Romanian gas market was dominated by Romgaz. Following the implementation of decision 334/2000 by the Government Romgaz was turned into five fully state-owned companies: S.C. Distrigaz Sud (supply and distribution), S.C. Distrigaz Nord (supply and distribution), S.C. Exprogaz (production and storage), S.C. Depogaz S.A. (storage) and S.N.T.G.N. Transgaz S.A. (transmission and transit). The year after, through decision 575/2001, the government turned Exprogaz S.A. and Depogaz S.A. into one company, S.N.G.N. Romgaz S.A., in charge of natural gas exploration, production and underground storage.

In 2003, through decision 283/2003, the government ruled that the two state owned distribution companies, SC Distrigaz Sud SA and SC Distrigaz Nord SA, should be privatized. This process culminated in 2004 when the government sold 51% of Distrigaz Nord to E.ON Ruhrgas and 51% of Distrigaz Sud to GdF.

E.ON Ruhrgas and GdF have both expressed an interest in investing in Romgaz when it is privatised, though this is unlikely to occur before late 2006 according to latest signals from the Government.

In 2001 the opening of the Romanian gas market began. Currently around 100 customers, accounting for 50% of the market, are eligible to choose their supplier. Full market opening is planned for 2007.

Infrastructure

The Romanian transmission system is operated by the wholly state owned Transgaz S.A. and has a total length of about 11,800 kms. Two interconnections exist for facilitating Russian imports. These interconnections offtake gas from the Progress pipeline from Russia.

In total there are about 20 distribution companies in the Romanian market, each of which owns and operates its own distribution network. The two main distribution companies Distrigaz Nord and Distrigaz Sud, are majority owned by E.ON Ruhrgas and GDF.

Currently Romania has storage capacity of 3 bcm, though plans are currently under development to double this by late 2008.

Wintershall are currently undertaking feasibility plans regarding the possibility of constructing two pipeline projects in Romania. The first of this involves a link between the Suceava region, the location of a number of Romania gas fields, and the Ukraine. The second involves the construction of a link with Bulgaria.




CHAPTER 27 RUSSIA

Market summary

The Russian gas market is dominated by Gazprom, in which the state is the controlling shareholder.

Gas exports are a major source of export revenue for Russia and several new gas export projects are under way or being planned, including the North European Pipeline under the Baltic Sea, as well as a planned increase in LNG exports.

Gazprom is undergoing the process of internal restructuring aimed at a financial and organizational unbundling of activities and at achieving greater transparency and financial efficiency.

Foreign investment opportunities exit mostly on the upstream side. Some German energy companies, including Wintershall, are looking to invest in the development of new production fields in return for the right to export equity gas.





Table 37: Russia, Supply and Demand Balance BCM 2002 2004 CAGR SUPPLY Production 583.500 633.500 4.2% Pipeline Imports 0.000 0.000 - Total Pipeline Imports 0.000 0.000 - LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 0.000 0.000 - Gross Supply 583.500 633.500 4.2% Exports Former USSR 42.300 52.500 11.4% Germany 31.500 37.700 9.4% Italy 19.300 21.000 4.3% Turkey 11.800 14.400 10.5% France 11.400 11.500 0.4% Other Europe 54.600 55.900 1.2% Total Pipeline Exports 170.900 193.000 6.3% Statistical Diffs 23.700 38.400 - Stock Change 0.000 0.000 - Net Supply 388.900 402.100 1.7% DEMAND Residential 68.000 69.900 1.4% Non Residential 215.900 224.500 2.0% Power Generation 104.900 107.700 1.3% Total Demand 388.800 402.100 1.7% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Russia is the world’s largest gas producer, with 21.9% of production in 2004. Gas production, having peaked in the late 1980s, showed a slight decline in the mid-1990s due to under-investment in exploration and in asset replacement. However, 1998 saw the beginning of a recovery which continues to this day. In 2004, the country fell just short of the 1992 production level of 641bcm

The Yamal peninsula is Russia’ biggest gas production area, yielding 506.6bcm in 2004 (80% of the total), followed by other parts of Western Siberia. Sakhalin Island in the Far East, where several of the world’s oil and gas majors have been acting since the late 1990s under production sharing agreements (PSAs), is growing in importance

Russia exports c.30% of its gas output, mostly to the EU, Ukraine and Turkey. The country is also a major transit route for Central Asian producers

Figure 88: Russia, Gas Production

0

100

200

300

400

500

600

700

1992 1994 1996 1998 2000 2002 2004

Gas

pro

duct

ion,

bcm

Source: Datamonitor / BP Statistical Review D A T A M O N I T O R




Figure 89: Russia, Gas production by producer type

Gazprom86%

Independents14%

Source: Datamonitor / Gazprom D A T A M O N I T O R

Demand overview

Having peaked in 1991 at 431bcm, gas consumption dropped precipitously in the early 1990s due to the country’s economic difficulties. However, it has since recovered almost to its pre-crisis level, led by a combination of modest growth in industrial output and growing household incomes

Power generation and industry are the biggest gas consumers, with an estimated 27% and 31% of the 2004 total, respectively. Housing represents another major source of demand, as a combination of direct household consumption and district heating. In fact, much of the power sector demand can also be attributed to the housing sector, as it includes numerous CHP plants whose heat output is used primarily for district heating purposes

Finally, a significant proportion of total demand is accounted for by agrochemical plants which use natural gas as a feedstock in the production of fertilisers




Figure 90: Russia, Sectoral Demand


17%

Non Residential

56%

Pow er Generation

27%

Source: Datamonitor / BP D A T A M O N I T O R


Gas regulation of what is still an essentially monopoly market remains rudimentary. The Federal Energy Commission (FEC) sets the tariffs for Gazprom’s pipeline transportation services as well as the tariffs for large end users connected to UGSS grid. Meanwhile, the Regional Energy Commissions (RECs) set end-user tariffs for small and medium-sized markets in their respective regions.

In August 2005 a working group was set up by the Industry Ministry, the Economic Development Ministry, the Anti-Monopoly Service, Gazprom, independent gas producers and RAO UES in order to draw up a blueprint for the development of a competitive gas market and for corresponding changes in the regulatory regime.

The working group gave preliminary approval to the “5+5” scheme for market opening, developed by the Industry Ministry and Gazprom. Under the scheme, Gazprom on the one hand and independent producers on the other will each be able to sell up to 5bcm at deregulated prices.

The next meeting of the working group, scheduled for September 2005, will discuss issues such as non-discriminatory third-party access (TPA) to the transmission and distribution systems, the issue of long-term agreements, and the role of gas in the country’s fuel mix.




Gazprom estimates that intra-country gas sales will only become a sustainable business at the commodity gas price in the region of $59-65 per 1,000cm – almost double the current level. Therefore, the company is quite eager to see a quick development of market-based mechanisms, provided its dominant position is not threatened.

Industry restructuring

The Russian government has taken a very cautious stance in liberalising the gas market. It wishes to maintain a high degree of security of supply on the internal market and protect Gazprom’s pricing power on the export markets, given that gas exports contribute some 25% of the Russian budget.

That said, reform has also started in the gas sector. Gazprom is undergoing the process of organizational and financial unbundling into production, transportation, distribution and supply, and non-core activities. Whereas the immediate objectives of this are greater financial transparency and efficiency, in the long run the unbundling process would enable a relatively quick introduction of deeper market reform.

The liberalized segment of the gas market, while relatively small, is gradually growing. In 2004 there were 33 independent shippers of gas on the Russian market, accounting for almost 100bcm worth of transactions. Of that, 44bcm represented transit flows from Central Asia to Ukraine, and another 41bcm were accounted for by deliveries by Russian independent producers to Russian customers.

Under the current “5+5” model of gradual market opening, up to 10bcm per annum is designated for sales on the open market (5bcm by Gazprom and 5bcm by independent producers). This quota will gradually be expanded over the coming years, until eventually all industrial and other large business customers buy gas on the open market. However, households, small businesses and other “socially significant” customers (such as government bodies) will remain on regulated tariffs for the foreseeable future.

Moreover, Gazprom is planning to consolidate its grip on the regional distribution companies (RGKs), eventually bringing them all under its control under the wholly-owned Gazpromregiongaz subsidiary. No unbundling of distribution and supply is envisaged, hence Gazprom would regain its monopoly on the mass market while allowing competition in the major business user segment.




Figure 91: Russia - The state is planning to increase its stake in Gazprom to 51% and to expand the open market

Source: Datamonitor / Gazprom D A T A M O N I T O R

Competitive intensity

Over the next three years, a lack of meaningful unbundling between distribution and supply, as well as Gazprom’s continuing stranglehold on gas production, will hold back market development. This will allow Russian gas industry’s Market Competitive Intensity (MCI) score to reach only 2.7, compared with the current 0.9, which will not be enough to allow the introduction of genuine competition. Below, we provide the rationale behind this assessment.




Figure 92: Russia, gas market competitive intensity 2005-08


Market framework factors

Currently, FEC is mostly engaged in tariff-setting, as the liberalized segment is very limited in both scale and scope. It is too early to tell if it will have become a vigorous enforcer of competition rules by 2008, but it is unlikely that it will have too much room for independent action.

No TPA rights exist at present, so even an imperfect TPA regime will be a dramatic improvement. However, it is unclear what type of TPA regime will be introduced, and the unbundling of UGSS from the rest of Gazprom is likely to remain minimal.

System balancing is now Gazprom’s internal function, but by 2008 it is conceivable that an independent system operator will be in place, as well as some sort of arrangement for data transfer between suppliers.

Supplier push factors

In 2004, Gazprom was responsible for 86% of Russia’s wholesale gas. By 2008, this may decline to c.75% as independent producers increase their output.

Currently, Gazprom and its subsidiaries represent 70% of distribution volumes in the mass market and the bulk of large user sales volumes. By 2008, the company is likely




to cede some market share at the top end of the market but consolidate its grip on distribution.

There is no genuine wholesale gas market at the moment, but a rudimentary gas exchange may develop out of Gazprom’s ETP within the next three years.

Customer pull factors

Gas users at present have no access to independent market information sources and are not represented in any organized way. Datamonitor expects a modest improvement in this within the next few years.


At present, there is no proper exchange-based natural gas trading in Russia, although since the end of 2002 Gazprom has been trialing a proprietary trading platform – the Electronic Trading Platform (ETP). During its 2.5 years of operation, only 2.5bn of gas was sold through ETP.

Given the relatively trivial volumes, the main benefit of ETP has been in giving Russian gas industry players an experience of working with competitively formed prices, as well as creating an additional incentive for independent producers to increase production.

For now, both independent producers and Gazprom itself (to the limited extent that it is allowed to sell on the open market) sell the bulk of their gas on a bilateral basis, through either long-term supply contracts or short-term over-the-counter (OTC) deals with regional distribution companies (RGK) and major end users.

Infrastructure

Upstream

After years of neglect, Russia is stepping up investment in gas exploration, reversing the late 1990s trend of declining gas reserves. In 2004, proved reserves were estimated at 48tcm, or 26.7% of the world total. Gazprom alone operates over 6,000 working boreholes.




Figure 93: Russia, Gas reserves

40

42

44

46

48

50

1997 1998 1999 2000 2001 2002 2003 2004

Prov

ed re

serv

es, t

cm

Source: Datamonitor / BP Statistical Review D A T A M O N I T O R

Unified Gas Supply System

Russia’s Unified Gas Supply System (UGSS), owned by Gazprom, comprises 152,800km of high-pressure pipelines and 262 compressor stations. In 2004, it transported 687.4bcm of gas, including 99.9bcm on behalf of third parties. However, almost 60% of the transmission network is over 20 years old and will need to be replaced before long.

Table 38: Russia, Age of high-pressure pipelines, 2004


UGSS also includes 24 storage facilities with a 494mcm joint daily peak capacity. They include the world’s two biggest storages – the Kasimovskoye underground storage and




the Severo-Stavropolskoye depleted field storage. Another three facilities are under construction.

The distribution network, 75% of which is owned by Gazprom’s regional subsidiaries (GRKs), is c.537,000km long. This is low by OECD standards, where the 10:1 ratio of distribution to transmission system length is more common.

Export infrastructure

Almost all of Russia’s exports currently go through the Yamal, Brotherhood & Friendship Pipelines that cross Belarus and Ukraine into central Europe and the Balkans, supplemented by the recently completed Blue Stream underwater link with Turkey.

To decrease its dependence on the political regimes in the eastern European transit countries as well as transit gas theft, Russia is planning the North European Pipeline under the Baltic Sea to link it with Germany and, possibly, Scandinavia. Construction has begun and is due to finish in 2007.




Figure 94: Russia, Main existing and planned export pipelines

Source: EIA D A T A M O N I T O R

Gazprom has also been looking to diversify its gas exports. It is planning the construction of a major LNG facility near the Shtokmanov field on the Barents Sea shelf, in order to target the US market. Asian markets, primarily China, Japan and South Korea, are also likely future export destinations.




CHAPTER 28 SLOVAKIA

Market summary

Like many Central and Eastern European countries, Slovakia’s significance in gas terms comes from its role as a transit route for Russian gas going to the west rather than its minor role as a consumer and producer of gas.

With Western Europe’s reliance on Russian gas increasing, Slovakia is well placed to see a consequential increase in the volumes of gas it moves to the west.

Slovakia’s location near some of the largest Russian export pipelines, its storage capacity and the fact that transit volumes can easily be increased mean that it is in a strong position to take commercial advantage of the liberalizing European markets.





Table 39: Slovakia, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.197 0.165 -16.2% Pipeline Imports Russia 6.795 5.066 -25.4% Turkmenistan 0.000 1.882 - Total Pipeline Imports 6.795 6.948 2.3% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 6.795 6.948 2.3% Gross Supply 6.992 7.113 1.7% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.004 0.000 - Stock Change 0.001 -0.394 - Net Supply 6.989 6.719 -3.9% DEMAND Residential 1.984 1.907 -3.9% Non Residential 3.192 3.069 -3.9% Power Generation 1.813 1.743 -3.9% Total Demand 6.989 6.719 -3.9% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

The majority of Slovakian gas supply is imported from Russia. In 2004 gas supplies were given an added degree of diversity following the introduction of imports from Turkmenistan.

Indigenous production volumes are low, amounting to less than 0.2 bcm per annum or 2.5% of national demand. Aside from Nafta Gbely, the dominant gas utility, much of the E and P activity in Slovakia is undertaken by Carpathian Resources of Australia which has been exploring in the Western Carpathian area on the Austrian / Slovakian border. Latest estimates indicate reserves of less than 15 bcm.

Figure 95: Slovakia, Gas Production


0

0.5

1

1968 1972 1976 1980 1984 1988 1992 1996 2000 2004

BC

M





Figure 96: Slovakia, Imports By Source


Russia73%

Turkmenistan27%


Demand overview

Demand growth in Slovakia has been much weaker than in other European markets. In the decade to 2004, total demand grew by an average of just 0.4% per annum. The residential sector provided the majority of this growth, with the non-residential and power generation sectors declining over the period by 0.6% and 1.2% respectively.




Figure 97: Slovakia, Sectoral Demand


28%

Non Residential

46%

Pow er Generation

26%


Figure 98: Slovakia, Historical Sectoral Demand

0

2

4

6

8

bcm

1968 1972 1976 1980 1984 1988 1992 1996 2000 2004








The Slovakian energy sector is regulated by the Regulatory Office for Network Industries, known as URSO, which was created by the Act on Regulation of Network Industries number 276/2001. URSO also has responsibility for regulating the power sector.

The majority of legislation governing the Slovakian gas sector was laid out in the Energy Act No. 70 passed in 1998, which sought to bring the sector into line with the European Energy Charter.

Parts of the non-residential market were opened in mid 2002 with the remaining parts of the non-residential market open from January 2005. So far, the number of customers switching supplier has been very minimal. Legislation passed in November 2004 will ensure that all of the market is fully open by July 2007 in order to comply with the EU directive.

The Slovakian gas sector is dominated by Slovensky Plynarensky Priemysel (SPP), which imports, transmits and distributes gas, and Nafta Gbely, which produces and stores gas and oil. SPP is owned by E.ON Ruhrgas (24.5%), Gaz de France (24.5%) and 51% by the Slovakian government. Gazprom had an option to buy a 16.33% stake in the company before the end of 2005, though has decided not to exercise this option. Nafta Gbely is 56% owned by SPP, 40% by E.ON Ruhrgas and 4% by miscellaneous other shareholders. Legislative changes to the law on monopolies in mid 2004 will make it easier for the government to divest its stake in SPP, though it does not currently have any plans to do so.

In October 2005 the Government agreed draft legislation which will unbundle SPP into a transmission and a distribution operation. The parent company of the proposed new companies will own the national transmission grids whilst the distribution unit will own the low pressure distribution grid. Completion of the unbundling process is expected during 2006.




Infrastructure

Pipelines Slovakia’s role as a conduit for Russian gas going to the west is the key feature of the Slovakian gas industry. Two key pipelines for exporting Russian gas, the Brotherhood and Soyuz pipelines, run through the country transiting a volume equivalent to around 25% of Western European gas consumption and close to 80% of Russian exports to the west.

In 2004 82.7 bcm was moved through the transit system, equating to 88% of the system’s 94 bcm capacity, meaning that potential exists to increase flows at minimal marginal cost.

The distribution network run by SPP totals around 24,000 kms in length. Transit lines total 2,300 kms in length.

Storage Slovakia’s geographic position make it ideally placed to use its ample supply of storage capacity to full commercial advantage as the European markets both develop and liberalize.

In May 2004 Ruhrgas paid $75 million for RWE’s 40% stake in Nafta Gbely, the owner and operator of all Slovakia’s storage capacity.

Table 40: Slovakia, Storage Sites Name Operator Capacity Peak Deliverability mcm (mcm/day) Lab 1 to 3 Nafta Gbely 1705 24.85 Lab 4 Nafta Gbely 785 24.85 Source: Datamonitor D A T A M O N I T O R




Figure 99: Slovakia, Gas Grid

Source: SPP D A T A M O N I T O R




CHAPTER 29 SLOVENIA

Market summary

Although only a minor player in the European gas market, Slovenia is at a notably advanced state of liberalization.

Gas currently accounts for around 13% of the primary energy mix.

At around one bcm, demand is very small with the power generation and non-residential sectors playing a surprisingly minor role. Although supply volumes are small, they are diversified.





Table 41: Slovenia, Supply and Demand Balance BCM 2003 2004 (est) CAGR SUPPLY Production 0.000 0.000 -Pipeline Imports Austria 0.050 0.088 75.0%Algeria 0.400 0.383 -4.3%Italy 0 0.003 -Russia 0.654 0.621 -5.0% Total Pipeline Imports 1.104 1.094 -0.9% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 1.104 1.094 -0.9% Gross Supply 1.104 1.094 -0.9% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.000 0.000 -Stock Change 0.000 0.000 . Net Supply 1.104 1.094 -0.9% DEMAND Residential 0.836 0.829 -0.8%Non Residential 0.189 0.188 -0.5%Power Generation 0.079 0.077 -3.1% Total Demand 1.104 1.094 -0.9% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Until 1992 Slovenia was entirely dependent on Russia for its gas supplies. However a contract with Algeria’s Sonatrach changed this and gave an added element of diversity and security of supply.

The import contract signed with Sonatrach in 1992 contains a provision that will gradually increase imports up to a peak of 0.6 bcm by 2007. Smaller volumes are also imported from Italy and Austria.

Figure 100: Slovenia, Imports By Source


Russia57%

Italy0.3%

Algeria35%

Austria8%


Demand overview

The residential sector dominates gas use and accounts for more than three quarters of demand.

A combination of economic growth, expansions to the distribution grid and investments in gas fired power mean that strong demand growth can be expected in the short to medium term.

Despite this expected demand growth, absolute consumption levels will remain modest.




Figure 101: Slovenia, Sectoral Demand


Residential15%

Non Residential

58%

Pow er Generation

27%



The Slovenian gas sector is regulated by the Slovenian Energy Agency which was set up in 2002 to oversee the gas and power markets. The Energy Law of 1999 began reforming the energy sector with subsequent amendments to incorporate EU legislation. Central to this was the Slovene Energy Act of July 2004. The first phase of market opening took place in 2003 when the country's 20 large industrial consumers became eligible to switch their supplier. Subsequently in July 2004 the non-residential market opened in line with the terms of the gas directive. Full market opening is scheduled before the July 2007 deadline.

The market is monopolised by Geoplin which is responsible for the supply and sale of gas directly to eligible end users and distributors. In order to ensure compliance with the unbundling requirements of the gas directive a new company, Geoplin Plinovodi, was created at the beginning of 2005. However the current lack of new market entrants and the strength of Geoplin will ensure Geoplin retains much of its dominant position for some considerable time. In the distribution sector there are currently 17 licensed players

The attractiveness of the Slovenian energy market to new entrants is constrained by the small size of the market and the fact that many of the larger energy buyers in the country are shareholders in Geoplin and thus have little or no incentive to switch supplier.




Infrastructure

Pipelines Slovenia is interconnected with Austria via the Sud-Ost Leitung (SOL), a spur connection feeding off the TAG pipeline. SOL has a 3.3 bcm per annum capacity and is owned and operated by OMV. An interconnection with Italy also feeds from the TAG line.

Geoplin is currently undertaking various projects to expand and upgrade the gas grid which is at, or close to, full capacity. Increased capacity is required to facilitate the likely increase in gas demand over the coming years.

The country’s distribution network totals around 1,000 kms in length.

Figure 102: Slovenia, Gas Grid

Source: Slovenian Energy Agency D A T A M O N I T O R




CHAPTER 30 SPAIN

Market summary

Strong GDP growth through the late 1990’s combined with rapid industrialisation have contributed to above average growth in both gas and energy demand in Spain. Over the past decade gas demand growth has averaged more than 13% per year.

This has boosted the role gas plays in the primary energy mix from 7% to 17% over the ten years to 2004.

Despite a softening in economic growth in recent years, gas demand is likely to show continued strength in the coming years with no indications that the Government’s goal of seeing gas account for 22.5% of primary energy demand by 2011 will not be met.

Demand for gas in power generation has driven much of this growth and will continue to do so in the coming years.

Limited indigenous resources make Spain heavily import dependent. These imports are sourced as pipeline gas and LNG from Algeria, pipeline gas from Norway transported via the French border, and LNG from a variety of sources.

The production and supply landscape of the Spanish gas market is expected to change significantly after the Spanish Supreme Court gave conditional approval for Gas Natural to take over Endesa in January 2006, though it remains to be seen if the deal is actually transacted following a surprise bid by E. On.





Table 42: Spain, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.215 0.339 57.7% Pipeline Imports Algeria 6.130 7.380 20.4% Norway 2.300 2.190 -4.8% Total Pipeline Imports 8.430 9.570 13.5% LNG Imports Algeria 7.170 6.440 -10.2% Libya 0.715 0.658 -8.0% Nigeria 3.921 4.771 21.7% Oman 0.547 1.255 129.4% Qatar 1.893 3.770 99.2% Trinidad 0.032 0.000 - UAE 0.372 0.311 -16.4% Others 0.087 0.177 103.4% Total LNG Imports 14.737 17.382 17.9% Total Imports 23.167 26.952 16.3% Gross Supply 23.382 27.291 16.7% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.100 0.131 - Stock Change -0.013 0.270 - Net Supply 23.269 27.430 17.9% DEMAND Residential 3.037 3.580 17.9% Non Residential 14.400 16.975 17.9% Power Generation 5.832 6.875 17.9% Total Demand 23.269 27.430 17.9% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

With reserves of less than 3 bcm, Spain’s scope for meeting gas demand indigenously is very limited and production meets less than 1% of demand.

The majority of production comes from Repsol-YPF’s Poseidón field, with smaller volumes coming from the Valle de Guadalquivir field. National production fell by more than 50% between 2002 and 2003 due to production problems at Poseidón which was shut in for 5 months during the year. However production has since grown again, albeit to still modest levels.

Despite the dominance of Algerian gas, supply sources are very well diversified reflecting security of supply legislation which sets a 60% limit on the proportion of national demand any one gas supply source can constitute. In February 2005 Union Fenosa imported Egyptian LNG to Spain for the first time from its Damietta project which it jointly owns with Eni.

Figure 103: Spain, Gas Production


0

1

2

1983 1987 1991 1995 1999 2003

BC

M





Figure 104: Spain, Imports By Source


Oman (LNG)5%

Qatar (LNG)14%

Others (LNG)2%

Nigeria (LNG)18%

Libya (LNG)2%

Algeria27%

Norw ay8%

Algeria (LNG)24%


Demand overview

Over the past decade, Spanish gas demand has grown strongly at an average of 12.5% per year. Gas fired power plants have been the driving force of this demand growth and resulted in power generation gas demand growing by an average of 23% per year in the decade to 2004. Continued construction of new CCGTs will continue to provide significant impetus to gas use in power generation.

The residential and non-residential sectors have also shown extremely strong growth of 13% and 10% per annum respectively owing to significant and ongoing expansion to both the transmission and distribution grids. Demand is likely to continue to show strong growth in the short to medium term, although the rate of growth is likely to slow as gas penetration increases in the longer term.




Figure 105: Spain, Sectoral Demand


13%

Non Residential

62%

Pow er Generation

25%


Figure 106: Spain, Historical Sectoral Demand

0

5

10

15

20

25

30

bcm

1969 1973 1977 1981 1985 1989 1993 1997 2001








The hitherto immature and undeveloped nature of the Spanish gas market has allowed the country to adopt a very pro-liberalisation stance in recent years, at least partly due to the fact that such a stance would help catalyse development of the industry.

The speed and momentum of liberalisation policy in Spain has consistently exceeded that required by the EU. The liberalisation process was begun with the Hydrocarbons Act in 1998 which laid out plans for market opening and set up the Comisión Nacional de Energia (CNE) to act as a regulator. Further pro-liberalisation legislation came with the passing of Royal Decrees in 1999 and 2000.

All Spanish energy consumers have been able to choose their supplier since January 2003, some five and a half years ahead of the full market opening deadline of July 2007 set out by the second EU Gas Directive.

Initially switching rates were very low with just 167,000 customers (3%) switching supplier in 2003. However switching rapidly developed in 2004 with more than 1.2 million (21% of the market) having switched by the end of the year as a result of extensive advertising and special offers by utilities. By the end of the third quarter of 2005 this figure had increased to 1.766 million customers or 28% of the total.

Prior to liberalisation, the Spanish gas market was almost entirely controlled by Gas Natural. Although still holding a commanding position, Gas Natural’s position has been eroded by pro-liberalisation policies whilst its attempts to expand have been curtailed.

Strong demand growth and a liberalized market make Spain an attractive target for European gas players looking to internationalise their activities in response to liberalisation induced market share erosion in their own markets. Foreign players who have entered the Spanish market include Eni, BP and Shell.

Gas Natural’s position is also being eroded by Spanish power utilities who have entered the gas market. These include companies such as Union Fenosa, Iberdrola, Hidrocantábrico and Centrica via its Luseo Energia subsidiary.

Spain had a gas release programme between the end of 2001 and early 2004 under which one third of the 6 bcm being piped by Gas Natural was re-allocated to other companies.

In January 2006 the Spanish Supreme Court decided to allow a proposed merger between Gas Natural and Endesa, an electricity producer – though it remains to be seen if the deal is actually transacted following interest from other parties. Although the Court’s ruling incorporated some strict conditions aimed at preventing anti-




competitive practice, the merger will still create a very significant presence within the market; a merged entity would control 40% of gas and electricity distribution, 60% of sales and 65% of supply.


A fledgling gas wholesale gas market has been emerging in Spain – though it will still be a considerable time before meaningful liquidity develops, despite growing volumes and a growing number of longer term deals including some for 1 year periods being transacted.

The small amount of trading activity undertaken by around 14 players is more closely related to swap rather than spot or forward deals with volumes changing hands between parties and then the same volume being passed back again at a later date at an equal price. Usually these deals are done on the basis of the weighted average cost data published by Enagás (the grid operator) rather than having any element of market based price formation in them. LNG time swaps are an increasing part of this emerging market and will continue to be so as more cargoes are imported.

In February 2005, new balancing rules were introduced which have the potential to bring more liquidity to this swap activity. The new rules mean that Enagás will store gas free of charge for 5 rather than the original 10 days at LNG terminals and for 2 rather than 5 days at the Centro de Gravedad, the country's technical balancing point which takes the form of a virtual hub like the UK’s NBP or Italy’s PSV.

The changes will force shippers to balance on a more disciplined basis. Whilst this may help catalyse wholesale activity in the longer term, it will probably encourage a wider role for the existing swap deals in the shorter term.




Infrastructure

LNG LNG has long played a key role in the Spanish gas market accounting for 63% of total consumption. At 17.4 bcm per annum, Spain is the world’s fourth largest LNG importer after the US, Japan and South Korea and accounts for more than 49% of Europe’s LNG imports.

Sources are well diversified, with seven separate countries delivering LNG, a degree of diversification second only to Japan.

Spain currently has five operational terminals, with another two under construction. Although geographically in Portugal, the Sines terminal is connected to the Spanish grid.

The regulator has been keen to encourage Third Party Access to LNG facilities. In late 2002 it ruled that GdF, Eni and Iberdrola were entitled to access capacity at LNG terminals, overruling the claim by Enagás that there was no spare capacity because it had all been allocated to Gas Natural.

Table 43: Spain, LNG Infrastructure Name Operator Size Status Barcelona Enagas 11 bcm Operational Cartagena Enagas 8 bcm Operational Huelva Enagas 8 bcm Operational Bilboa BP, Iberdrola, Cepsa, EVE 3 bcm Operational Sines Transgas 5.2 bcm Operational, located in

Portugal Reganosa Fenosa, Endesa, Sonatrach 3.4 bcm Under construction, start up

due 2007 Sagunto Fenosa, Iberdrola, Endesa 6.6 bcm Under construction, start up

due 2007 Source: Datamonitor D A T A M O N I T O R




Pipelines Gas is imported to Spain by Enagás via two cross-border pipelines:-

The Lacq-Calahorra pipeline on the French border allows the importation of Gas Natural’s 2.4 bcm per annum contract with Norway. Given its 4 bcm capacity, imports could theoretically be increased via this route, though capacity constraints in the French system mean that this remains problematic.

Euskadour - In mid-2003, the French, Spanish and Portuguese regulators jointly declared their intention to offer incentives to encourage increased pipeline interconnections between France and Spain in order to ease bottlenecks and congestion. This aim has since been achieved with the development of the Euskadour pipeline which, following its inauguration in the latter part of 2005, allows Spain to re-export gas to south west France.

The Pedro Duran Farell pipeline (formerly known as the GME or Maghreb-Europe line) brings Algerian gas into the south of Spain via Morocco. In 2004 a large capacity expansion was undertaken, increasing throughput to close to 12 bcm per annum.

Small volumes of gas landed at the Sines LNG terminal in Portugal are also imported to Spain via two cross-border links.

Spain’s transmission system is owned and operated by Enagás. Third Party Access tariffs are published by the government, based on an entry-exit model.

Pipeline developments

Medgas - A consortium including Spanish oil company Cepsa, Algeria’s Sonatrach, BP, GdF, Endesa and Iberdrola signed an agreement in 2001 to construct an 8 bcm per annum link between Algeria and Spain to supplement the existing connection. The project, known as Medgas, has been subject to delays caused by financing difficulties though received final regulatory approval in June 2005. Construction is due to start in July 2006. Assuming these timings are adhered to, initial flows are likely by early 2009.




Figure 107: Spain, Gas Grid

Source: Comisión Nacional de Energia D A T A M O N I T O R

Storage

Total storage capacity at Spain’s storage sites totals just over 1.4 bcm, equivalent to only a few weeks’ average supply. This shortage of storage means that storage tanks at the country’s LNG sites are of added importance.

The CRE has expressed concern at the lack of storage capacity. The CRE’s 2002 energy plan made a number of suggestions to boost capacity, including the possible conversion of the Poseidón field to a storage site and the expansion of the Gaviota site. Spain’s only new storage project currently under development is a plan by Canada’s Eurogas to convert the Amposta field in the Gulf of Valencia to a 1 bcm per annum storage facility when the oil reservoir depletes in 2009.

The CRE has also expressed concern at the utilisation made by Spain’s 14 gas traders of existing storage capacity, and has pointed out to the traders that, under the terms of the 1998 Hydrocarbons Bill, they are required to maintain at least 35 days of supply in




storage. In response, the traders argue that the current storage pricing regime gives insufficient incentive for them to store beyond their short-term needs.

Storage in Spain is operated under a non-discriminatory Third Party Access model overseen by the regulator.

Table 44: Spain, Storage Sites Name Type Operator Capacity Peak (mcm) Deliverability (mcm / day) Gaviota Depleted gas field Enagas 770 5.7 Serablo Depleted gas field Enagas 635 4.9 Total 1405 10.6 Source: Datamonitor D A T A M O N I T O R




CHAPTER 31 SWEDEN

Market summary

Gas plays only a very small role in the Swedish energy mix owing to the strong dominance of both hydro and nuclear power.

Gas has only been consumed in the country since 1985. All gas consumed in Sweden is currently imported from Denmark, although scope does exist to diversify supply sources when required.

The residential sector is a very small consumer of gas and is likely to increase its role as the distribution grid reaches new areas of the country.





Table 45: Sweden, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.000 0.000 - Pipeline Imports Denmark 0.983 0.979 -0.4% Total Pipeline Imports 0.983 0.979 -0.4% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 0.983 0.979 -0.4% Gross Supply 0.983 0.979 -0.4% Exports 0.000 0.000 - Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.095 0.095 - Stock Change 0.000 0.000 - Net Supply 0.888 0.884 -0.5% DEMAND Residential 0.043 0.043 -0.4% Non Residential 0.507 0.505 -0.4% Power Generation 0.338 0.337 -0.4% Total Demand 0.888 0.884 -0.4% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Sweden did not become a gas consumer until 1985. A lack of indigenous production means that all gas supply has to be imported. Currently the sole source of supply is Denmark, though various plans have been mooted, including an LNG terminal, to increase both the size of imports and the diversify of supply sources.

Gas penetration has been held back by the dominance of nuclear and hydro power, which together account for 61% of the primary energy mix. By contrast, gas makes up less than 1.5% of primary energy demand.

Sweden’s geographic position means that it would be relatively simple to build pipeline infrastructure to import Russian, Dutch and Norwegian gas when sufficient demand exists. Given the current very low levels of demand in Sweden, interconnections of this type will not be needed in the short, or probably medium, term.




Demand overview

Current levels of demand are low compared to other European countries, owing to a lack of infrastructure and the dominance of other fuels.

Gas is currently consumed in just 30 of Sweden’s 289 municipalities. In these municipalities gas has a penetration of around 20%, a level comparable with many other more developed gas markets. However, the small number of municipalities connected to the gas grid means that overall gas penetration for the country is far lower.

In mid 2004 the future prospects for gas demand growth were advanced, following the connection of Sweden’s main petrochemical complex at Stenungsund to the gas grid.

Figure 108: Sweden, Sectoral Demand


Residential5%

Non Residential

57%

Pow er Generation

38%





Figure 109: Sweden, Historical Sectoral Demand

0.0

0.5

1.0bc

m

1985 1988 1991 1994 1997 2000 2003





The Swedish gas market is regulated by the Swedish Energy Agency, known as STEM, which was formed in 1996. In addition to the gas market, STEM also regulates the power market. Sweden transposed the terms of the first gas directive into national law via the Natural Gas Act of August 2000 and opened the market to consumers using more than 15 mcm per year (around 10 users). Subsequent amendments were made in order to comply with the accelerated directive, though the opening of the remaining part of the non-residential market in July 2005 took place one year behind the EU deadline. Full market opening in line with the directive is planned for July 2007.

There are currently two main players in the Swedish gas sector: Nova Naturgas and Sydkraft. Nova Naturgas is owned by E.ON Ruhrgas (30%), Statoil (30%), DONG (20%) and Fortum (20%), whilst Sydkraft is owned by E. ON (55%), Statkraft (44.6%) and various minority interests (0.4%).

In January 2005 the Swedish government issued a report in which it expressed reservations about the structure and undeveloped nature of the market. Of specific concern was the dominance of Nova Naturgas and the fact that Dong is both the only source gas imports and a 20% stakeholder in Nova.

In late 2004 the role of gas TSO was passed to Svenska Kraftnat, the country's power TSO. Previously Nova had been acting as TSO on an unofficial and informal basis as




well as acting as a distributor. The decision to appoint Svenska Kraftnat as TSO was something of a surprise given that the TSO role was widely expected to have been awarded to Nova.

Infrastructure

Pipelines Danish gas is imported into Sweden via a subsea pipeline under the Oresund sea and lands at Klagshamn, close to Malmo where it enters the Swedish grid.

The majority of the Swedish network is owned and operated by Nova Naturgas with a small number of minor branch lines owned by Sydkraft. The Swedish grid runs in two main sections – the north to south axis runs between Trelleborg in the south and Gothenburg in the north (owned by Nova Naturgas), whilst the east west axis runs from Kristianstad to the west coast (owned by Sydkraft). Sydkraft is in the process of expanding its network further to the east,

The low levels of gas penetration in Sweden mean that there remains scope for the continued development of the grid to gasify the inland municipalities not yet connected to the gas gird. Various initiatives are underway to expand the existing infrastructure.

During 2004 Nova Naturgas and Sydkraft were in discussions regarding the possibility of forming a joint venture company to unify their infrastructure and to expand the transmission network. However these negotiations were abandoned in March 2005 following an inability to agree on the value of the assets involved.

In September 2004 Sydkraft was given permission to build the Baltic Gas Interconnector, a 210 kms pipeline linking Trelleborg in Sweden with Rostock in Germany. When the 5 bcm per annum project become operational in 2010 it will give a much needed element of supply diversity to the Swedish market.

Currently Sydkraft is developing plans to build a 1.5 bcm to 2 bcm LNG reception terminal at Oxelösund on the east coast. When developed, the project would not only diversify Swedish supply but would also bring gas to the east of the country for the first time. If developed the project is unlikely to be operational before at least 2010.

In addition to the supply diversity benefits that these two project will bring to the market, they will also catalyse a more competitive market by providing supply to potential new market entrants.




Figure 110: Sweden, Gas Grid

Source: Sydkraft D A T A M O N I T O R




CHAPTER 32 SWITZERLAND

Market summary

At just over 9% of the primary energy mix, and total annual demand levels of less than 3.5 bcm, gas plays a much lower role in Switzerland than it does in other nearby markets at similar stages of economic development.

Market opening and liberalisation is yet to take place in the Swiss market and all but the very largest end users are able to choose their supplier. Possible market opening and liberalisation options are currently being explored to liberalise the market though any developments in this regard are not expected in the short to medium term.

Switzerland has no indigenous gas resources and is therefore entirely dependent on imports. Russia is the main source of imports and accounts for more than half of supply volumes. Imports are well diversified coming from a range of sources.





Table 46: Switzerland, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.000 0.000 0.000Pipeline Imports France 0.521 0.346 -33.6%Germany 1.458 1.720 18.0%Italy 0.118 0.182 54.2%Netherlands 0.706 0.748 5.9%Russia 0.406 0.315 -22.4%Total Pipeline Imports 3.209 3.311 3.2% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 3.209 3.311 3.2% Gross Supply 3.209 3.311 3.2% Exports Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.000 0.000 -Stock Change 0.000 0.000 - Net Supply 3.209 3.311 3.2% DEMAND Residential 1.174 1.211 3.2%Non Residential 1.782 1.839 3.2%Power Generation 0.253 0.261 3.2% Total Demand 3.209 3.311 3.2% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

A lack of indigenous resources means that Switzerland is entirely dependent on imports of natural gas. The largest single source of imports is Germany, accounting for more than half of supplies.

Smaller volumes are imported from other neighbouring markets.

Figure 111: Switzerland, Import Sources


Russia10%

Netherlands23%

France10%

Germany52%

Italy5%


Demand overview

At just over 9% of the primary energy mix, gas plays a much lower role in Switzerland than it does in other nearby markets at similar stages of economic development. Despite accounting for around 2.5% of European GDP and 1% of population, Switzerland accounts for less than 0.5% of European gas demand.

Demand growth has averaged 2.1% per year over the past decade. At 5.4% per annum, by far the largest demand growth rates have been seen in the power generation sector. Growth in the residential and non-residential sectors has averaged 2.1% and 1.8% respectively over the period.




Figure 112: Switzerland, Sectoral Demand


Generation8%

Non Residential

55%

Residential37%


Figure 113: Switzerland, Historical Sectoral Demand

00.5

11.5

22.5

33.5

bcm

1970 1974 1978 1982 1986 1990 1994 1998 2002





The main regulatory body in the Swiss gas market is the Swiss Federal Office of Energy (SFOE) which is part of the Federal Department of Environment, Transport, Energy and Communication.




The SFOE has a traditional regulatory remit and is responsible for issues such as regulating transmission TPA, promoting security of supply, increasing energy efficiency and contributing to national energy policy. Further to this the SFOE has a remit in areas not often seen by other regulator such as its role in nuclear safety and oil transportation health and safety issues.

The Swiss gas market is controlled by a small number of players. Of these, Swissgas AG, which accounts for 75% of the country's imports is by far the largest. The majority of gas imported by Swissgas is then sold on to four regional associations consisting of local utilities cooperating together to secure gas supplies for onward sale to end users. These regional associations are Gasverbund Mittelland AG, Erdgas Ostschweiz AG, Gaznat SA and Ergas Zentralschweiz AG.

Gas distribution is undertaken by around 100 utilities. These utilities vary greatly in size with the seven largest accounting for half the market and the remainder having a market share of just a few percent. In general these utilities are owned by local governments. The ownership of Swissgas AG is shared by the four regional associations as well as the Association of the Swiss Natural Gas Industry.

A lack of political willingness to open up the market and the ongoing monopolies held by the regional players mean that consumer choice and freedom to choose supplier are not currently prevalent in the Swiss market. The SFOE is currently examining possible liberalisation options, though developments in this regard are unlikely to occur in the short term.

The only exception to this monopoly control and lack of consumer choice is in the Major Energy User segment. Since the 1960s Art. 13 of the pipeline Act has allowed major industrial gas users direct third party access to the transmission grid. This process is overseen by the “Koordinationsstelle Durchleitung” (KSDL), part of Swissgas AG.

Infrastructure

The Swiss natural gas grid is well integrated with the European gas grid allowing imports to be made from a diverse range of sources. In the mid 1970s the first natural gas was imported from Europe via a pipeline built through Switzerland to Italy from the Netherlands. This became known as the Transitgas system, 51% owned by Swissgas AG.

The Transitgas system led to the development of a transmission grid which is currently around 2,100 kms in length and a 14,000 kms long distribution grid. About two thirds of the Swiss population live in municipalities connected to a local gas grid.




The transmission grid includes about 290 kms of the Transitgas system and about 1,600 kms of regional high pressure pipelines. Most of the remaining part belongs to the Swissgas AG system and consists of four high-pressure pipelines leading from the Transitgas pipeline to the various regions. These four pipelines are:-

Eastern natural gas pipeline – diameter 400 mm, length 43.8 kms (Aargau – Zurich)

Western natural gas pipeline – diameter 400 mm, length 538 kms (Aargau – Bern)

Rhone valley natural gas pipeline – diameter 250 mm, length 48.5 kms (Valais – Vaud), diameter 300 mm, length 92.5 kms (Visp – Bex)

Central Switzerland natural gas pipeline - diameter 250 mm, length 13.8 kms (Lucernbe – Lucerne)

Figure 114: Switzerland, Gas Grid

Source: Swissgas AG D A T A M O N I T O R




CHAPTER 33 TURKEY

Market summary

Despite having seen strong demand growth of over 12% per annum over the past decade, Turkish gas demand has fallen considerably short of forecasts.

In the late 1990s strong economic growth resulted in extremely bullish demand growth forecasts, which in turn led to the construction of a number of large pipeline projects.

A severe economic downturn in 2001 meant that much of the forecast demand growth did not materialise, leading to significant excess supply and Take or Pay disputes.

Indigenous production remains modest, with no imminent signs of any significant increase. As such, Turkey is heavily import dependent. Although around two thirds of imports are sourced from Russia, the presence of an import link with Iran and LNG supplies from Nigeria and Algeria mean that imports are relatively secure and diverse.





Table 47: Turkey, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 0.000 0.000 0.000Pipeline Imports France 0.521 0.346 -33.6%Germany 1.458 1.720 18.0%Italy 0.118 0.182 54.2%Netherlands 0.706 0.748 5.9%Russia 0.406 0.315 -22.4%Total Pipeline Imports 3.209 3.311 3.2% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 3.209 3.311 3.2% Gross Supply 3.209 3.311 3.2% Exports Total Pipeline Exports 0.000 0.000 - Statistical Diffs 0.000 0.000 -Stock Change 0.000 0.000 - Net Supply 3.209 3.311 3.2% DEMAND Residential 1.174 1.211 3.2%Non Residential 1.782 1.839 3.2%Power Generation 0.253 0.261 3.2% Total Demand 3.209 3.311 3.2% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Turkish indigenous production levels are extremely low so gas imports play a key role in the country’s growing gas demand. Gas imports began in 1987 following the signature of a long term contract with Russia.

Currently less than 3% of Turkish demand is met indigenously. As rapid demand growth continues, self sufficiency levels will diminish even further.

The majority of imports are sourced from Russia, though imports from Iran also play a role. Since 1994 LNG has played a key role in meeting gas supply and imports are now made from Nigeria and Algeria.

Figure 115: Turkey, Gas Production


0

100

200

300

400

500

600

700

800

1981 1984 1987 1990 1993 1996 1999 2002

MC

M





Figure 116: Turkey, Imports by Source


Nigeria (LNG)

5%

Russia65%

Iran16%

Algeria (LNG)14%


Demand overview

Excessively bullish forecasts of gas demand growth made in the late 1990s have turned out to have been unfounded following a period of severe economic problems in 2001. However, since then the economy, and hence energy demand, have both recovered meaning that Turkey has nonetheless seen demand growth significantly above many other markets.

In the decade to 2004 annualised demand growth averaged over 12%. In common with other relatively immature gas markets, the key driver of this growth has been the power generation sector which has grown by 14.5% over the period. Growth in the residential and non-residential sectors has also been strong at 12.1% and 7.6% respectively.




Figure 117: Turkey, Sectoral Demand


Pow er Generation

62%

Non Residential

19%

Residential19%


Figure 118: Turkey, Historical Sectoral Demand

0

5

10

15

20

25

bcm

1982 1986 1990 1994 1998 2002








The Turkish energy sector is regulated by the Energy Market Regulatory Authority (EMRA), which was established in 2001 under Law no. 4628. Subsequently its remit was widened to include the gas sector following the passing of the Natural Gas Market Law no. 4646.

Turkey is a candidate country for EU membership and as such has legislated for market opening in line with the EU gas directive. The market is currently 80% open with users above 1 mcm per year eligible to choose their supplier. However, in reality, the strong position held by BOTAŞ, which until 2001 held a monopoly on the gas market, means that very little consumer choice exists. Theoretically, full market opening will take place by July 2007.

A Network Code governing use of the transmission and distribution grids came into force in September 2004. End user prices are regulated by the EMRA and will remain so until it rules that sufficient competition has become established. Given that the distribution sector is currently being opened to competition this process is continuing, though the dominance of BOTAŞ remains a severe constraint on the development of competitive conditions.

Plans have been mooted for BOTAŞ to be unbundled by 2009. In tandem with this there are plans requiring the company to gradually forfeit market share so it is left with 20% of the market by 2009, though continued legislative disputes make the exact nature of these plans unclear.

Each year BOTAŞ undertakes a gas auction under which it makes available to new entrants 10% of its contractual gas purchase quantities.

Infrastructure

The first, and most important, piece of Turkish gas infrastructure is the pipeline importing Russian gas into Turkey via Bulgaria. When this pipeline became operational in 1986 it was used exclusively to supply the Trakya CCGT plant at Hamitabat. Over the course of the following two years a larger distribution grid was constructed allowing supplies to be made to both the residential and non residential sectors in Ankara. Subsequently the transmission and distribution grids were expanded bringing gas to larger areas of the country.

The development of this pipeline was followed in January 2002 by the start up of an import line from Iran, though lower than expected demand growth resulted in significant flow interruptions and legal disputes.




In February 2003 a third pipeline, known as Blue Stream, came online supplying gas from the Russian Federation. Blue Stream runs underneath the Black Sea and lands gas at Samsun before going overland to Ankara. Like the Iranian pipeline, lower than expected demand growth has meant that Blue Stream has flowed considerably less gas than had originally been forecast, resulting in a six month suspension in flows soon after its inauguration.

Plans had been developed for another import project known as the Trans Caspian Gas Pipeline (TCGP) from Turkmenistan, though weaker than expected demand growth and the presence of the existing import pipelines means that the project is unlikely to materialise in the short to medium term.

LNG imports began in 1994 at the Marmara Ereglisi terminal which has an annual capacity of 3.2 bcm. Currently imports are made from Algeria and Nigeria.

Gas storage does not currently exist in Turkey, though various projects continue to be assessed.

Figure 119: Turkey, Gas Grid

Source: BOTAS D A T A M O N I T O R




CHAPTER 34 UNITED KINGDOM

Market summary

Since natural gas production from the UK continental shelf (UKCS) first began flowing in the mid-1960s, gas has increasingly played a key role in the UK energy mix, with strong demand growth both in the past and forecast for the future.

Traditionally, indigenous supplies have allowed the UK to be a net exporter of gas, however the UKCS has now matured resulting in the UK becoming a net gas importer at the end of 2004.

This decline in indigenous production has resulted in a growing need for gas imports from other parts of the EU, Russia and Norway, as well as other more distant supply sources in the form of LNG.

The UK has a long history of gas market liberalisation dating back to 1995 and is now the most liberalized market in the EU.





Table 48: UK, Supply and Demand Balance BCM 2003 2004 CAGR SUPPLY Production 108.532 101.182 -6.8% Pipeline Imports Belgium 1.323 3.428 159.1% Norway 6.528 8.678 32.9% Total Pipeline Imports 7.851 12.106 54.2% LNG Imports 0.000 0.000 - Total LNG Imports 0.000 0.000 - Total Imports 7.851 12.106 54.2% Gross Supply 116.383 113.288 -2.7% Exports Belgium 11.744 6.565 -44.1% Ireland 4.051 3.557 -12.2% Netherlands 0.311 0.263 -15.4% Total Pipeline Exports 16.106 10.385 -35.5% Statistical Diffs -0.011 -0.011 - Stock Change 0.318 -0.567 - Net Supply 100.606 102.347 1.7% DEMAND Residential 34.982 35.587 1.7% Non Residential 34.355 34.950 1.7% Power Generation 31.269 31.810 1.7% Total Demand 100.606 102.347 1.7% Source: Datamonitor / IEA D A T A M O N I T O R




Supply overview

Current reserves on the UKCS stand at 590 bcm, giving a Reserves to Production ratio of 6 years.

Production in 2004 totalled around 101 bcm, a 7% decrease on 2003. Exports totalled 10.4 bcm (down from 16.1 bcm in 2003) whilst imports reached 12.1 bcm (up from 7.8 bcm the previous year). Overall this meant that imports exceeded exports by 1.7 bcm compared with the previous year’s 8.3 bcm net surplus. The movement to net importer status came as no surprise given the ongoing production decline, though it had not been expected until at least 2006. Despite the movement to net importer status, the UKCS still has considerable production capacity both now and in the future. This means that, given current reserves, imports are unlikely to exceed production until at least 2012, a date that will move further back if significant new reserves are found by current exploration activity.

The majority of production activity takes place in the North Sea, though smaller volumes are produced both onshore and in the Irish Sea.

Most reserves are in the form of non-associated gas located in three distinct areas – the central North Sea, the northern North Sea and the Southern Basin.

Offshore reserves are landed via 4 main pipeline systems – see Infrastructure.

The 3.4 bcm of gas the IEA classifies as being imported from Belgium is in reality sourced from the Netherlands and Germany, though is delivered from Belgium via the Interconnector.

Figure 120: UK, Gas Production


0

20

40

60

80

100

120

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000

BC

M





Figure 121: UK, Imports By Source


Belgium28%

Norw ay72%


Demand overview

As an established and mature market, gas demand growth rates are much less spectacular in the UK than in other markets at earlier stages of development.

Total demand in the UK has risen by an average of 3.1% over the past decade. A concerted movement towards gas fired power in the 1990s, the so called “Dash for Gas”, meant that the power generation sector has played a key part in this demand growth, though the growth in this sector was subsequently curtailed by a temporary moratorium on new gas fired power capacity. Over the decade to 2004, demand in the power generation sector grew by an average of 8.7% per year, compared with 1% and 1.8% in the non-residential and residential sectors respectively.




Figure 122: UK, Sectoral Demand


Residential35%

Non Residential

34%

Pow er Generation

31%


Figure 123: UK, Historical Sectoral Demand

0

20

40

60

80

100

120

bcm

1960 1964 1968 1972 1976 1980 1984 1988 1992 1996 2000 2004


Residential Non Residential Pow er Generation






As one of the world’s most liberalized gas markets, regulatory policy in the UK differs from that in other EU countries in that it focuses more on policing the market rather than on seeking to introduce competition.

The liberalization of the UK gas industry began with the 1986 Gas Act, which legislated for the privatization of British Gas. In the same year, OFGAS (the Office of Gas Supply) was created to regulate the industry and promote the interests of gas consumers. Further legislation relating to consumer protection and energy pricing was contained in the Utilities Act 2000 which also merged Ofgas with Offer (the power industry regulator) to form Ofgem (Office of Gas and Electricity Markets).

Currently, Ofgem does not have any jurisdiction over issues relating to offshore gas production, although it is currently lobbying the government for an extension to its powers to take over this responsibility from the Department of Trade and Industry.

The first gas market opening in the UK came in 1992, when competition was introduced to large Industrial and Commercial consumers, a process which encouraged new players to enter the market. At this point however, British Gas maintained a monopoly over non-Industrial and Commercial supplies. Competition was encouraged with a gas release program to aid new market entrants.

British Gas continued to hold this monopoly until the passing of the 1995 Gas Act, which opened up the whole market to competition. Competition was introduced regionally over a 2 year time period in order to allow processes and systems to be perfected before national roll-out. The market officially became fully open to competition in late May 1998.

Competition has become well established in the UK, with around 50% of customers having switched their supplier, with significant numbers of consumers having chosen to switch their supplier more than once.

Since the market opened, average bills have fallen by around a third, collectively saving consumers around a billion pounds each year.

Rates of switching in the gas market are higher than in other markets. In the telecoms sector, which was liberalized 14 years before the gas markets, only around 30% of customers have exercised their right to switch from the former monopoly supplier.

The interests of customers have been further advanced by the existence of the UK’s wholesale gas market, where gas is traded on a bi-lateral basis between producers and shippers. Wholesale trading in the UK is subject to the rules laid out by the Network Code, the terms of which are overseen by Ofgem.




Most gas is traded at a notional point within the UK gas grid known as the National Balancing Point (NBP) (see Wholesale Environment) which accounts for the vast majority of wholesale liquidity in Europe.


The National Balancing Point (NBP) is Europe’s leading and most active wholesale gas market and accounts for the bulk of European wholesale market liquidity.

Aside from the commercial opportunities that exist from trading at the NBP, there are also significant opportunities available for arbitraging with the Zeebrugge market by utilising either the Interconnector or the power market in the form of spark spreads.

Gas is traded in various contract lengths ranging from within day to up to two years. An NBP futures contract has been traded on the International Petroleum Exchange (renamed ICE Futures after its parent company the Intercontinental Exchange in October 2005) since January 1997.

Rather than being a physical hub located at a specific point, the NBP is a notional or virtual point allowing delivery anywhere within the UK gas grid.

Currently there are around 60 active NBP players at various stages in the value chain. These players are primarily gas shippers, but also include producers, power generators and financial institutions. To trade at the NBP, players need to obtain a shippers license from Ofgem.

An indication of the NBP’s strength is the fact, in the past, its ratio of trades to physical flow has averaged between 9:1 and 10:1, meaning that between nine and ten times as much gas is traded as actually flows. However, this liquidity has diminished significantly recently, particularly in the forward part of the curve given that many players have been unwilling to take significant long term positions in light of the upward movement in prices seen in 2004 and 2005. Another factor attributable to the decrease in liquidity is the growing trend for utilities to vertically integrate by buying upstream assets, thus reducing their wholesale market purchasing needs.




Infrastructure

Transmission and distribution

The UK National Transmission System (NTS) is one of the few elements of the UK gas industry still under monopoly control. The infrastructure is owned and operated by National Grid Transco (NGT), an incarnation of the now demerged former monopoly British Gas. Ofgem oversees the regulation of the NTS through the use of price controls governed by an “RPI minus” formula reviewed every five years. Gas enters the NTS at 6 coastal terminals around the UK. From here it exits the system in any one of 8 Local Distribution Zones (LDZ’s).

Historically the LDZ’s were owned by NGT, although in 2003 the company invited interested parties to express their potential interest in purchasing a number of the zones. In August 2004 deals were concluded with Australia’s Macquarie Bank and a consortium of United Utilities and CKI who each bought one zone, with Scottish and Southern Energy buying two. Completion of the deal occurred in June 2005.

Entry capacity to the NTS is auctioned in monthly tranches. The 60 users of the NTS are obliged to obtain a shipper’s license from Ofgem and are governed by the terms of the Network Code, a set of rules governing use of the system. A key requirement for shippers is to balance their deposits to and withdrawals from the NTS on a daily basis. Short term wholesale gas prices are heavily influenced by the shipper’s efforts to keep the system in balance.

Offshore infrastructure

Key infrastructure for landing gas in the UK includes:-

The SAGE (Scottish Area Gas Evacuation), FLAGS (Far North Liquids and Associated Gas System), Fulmar, Vesterled and FRIGG pipelines all land gas at St. Fergus in the north east of Scotland.

CATS (Central Area Transmission System) lands gas at Teesside from central North Sea fields.

The Easington and Theddlethorpe terminals, to the south of Teesside, also land central North Sea gas.

The SEAL (Shearwater Elgin Franklin Area Line) lands gas at Bacton, on the east coast.




Gas from the Morecambe North and South fields in the Irish Sea is landed on the UK’s north west coast.

Gas is exported from the UK mainland via the following pipelines:

UK-Belgium Interconnector - runs between Bacton and Zeebrugge, Belgium. The pipeline has the ability to operate in both forward and reverse flow modes. Current capacity is 20 bcm per annum in forward flow (exporting gas from the UK to Zeebrugge) and, following expansion completed in late 2005, 16.5 bcm per annum in reverse flow (exporting gas from Zeebrugge to the UK). Further expansion work will increase this to 23.5 bcm by the end of 2006.

Gas from the UK is exported to Ireland via two Interconnectors running from south west Scotland to the County Dublin area. The first was built in 1993, with the second completed in 2002. A spur from the second Interconnector also supplies the Isle of Man.

SNIP (Scotland to Northern Ireland Pipeline) ships gas from the UK mainland to Northern Ireland.

Two significant pipeline projects are currently being built with one other significant project possible:

Langeled – Norwegian exports to the UK will be significantly increased following completion of the Langeled pipeline. Up to 20 bcm of gas from the new Ormen Lange field will be shipped through the pipeline. The project is being developed in 2 phases. The first phase will supply gas to the UK via the Sleipner platform from late 2006, with the second part of the pipeline supplying gas from Ormen Lange by October 2007.

BBL – the Bacton to Balgzand project linking the Netherlands to the Bacton coastal terminal in the east of the UK is currently being constructed. The planned project will have sufficient capacity to import up to 16 bcm per annum of low calorific Groningen gas to the UK, equivalent to about 14 bcm of high cal gas. Regulatory delays in obtaining a license to exempt the pipeline from Third Party Access requirements in order to provide sufficient capital return on the project had delayed construction work, though this finally began in October 2004. Initial flows are expected by early 2007.

North European pipeline – Gazprom, BASF and E.On are currently developing plans to construct a 30 bcm pipeline supplying Russian gas to Britain and other parts of Western Europe under the Baltic. Initial flows are expected by 2010.




LNG The UK had a long history as an LNG consumer and became the world’s first importer of LNG in 1964, before closing its’ regasification facility in the early 1980’s following the growth in indigenous production.

The maturing of UK indigenous supply, increasing demand and improvements in LNG economics, have meant that LNG is set to re-emerge as a key source of UK gas supplies.

Three new regasification projects are currently under way:

Isle of Grain – Located on the River Medway, 20 miles from London, NGT’s Isle of Grain project came online in July 2005. All of the project’s 4.4 bcm per annum capacity has been reserved by BP and Sonatrach. NGT has been awarded permission to expand capacity to 14.7 bcm which could be operational by late 2007 or early 2008.

Milford Haven – Two separate projects are currently under development at Milford Haven in Wales. The Dragon project being developed by Petroplus, BG and Petronas is a 6 bcm facility and is expected to enter service by late 2007. Qatar Petroleum and ExxonMobil have now resolved various regulatory and financing issues at their 10.5 bcm South Hook project and completion of the project is now expected by the end of 2008. Plans are being developed to double the plant's capacity to 21 bcm.

Two other potential LNG projects have been mooted, although both are in the very early stages of development, and as such are not certain to reach the construction stage.

UK supplier Centrica, Calor Gas and LNG Japan have lodged a planning application to develop a new LNG terminal on Canvey Island in the east of England. The £150-200 million terminal will have enough import capacity to supply 5.4 bcm per year, meeting 5% of the UK’s gas needs. If planning permission is agreed the project should be operational by 2010.

Canatxx of the USA has stated its intention to construct a terminal on the Isle of Anglesey.

ConocoPhillips is currently seeking planning consent to build an LNG terminal at the Teeside oil terminal in northeast England.

Despite the future supply gap created by demand growth and indigenous supply contraction, it is far from clear if these projects will be able to find room for their LNG in the market (at least in the short term), given the larger projects already at far more advanced stages of development and the existence of various competing pipeline projects.




Table 49: UK, LNG Infrastructure Name Operator Size Status / Expected start up (bcm) Isle of Grain NGT 4.4 Operational South Hook Exxon

Mobil/Qatar Petroleum

10.5 Under construction/2008

Dragon Petroplus 6 Under construction/2007 Canvey Island Calor Unspecified Early planning stage/2008 Amlwch Canatxx Unspecified Early planning stage/2008 Source: Datamonitor D A T A M O N I T O R

Storage

As self sufficiency in gas diminishes, the role of storage in the UK will take on a greater importance in order to meet peak demand swings and to protect against supply disruptions.

In the past, the development of storage capacity has been a low priority for the UK gas industry. Plentiful supply and the fact that many of the older fields on the UKCS had high swing capabilities mean that the UK now has much less storage capacity than continental Europe.

Existing storage capacity in the UK is dominated by Centrica’s Rough site which, at 2,800 mcm, accounts for 77% of the UK’s total storage capacity and is able to meet 10% of peak day demand.

In addition to Centrica Storage, the other key player in the UK storage market is Scottish and Southern Energy which operates the Hornsea facility.

With the changing supply dynamics now prevalent, increased levels of storage are likely to be needed in the short to medium term.

A number of new projects to meet the projected need for additional storage capacity are now at various stages of development. These include:

Scottish and Southern Energy and Statoil are currently developing a 420 mcm site at Aldbrough, Humberside due to be opened in 2007.




EDF Trading is doubling the size of its Hole House Farm facility. An additional 150 GWh will be on line from early 2007 with another 150 GWh from early 2009.

Star Energy, the owners of the Humbly Grove facility inaugurated in November 2005, are also developing four other projects. The most advanced of these is at Welton in Lincolnshire which is due online in 2008.

In May 2004 Scottish Power was awarded planning consent to construct a 168 mcm facility at Byley in Cheshire, due to come into service by 2009.

Canatxx is planning to develop a 1,600 mcm site at Fleetwood in Lancashire, though the project is now subject to a planning enquiry. As such we do not expect it to be operational before at least Q2 2010.

Eural Trans Gas has indicated that it is considering acquiring a depleted offshore gas field to be converted into a storage facility.

Warwick Energy is seeking to convert its Caythorpe field into a 180 mcm storage site by 2007.

Centrica and Amerada Hess are examining the possibility of converting the York field into a storage site.

Wingas has applied for planning permission to extend the life of its Saltfleetby gas field in Lincolnshire by converting it to a storage facility with expected capacity of more than 700 mcm.

Table 50: UK, Storage Sites Name Type Operator Capacity Peak (mcm) Deliverability (mcm / day) Rough Depleted Field Centrica Storage 2,800 42 Hornsea Salt Cavity Scottish and

Southern 325 18

Hatfield Moors Depleted Field Scottish and Southern / EOG

134 1.7

Hole House Farm Salt Cavity EDF Trading 12 2.7 5 LNG Peak Shavers

LNG NGT 374 75

Humbly Grove Depleted Field Star Energy Total 3,925 167.4 Source: Datamonitor D A T A M O N I T O R

Appendix




CHAPTER 35 APPENDIX

Data sources

Statistical data is sourced from the International Energy Agency (IEA). Data for countries not members of the IEA (Algeria, Bulgaria, Croatia, Cyprus, Estonia, Latvia, Lithuania, Malta, Russia, Romania and Slovenia) is sourced from national sources such as regulators, energy companies and government departments.

Data Adjustments

IEA source data does not disaggregate LNG and pipeline imports therefore proportions have been taken from the BP Statistical Review of World Energy and applied to the IEA imports total.

Sectoral Demand - End use demand data breakdowns have not been provided for the latest year by the IEA.

End use proportions for the previous year have been used and applied to the latest total demand data.

End use sectoral consumption is disaggregated by the IEA into various industries such as the mining industry, chemical processes, manufacturing etc. Datamonitor aggregates this data up into the following groups :-

Residential – consists of end use consumption by households.

Non-Residential - consists of end user consumption in the Industrial and Commercial sectors including public services.

Power Generation - gas used by gas fired power stations for conversion into electricity. This includes gas inputs to both public and private power, CHP and heat production generation.

Statistical differences are balancing adjustments used to compensate for conversion differentials and differing calculation assumptions in IEA source data.

Appendix




Definitions

Aquifer – a type of gas storage facility using the site of former underground water deposits.

Associated gas – gas found alongside oil deposits.

bcf – billion cubic feet

bcm – billion (10 to the power of 9) cubic metres

E and P – Exploration and Production.

IEA – International Energy Agency

LNG – Liquefied Natural Gas

mcf – million cubic feet

mcm – million cubic metres

mtoe – million tonnes of oil equivalent

Non-Associated gas – gas that occurs in its own structure rather than alongside oil deposits.

RPI – Retail Price Index

Salt Cavern – A type of gas storage facility using former salt mines.

Town Gas – Gas manufactured by collecting the methane emitted from burning coal.

TPA – Third Party Access

TSO – Transmission System Operator

UKCS – United Kingdom Continental Shelf

Appendix




Future readings

DMEN03417 - Market Competitive Intensity: Current and Future Trends Assessments of Competitive Development in Key European Gas and Power Markets

DMEN0370 - Future Development of European Wholesale Energy Markets: The likely development of wholesale gas and power markets in selected European countries

DMEN0401 – European 33 Electricity Market Profiles: Q1 2006 Update

SPP writing team

Andrew Hill – Lead Analyst [email protected]

Karl Lindstrom – Associate Analyst [email protected]

For more information on this report or other European energy market research, please contact your Datamonitor account or the author.

Appendix




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Documents

European 33 Gas Market Profiles 2006