Long-Term Natural Gas Supply to Europe: Import Potential, Infrastructure Needs and Investment Promotion

Long-term natural gas supply to Europe: Import potential, infrastructure needs and investment promotion

Manfred Hafner, Sohbet Karbuz, Benoit Esnault, Habib El Andaloussi Observatoire Méditerranéen de l‘Energie (OME)

Due to increasing European gas demand and declining domestic supplies, Europe faces a growing import dependency over the next decades. Europe‘s neighbouring regions are endowed with substantial reserves and resources which can cover the increasing European import requirements in the medium to long term. W ith the development of its different uses, especially for power generation, gas is increasingly gaining importance for European energy security of supply. A substantial captive demand has indeed developed during the past decade, which explains the essential role the EU gives to natural gas in its energy policy. Securing and increasing gas supply will, however, require huge investments on all the segments of the gas chain, namely exploration and development, international transit and downstream infrastructures (gas lines and storage). These investments will be realised by energy companies and will, therefore, require an appropriate investment climate, which not only involves economic considerations but also a stable environment, a clear regulation and the possibility for operators to develop necessary strategic partnerships. This paper assesses the future long term (2010-2020-2030) gas import requirements and external supply potential for Europe, and identifies future gas corridor infrastructure needs taking into account a reserve/resource analysis, production and demand outlooks, export infrastructure and projects, supply costs as well as institutional, strategy and geopolitical issues, etc. Finally, the paper identifies investment barriers for different types of gas corridor infrastructure projects and proposes issues to be addressed by policymakers in order to put in place a favourable environment regarding investment promotion and to create a sustainable gas market for the long term. The paper is based on the work carried out by OME in the framework of the ENCOURAGED (Energy Corridor Optimization for the European Markets for Gas, Electricity and Hydrogen) project financed by the European Commission DG-Research 6th Research and Development Framework Programme.

1. Long term European gas import requirements

Import requirements are the difference between domestic demand and domestic production. According to the two demand scenarios used in this study, import requirements in Europe-341 should increase from 220 bcm in 2000 to 470 bcm in 2030 in the low gas demand scenario and even up to 650 bcm in the high gas demand scenario (Figure 1), this represents a doubling or a tripling of import requirements over three decades. Such an evolution requires increasing supplies from the traditional European suppliers as well as developing additional sources.

1 Europe-34 corresponds to EU-27 plus Switzerland and all the Balkan countries.

1 Figure 1 Europe-34 future gas import requirements

bcm

900 m

800 c b

High demand scenario 0 700 5 6 m c

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Low demand scenario 7

500 4 400 300 Import m

c requirements b

0 200 2 2 100 European gas production 0 2000 2010 2020 2030 Europe-34 corresponds to EU-27 plus Switzerland and all the Balkan countries Source: DG-TREN and OME

It should here also be pointed out that, in addition to the future European demand uncertainties, there exists a great level of uncertainty concerning future domestic gas production forecasts. The biggest question mark is the rate of decline of the UK gas production. For example, the EC DG-TREN estimate used here assesses UK gas production in 2020 at 88 bcm, whereas the UK Department of Trade and Industry estimates it below 20 bcm. A level between these two figures seems reasonable, but this illustrates the level of uncertainty associated to future gas import requirements.

2. Long term external gas supply potential to Europe

In order to satisfy future import requirements, a thorough assessment of long term potential gas supply sources has been carried out. A large number of potential natural gas suppliers to Europe have been considered. Because of the long term character of this study, up to 2030, and the continued rapid evolution of the world of natural gas, the possibility for new suppliers to appear during the period under consideration cannot be ruled out. The assessment of the future supply potential by each exporting country to Europe has been based on the following bottom-up methodology. Reserves and resources (reserves which are not discovered yet) assessment combined with the countries‘ energy strategy and institutional framework as well as exploration and development efforts have allowed to evaluate a future production potential. Assessment of future domestic demand, the countries‘ gas exporting strategy, presence of international companies and export projects, economic, institutional, geographical and geopolitical considerations as well as arbitration possibilities between different export markets have allowed to evaluate the total gas export potential and the export potential to Europe. W henever possible and, in particular, up to 2015-2020, the analysis was based on existing projects and infrastructure capacity for exports (by pipeline and LNG) as well as contracts. The more remote the analysis, the more it had to be based on assumptions.

2.1. Norway

According to the Norwegian Petroleum Directorate, Norway‘s total gas resources amounted in 2005 to 6007 bcm (about 55% in the North Sea, 31% in the Norwegian Sea and 14% in the Barents Sea). By 2005, Norway had produced 948 bcm. The remaining resources are evaluated at 5059 bcm, of which 3159 bcm of proven reserves. The large percentage of proven reserves indicates that Norway will remain an important gas producer over the foreseeable future. Until today only about 60% of the Norwegian Continental Shelf has been opened to exploration. The North Sea is the best explored area and, after more than 30 years of exploration, while the average success rate is currently above 40%, the average size of new discoveries is declining. Exploration has progressively shifted from the North Sea, further north to the Norwegian Sea and recently to the Barents Sea, which represents major technological and environmental challenges. Gas production in Norway has been steadily increasing as new fields and export pipelines came online. Norway‘s gas production more than tripled during the last ten years, increasing from 28 bcm in 1995 to 87 bcm in 2005. W ith 1129 bcm remaining reserves, Troll is the Norway‘s largest natural gas field. Ormen Lange, with 375 bcm of reserves, is the second largest. It is expected to start operation in 2007. Norway is also developing the Snøhvit field, whose production is expected to start in 2007, in the Barents Sea. Many operators have ambitious plans to increase production from their existing fields. Gas production is expected to increase markedly in the future, especially after 2007 when Ormen Lange starts producing. Domestic gas consumption remains very limited (about 1% of Norway‘s energy consumption). Though gas fired generation could significantly increase in the coming years, we expect that about 90% of the future gas production should be for the export market. Norway‘s offshore transportation system (Figure 2) has mainly been designed for exports to continental Europe. Its present export capacity amounts to some 87 bcm/yr. Exports through these lines have strongly increased over the past years and reached 79 bcm in 2005. Norway‘s system is also connected to the UK through the Vesterled pipeline, from Frigg and Heimdal fields to St Fergus (13 bcm/yr). A new 1200 km offshore pipeline (the Langeled pipeline) will carry the gas produced from the Ormen Lange field, in the Norwegian Sea, to Easington, on the English east coast. This 22-24 bcm/yr pipeline is expected to start operation fully by October 2007, but the southern part of this pipeline began already gas deliveries in October 2006. There is moreover a plan to build a new export pipeline, with 20 bcm/yr capacity, from Kollsnes to either continental Europe or to the UK. In addition, Norway is establishing LNG export capacity by building two liquefaction trains (5.7 bcm/yr each) in Snovhit, which will be online by 2007 and 2012. All these developments will enable Norway to export some 130 bcm of gas, of which 120 bcm for Europe, by 2030.

3 Figure 2 North European gas infrastructure and projects Shtokmanovskoye Existing Gas Pipeline Snohvit Shtockman Gas Pipeline Project LNG SnohvitLNG 23 bcm 6-11 bcm

Asgard fields/ ATS Haltenbanken 21 bcm FINLAND

S Ormen Lange/Britpipe T A 22 bcm Ormen SWEDEN Lange NORWAY M urchison Troll Frigg/Vesterled Eastern axe 45 bcm 13 bcm Norpipe 11 bcm Frigg Europipe I 13 bcm HELSINKI

Europipe II 21 bcm

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I TALLINN

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F F Z Z Bacton al Balgzand am Isle of Grain BBL Y 5/10 20 bcm Source: OME

2.2. North Africa

North Africa is a traditional gas supplier of Europe. In addition to their vast gas resources, North African countries benefit from their geographic proximity to Europe, especially of its fastest growing markets, the EU Mediterranean countries. W hile Algeria has remained almost the only exporter for decades, Libya and Egypt are rapidly developing their sales.

4 Figure 3 Export infrastructure and projects from North Africa to Europe

PORTUGAL Algeria-Italy via ITALIY SPAIN Sardinia Corsica (Galsi) 8 to 16 bcm Algeria-Italy Enrico Mattei Gasline (EMG, ex-Transmed) Algeria-Spain LNG Algeria 25 to 31 bcm (Medgaz) 27 to 38 bcm 8 to 16 bcm SICILY ALGER Skikda Arzew LNG (G.Touil) BeniSaf Damietta 5 bcm EMG Libya-Italy SEGAS (UFG) (Greenstream) 2x6.9 bcm Pedro Duran Farell 8 to 16-24 bcm Gasline (PDFG, ex-GME) PDFG Bouri Idku TUNISIA ELNG (BG) 11.5 to 18-20 bcm 3x4.8 bcm Hassi R’Mel Libya-Tunisia LNG Libya TRIPOLI MOROCCO 2 bcm 1 to 9-14 bcm

Marsat - El Braga ALGERIA Egypt to Libya R.Nouss Ghadames Basin Hatiba 3 to 5 bcm Hamra Reg Tegentour TFT Ohanet Zelten In Amenas LIBYA Ahnet In Salah Gasline Projects Wafa ExistingGaslines

ExistingLNG Plant TSGP LNG Plant Projects Nigeria-Algeria to Europe

Source: OME

2.2.1. Algeria Algeria holds the most important reserves with 4580 bcm estimated as of January 2006. The Hassi R‘Mel field contains more than half of it, while other fields are far smaller. Gas to be discovered has been estimated at about 1400 bcm by USGS, however, this figure was based on old estimates. Algeria has carried out an important exploration effort, focusing on sedimentary basins of 1.6 million km×. In the past 20 years, more than 150 discoveries were made. The realisation of new domestic gas pipelines will also connect new areas to the main network infrastructure, opening them to gas production. Natural gas gross production increased rapidly during the last 15 years from 127 bcm in 1990 to 152 bcm in 2005. Approximately 50% of this gross production is reinjected. There are several gas development and evacuation projects in Algeria. Of these, In Salah came on stream in 2004 and its production is expected to be maintained at 9-11 bcm/yr over about 25 years with the possibility to increase to 18-19 bcm/yr. The In Amenas gas project came on stream end of 2006, and its production is expected to reach 9 bcm/yr in 2007; it consists in developing production in a region where reserves are estimated at more than 700 bcm. In the Ahnet region, another gas development project is under way. Last, the Gassi Touil Integrated LNG Project aims at exporting the production from Gassi Touil. Algeria has a well established pipeline transport system linking the gas fields in the extreme south east region of In Amenas to the giant field hub of Hassi R'Mel and to the LNG plants of Arzew and Skikda, to Italy via the Enrico Mattei Gasline (ex-Transmed) to Spain and Portugal via the Pedro Duran Farrel Gasline. The capacity of these two lines is planned to be increased by about 15 bcm/yr with the addition of compressors. Algeria has two new pipeline

5 projects in order to reach the Spanish and Italian markets without having to cross any transit country: the Medgaz pipeline to Spain (8 bcm/yr) planned to be operational by 2008 (this pipeline could later be expanded to 16 bcm) and the Galsi pipeline to Sardinia and mainland Italy (8-10 bcm/yr) shortly after 2010 and a possible doubling at a later stage. W ith four liquefaction plants, Algeria is also an important LNG exporter and intends to further develop its liquefaction capacity. Once the new projects under way are completed, total LNG capacity could increase from the current 27.5 bcm/yr to 43 bcm/yr by 2030.

2.2.2. Libya Libya's officially estimated proved gas reserves more than doubled over the past two decades, from 626 bcm in 1985 to 1500 bcm in 2006. However, for the past 30 years, exploration efforts remained limited and Libya‘s strategy mainly focused on oil rather than gas. Even though the USGS estimated the mean undiscovered reserves at about 600 bcm, the Lybian national oil company NOC is more optimistic, estimating its resource potential more than 3300 bcm. The lifting of the remaining EU and US sanctions in September 2004, and Tripoli‘s efforts to bring in foreign investors translated into several Exploration and Production Sharing Agreements bid rounds. Libya‘s gross gas production reached a peak of 20.4 bcm in 1980 (most of it reinjected or flared), but decreased to 12.5 bcm in 1995 and remained close to that level until now. The marketed production only amounted to 11 bcm in 2005. In the future, most of the gas output is expected to come from non-associated fields while the production of associated reservoirs is expected to decline progressively. The capacity of the Greenstream gas pipeline (currently 8 bcm/yr), connecting Libya to Sicily in Italy, could be doubled or even tripled during the next decades. After 2007, a new onshore 2 bcm/yr pipeline will allow to export gas also to Tunisia. The capacity of Libya‘s liquefaction plant is currently 1 bcm/yr, compared to its 3.5 bcm/yr original capacity. There are projects underway to upgrading and expanding the Marsa El Brega LNG plant and possibly to building an additional LNG export facility. Assuming that the domestic gas consumption could double, reaching to 12 bcm by 2030 and according to the ongoing gas export development plans, Libya could increase its export potential progressively from 5.4 bcm in 2005 to 40 bcm by 2030. This can be achieved by increasing pipeline export capacity to Italy and adding new LNG plants. Most of these potential gas export volumes would be available to Europe.

2.2.3. Egypt The proved natural gas reserves of Egypt hugely increased over the past two decades, from 265 bcm in 1986 to 1900 bcm in 2006. The continual increase in reserves is attributed to the use of new advanced technology in exploration, development and production, with the assistance of international companies. That led to discoveries in the deep waters of the Mediterranean continental shelf, in the Nile Delta and in the W estern Desert, which is considered as a new promising petroleum province. Still under-explored, Egypt has a great potential for more oil and gas discoveries, especially in the north of the Sinai, the Nile Delta and the W estern Desert. According to official statements, the present gas reserves are to be equally dedicated to exports, domestic consumption and creating a strategic reserve. Since the early 1990s, the Egyptian government‘s policy consists in substituting natural gas to oil and oil products in almost all economic sectors, in particular in power generation, which

6 accounted for two thirds of Egypt‘s gas consumption. Domestic consumption could double by 2020, under the pressure of the population growth, and even reach 84 bcm by 2030. Egypt started to export gas in 2003 through the Trans-Mashreq gasline to Jordan2. The country has an ambitious LNG export policy with two important LNG projects: SEGAS in Damietta which should count two 6.9 bcm/yr liquefaction trains by 2010; and ELNG in Idku, which shall have two or three trains of 4.8 bcm/yr. In total, three trains (18 bcm/yr capacity) are already operational. Assuming that the marketed gas production will quadruple between 2005 and 2030, to reach some 120 bcm, and considering that the domestic demand could triple, Egyptian exports are expected to strongly increase in the coming years from 8 bcm in 2005 to almost 40 bcm/yr by 2030. LNG should represent about three quarters of this total, most of which for the European market.

2.3. W est Africa

2.3.1. Nigeria Proved gas reserves of Nigeria were estimated at about 5000 bcm. Once probable and possible reserves are included, this figure is estimated to triple. From 1.7 bcm in 1980, marketed gas production has increased to 21.2 bcm in 2005. But end of 2006 still some 40% of natural gas production is flared. Official Nigerian policy is to end natural gas flaring completely by 2008 by collecting associated natural gas and processing it into LNG. Nigeria began exporting gas in 1999 with the completion of the first train in the Bonny Island LNG plant. Currently, Nigeria has five operational trains in Bonny Island with a total capacity of 21 bcm/yr. A sixth train of 5.3 bcm/yr will be realised by 2007 bringing the total export capacity to 29 bcm/yr. There are four other LNG projects in Nigeria announced for 2010. If all of them were to be implemented in the foreseen timeframe, which seems rather unlikely, the total additional export capacity of Nigeria would amount to 50-60 bcm/yr. Nigeria‘s LNG export capacity is expected to reach 29 bcm by 2010, possibly increasing to 86 bcm by 2030. The most ambitious project is the Nigeria-Algeria Trans-Saharian Gas Pipeline (TSGP), from the Niger River Delta to Northern Algeria crossing Niger and the Sahara Desert. Europe is the targeted market of this 4500 km long pipeline of 18 to 25 bcm/yr. However, this project remains highly questionable. Except for its political situation, Nigeria seems not to have any limiting factor for increasing natural gas production over the next 25 years. Domestic demand should progress from 9 bcm in 2005 to 40 bcm by 2030. Large volumes of gas should therefore be available for exports to the American and European markets.

2.3.2. Angola Angola is sub-Saharan Africa‘s second largest oil producer behind Nigeria. However, there is no consensus about its gas reserves. The estimations range from a pessimistic 45 bcm to an optimistic 700 bcm. About 85% of the produced gas is flared, and the remainder is reinjected to maintain oil production and processed in the production of LPG. The government intends to reduce gas flaring and convert the associated gas to LNG, NGLs, and LPG. An onshore

2 This pipeline will be extended to Syria and Lebanon, and possibly also to Turkey.

7 LNG plant at Soyo (6.8 bcm/yr of capacity), in Northern Angola is expected to come online around 2009. Angola is, therefore, foreseen to become a gas exporter starting from around 2010. A possible addition of a second train would increase the LNG capacity to 13.6 bcm/yr, hence doubling the exports.

2.4. Russia

Russia holds the world‘s largest natural gas reserves and is the world‘s biggest producer and exporter of natural gas, providing about a quarter of Europe‘s total gas needs. Its strategy will have a determining impact on the future dynamics of the international gas markets. Europe particularly relies on supply from Russia for its future security of supply. According to Gazprom, total initial Russian gas resources are 250 tcm (2004). Of these initial gas resources, only 10 tcm have been produced; 52.5 tcm are explored reserves (most of which in W estern Siberia); and 187.5 tcm are yet to be discovered. At present, nearly 97% of reserves are concentrated in 23 giant fields (with more than 500 bcm in each) and around 120 large fields (between 30 bcm and 500 bcm) which account for nearly all domestic production. However, many fields are at the gradual depletion stage, and pose challenges to gas production planning. Russia‘s gas production fell sharply in the 1990s in response to a collapse in domestic demand following the break-up of the Soviet Union, from a peak of 643 bcm in 1991 to 571 bcm in 1997. Production has since recovered and reached 641 bcm in 2005. Based on reserves and resources analysis, as well as the production capacities of the new fields, total Russian production potential could, over the next 25 years, increase between 27% (moderate scenario) and 40% (optimistic scenario). A large part of the increase is expected to come from independent producers. Table 1 Russian gas production potential in moderate and optimistic scenario bcm/yr 2004 2010 2020 2030 W est Siberia MS 575 564 520 520 OS 572 541 541 of which Yamal MS 0 0 100 250 OS 120 250 European Part onshore MS 45 40 50 61 OS 41 55 80 Shtockman 0 0 60 69 East Siberia and Far East MS 10 41 60 80 OS 52 70 90 Additional new fields MS 6 25 50 80 OS 30 60 100 Total production MS 636 670 740 810 OS 690 776 890 MS: moderate scenario; OS: optimistic scenario; Source: Center of Energy Policy, Moscow Russia has the world's largest gas network but the system is very old and needs substantial investment to maintain adapt it to growing gas deliveries. The United Gas Transmission System (UGTS) for example was close to its technical capacity limits by 2004. For the purpose of ensuring the required gas deliveries, Gazprom has been implementing a comprehensive programme for the existing infrastructure de-bottlenecking. The Russian transmission system consists of three major East-W est routes (Figure 4): - The Central route is designed to deliver gas to consumers in southern Russia and to export it to Europe via Ukraine as a transit country. - The Northern route provides gas to northwestern Russia and supplies gas through

8 Belarus to the Baltic countries and further to Poland and Germany. - The Southern route is used for consumers in southern Russia and adjacent countries including Ukraine. This route also enables Russia to interact with Central-Asian natural gas producers and is used for transportation of gas from Turkmenistan, Uzbekistan and Kazakhstan and gas exports to Ukraine and to Turkey (via the Blue stream pipeline). Regarding new routes, the largest project is the 1200 km Nord Stream project. The pipeline will run from Vyborg (near St Petersburg) through the Baltic Sea to Greifswald on the German coastline, thus bypassing potential transit countries. It is expected to come on stream in 2010, with an initial capacity of 27.5 bcm/yr, the addition of a twin pipeline after 2010, hence bringing total capacity to 55 bcm/yr. Figure 4 Russian gas transit infrastructure and projects to Europe

Y Yamal LNG A M 25 bcm A Shtokmanovskoye L Bovanenko Barents Sea Urengoy TYUMEN Shtockman LNG 23 bcm

Shtokmanovskoye Europe Baltic Pipeline 18-35 bcm te RUSSIA u o R Nord Stream rn e 2S7T-O55C KbHcmOLM h HELSINKI rt St Petersburg o N te Baltic Sea TALLINN ou l R ra Yamal I- Europe t en 29 to 32 bcm C te u Yamal II - Europe o R +32 bcm MOSCOW rn e h Yamal - Europe u o Kondratki MINSK S WARSAW

Uzhgorod Aleksandrov-Gay Novopskov KAZAKHSTAN New Transit Line UKRAINE through Ukraine 28 bcm Blue Stream 16 bcm Izmail Source: OME Gazprom has projects to expand the Central Asia œ Center (CAC) gas transportation system to improve gas transit from Turkmenistan, Uzbekistan and Kazakhstan. CAC currently puts through around 50 bcm annually but an additional line will bring the total capacity of CAC to 85 bcm/yr before 2010. In order to evacuate Central Asian gas to W estern Europe, a new transit line of 28 bcm/yr is planned. The project should run across Russia and Ukraine from the Kazakhstan-Russia border (Aleksandrov) to Uzhgorod.

9 It has been assumed here that all northbound Central Asian gas exports will enter the Russian system and therefore be available to the overall Russian gas pool. Potential imports from Central Asia are expected to triple, increasing strongly from 50 bcm in 2004 to 150 bcm in 2030. Rising gas demand in Europe is expected to remain the primary driver for future Russian gas exports, but we will increasingly see a wish to diversify gas exports into the other two large world markets: the North American and the East-Asian markets. In fact, Russia has projects aiming at developing exports to Asia from Eastern Siberia and Sakhalin. The Kovytka field development would require building an export pipeline to China and Korea. Moreover, Russia will soon enter the club of LNG exporting countries. It has several LNG projects in Sakhalin, Sakhalin-2 being the most advanced one - a two-train liquefaction plant with a capacity of 9.6 Mt/yr (13 bcm/yr). These projects target the Pacific markets. In addition, Russia has projects targeting the Atlantic and in particular the North American markets. Several projects have been proposed: Stockman LNG (feeding from the offshore Shtockman field); Yamal LNG; and Ust Luga LNG, near St. Petersburg. Taking into account of future domestic gas production potential, import potential from Central Asia, domestic demand evolution, total potential Russian gas exports are therefore assumed to increase from 222 bcm in 2005 to 446 bcm in 2030. As far as gas export potential to Europe-34 is concerned, it could increase from 134 bcm/yr in 2004 to some 207 bcm/yr by 2030. Should, however, future total Russian gas production levels be lower than estimated here above, we expect Russia to still satisfy its export potential to Europe as export infrastructure is largely available (we expect the reduction to affect mainly exports to East Asia and the North American continent).

2.5. The Caspian

Caspian countries have important reserves but their export potential is hindered by their geographical situation. Indeed, created under the Soviet era, the gas system of Turkmenistan, Kazakhstan and Uzbekistan had been designed to supply Russia. As a result, these countries remain dependent on Russia for their exports to W estern regions including Europe. To directly export gas to Europe, Caspian countries would need either to have access to the Russian gas system under fair TPA conditions, or to develop alternative routes. Two options are possible, across the Caspian Sea and further to Turkey, or via Iran. Azerbaijan and Iran are both endowed with large gas reserves and have ambitions of their own to export gas to Europe. Central Asian countries are therefore seen as competitors. Due to the increased distance, their gas supplies would also be more expensive. In addition, as far as transit through Iran is concerned, the strong US opposition and the recent Russia-Iran agreements make such a route highly unlikely. This is why, in this study, only Azerbaijan has a direct gas export potential to Europe, while it is assumed that Kazakhstan and Turkmenistan will have to export their gas to Russia which will resell part of it to European markets.

2.5.1. Azerbaijan Over 95% of Azerbaijan's gas production comes from offshore fields. Available forecasts for natural gas production for 2020 range between 30 to 70 bcm, with the higher figure assuming major development of gas condensate resources. W e expect a natural gas production boom in Azerbaijan following the ACG and Shah Deniz fields come online. After 2020, the rate of production should stabilise mainly due to the fact that the country is well explored and the probability of finding big oil and gas field is very low. Domestic consumption is expected to

10 double over the forecast horizon mainly as a result of the government‘s objective to switch all thermal power plants to natural gas. Export potential, therefore, is to increase from zero today to 20 bcm by 2030 and should make Azerbaijan an important gas supplier to Turkey and the rest of Europe.

2.5.2. Kazakhstan Considering the fact that Kazakhstan is under-explored and that the giant Tengiz and Karachanak oil fields with important associated gas reserves will heavily contribute to future gas production, we can expect more than a four-fold increase in production over the coming 25 years, from 22 bcm in 2005 to almost 90 bcm in 2030. This could even be higher if high pressure gas in Kashangan could be recovered. W e expect domestic consumption of coal to be replaced by gas in the future, which will increase the demand for gas in the country. However, the big discrepancy between production and domestic demand will make ever growing amount of gas available for exports. Exports could therefore increase dramatically from 6 bcm in 2005 to 50 bcm in 2030.

2.5.3. Turkmenistan Turkmenistan‘s remaining reserves are estimated at about 2900 bcm. However, it is generally considered that the country has been poorly explored. There should be a large potential for additional discoveries. During the Soviet era, Turkmenistan was a major gas supplier of the Soviet Union. It used to export about 90% of its production. In 1990, Turkmenistan reached its gas production historical peak with 85 bcm, over half of this volume going to Ukraine. The break-up of the Soviet Union led to a sharp decline, down to 13.2 bcm in 1998. Since then, production recovered, reaching 62 bcm in 2005. The Turkmen gas export system had mainly been designed to supply CIS countries through Uzbekistan and Kazakhstan to Russia. W hile currently limited to 45 bcm/yr, the initial capacity of this route was estimated at 100 bcm/yr. This transit system is in the process of being refurbished to regain its initial capacity. Turkmenistan also has an 8 bcm/yr pipeline to Iran. Turkmenistan‘s export potential is expected to increase from 46 bcm in 2005 to 120 bcm in 2030.

2.6. The Arab-Persian Gulf

Proved natural gas reserves in the seven Gulf countries under study (Iran, Iraq, Oman, Qatar, Saudi Arabia, United Arab Emirates, and Yemen) were estimated at almost 71 000 bcm as of January 2006, accounting for almost 40% of the world total. The bulk of known Gulf gas reserves are concentrated in a small number of giant accumulations. The region has nine of the 20 super-giant fields in the world, including the world‘s largest non-associated gas field, the Qatar‘s North Field. In addition, the ratio of non-associated to associated gas reserves in the Gulf is far lower than in most other regions of the world, and it is thought that the potential for the discovery of significant volumes of non-associated gas in the region could be high. In fact, although exploration for hydrocarbons in the Gulf has been carried out for almost 100 years, activity there has concentrated till recently on the search for crude oil rather than gas. It is only in recent years that exploration specifically targeted at discovering gas has been undertaken in various Gulf countries. This effort has involved drilling in previously identified, but unexplored structures as well as undertaking the drilling of more sophisticated and deep wells.

11 This new interest for gas in the Gulf has led to several export projects all over the region. However, two countries are to take the leadership in gas production and exports: Iran and Qatar. Qatar is, by far, the most advanced country in term of gas export projects. Figure 5 LNG plants and projects in Gulf countries

Homs BAGHDAD

DAMASCUS Iran LNG (9) QatargasI (9.6) Pars LNG (10) Amman QatargasII (15.6) IRAN NIOC LNG (9) QatargasIII (7.5) Persian LNG (9) QatargasIV (7.8) Basra RasgasI (6.6) KUWAIT RasgasII (9.4) RasgasII (4.7) Assaluyeh Oman LNG 1&2 (7) RasgasII (15.6) Oman LNG 3 (3.3) North Field SAUDI ARABIA ct BAHRAIN Dubai roje in P QATAR Das Island lph Existing Gaslines ABU Do DHABI GaslineProjects DasIsRlaInYdA 1D,2H&3 (5.7) Sohar UAE MUSCAT Existing LNG Plant (M t/y) DasIsland 4 (3.3) Sur LNG Plant Projects(M t/y) OMAN

Source: OME

2.6.1. Iran Iran has the second largest gas reserves in the world after Russia. As of January 2006, its proven reserves were estimated at 27,600 bcm. Of this, around 60% are located in non- associated fields and have not been truly developed. Most of this production will come from the South Pars field, which contains at least 8 000 bcm. The ambitious development plan calls for a gas production from this field of about 200 bcm by the beginning of the next decade but its development has been delayed by technical, contractual and political problems. Most of the gas is expected to be consumed domestically as final energy or for reinjection for oil recovery. Four LNG plants and several pipeline projects for the export markets in Asia and Europe are also envisaged after 2010. Turkey is connected to the southern Iranian gas fields through a 14 bcm/yr capacity gas line which could be expanded to 20 bcm in the future. Part of these pipeline gas exports should be destined for the Turkish market, while the remaining may reach the Europe-34 markets.

2.6.2. Iraq Iraq has proven reserves of around 3080 bcm, but many experts expect an additional undiscovered potential of more than 9000 bcm. Important gas fields are located in the North of the country and could therefore reach easily and cheaply Turkey and, from there, Europe- 34 markets. Currently all gas produced is used domestically. Because of the present uncertainty and chaos in the country it is not possible to have a clear understanding about what the future may hold. However, it is clear that Iraq needs oil and gas exports to help develop its economy. The current government puts emphasis on the development of oil fields and related infrastructure, and increase the domestic use of gas. W e expect domestic demand for gas to expand importantly up to 2030 due to an expected population increase of 50% as well as the switching to gas for electricity generation. To be able to meet the domestic demand and export commitments, the production has to be boosted. This can be achieved

12 easily if required investments take place. Due to Iraq‘s potential and restrictions, we do not see a significant export potential to Europe before 2020, but it could reach some 20 bcm by 2030.

2.6.3. Qatar As of January 2006, proven natural gas reserves of Qatar were evaluated at 25 783 bcm, practically all contained in one of the largest gas fields in the world, the North Field. The North field gas reserves are estimated at 25 500 bcm. Gross gas production was 47 bcm in 2005, of which approximately 20% was reinjected and used for shrinkage. In May 2005, Qatar has brought forward by 10 years its plan to produce 248 bcm/yr starting 2010 (originally targeted for 2020). W e think this target for 2010 to be rather ambitious and that it will be difficult to obtain before 2015. The present LNG capacity of 25.5 Mt/yr is expected to strongly increase to 77 Mt by 2010- 2012 both by debottlenecking the trains in the existing LNG plants and by building eight seven new trains in four new LNG plants. This huge and aggressive gas export development programme aims at boosting LNG capacity from 34 bcm/yr in 2005 to 103 bcm/yr by 2010- 2012. W hile Qatar‘s main export markets have traditionally always been Far East Asia, the new policy is to re-equilibrate market destinations with Europe, Asia and the US, each representing one third of total exports. This means that Qatar has already signed sales and purchase agreements with European clients of a total of 36 bcm/yr by 2010. Qatar‘s LNG export potential to Europe could thus reach 80 bcm/yr by 2030.

2.6.4. Oman Discoveries through the 1990s increased Omani proved gas reserves from under 300 bcm to 995 bcm at the beginning of 2006, almost 90% of which is non-associated. Natural gas production was 17.5 bcm in 2005. Oman‘s liquefaction plant located in Qalhat has two trains of 3.3 Mt/yr (4.5 bcm/yr) each. A third train of 3.6 Mt/yr (4.9 bcm/yr) was put on-stream in early 2006. This will bring Oman‘s total liquefaction capacity to 10.3 Mt/yr. Due to the limited Omani gas reserves, we do not expect additional LNG plants in Qatar after the presently planned third train. Most exports will target the Far Eastern markets, only small volumes being available for Europe.

2.6.5. United Arab Emirates UAE‘s proven natural gas reserves are currently estimated at 6000 bcm. But, as elsewhere in the Gulf, most of the gas reserves in the Federation are in associated form (90%). Undiscovered gas resources in the country are relatively small. Among the UAE, Abu Dhabi is the only gas exporting state. In 2005, it exported 7.1 bcm of LNG, almost all to Asia. Abu Dhabi has one liquefaction plant in Das Island, composed of three trains with a total capacity of 5.7 Mt/yr. Feasibility studies are being carried out for a fourth train which would increase UAE‘s liquefaction capacity to 12 Mt/yr (16.3 bcm/yr). W e expect the UAE to continue to target Asian markets, leaving only marginal volumes available for Europe.

2.7. Summary of long-term potential supply volumes to Europe

W hile Algeria, Norway and Russia are expected to keep their dominant role as far as supply potential is concerned, there appears to be a spectacular progression of supply potential from Middle East and from Nigeria, Libya and Egypt (see Table 2 and Figure 6). That means that Europe will need both important new pipeline and LNG infrastructure. LNG represents a third of the total supply potential outside Europe in 2030. Such an evolution would require to

13 spectacularly develop the European gasification capacity. The LNG supply potential is, indeed, assessed at 227 bcm/yr in 2030, against only 37 bcm in 2005. Needless to say that not all this potential will be tapped if import requirements do not ask for it. On the other side, should import requirements be higher than expected, additional gas volumes to Europe could be made available especially (but not only) from Russia and Qatar. These countries do not only have a huge reserve potential, but their allocation between different world markets will be adjusted to demand requirements. Table 2 Gas supply potential to Europe-34 by exporting country, projections to 2030 2005 2010 2020 2030 Production Exports … to Production Exports … to Production Exports … to Production Exports … to Europe Europe Europe Europe Norway 87 81 81 105 98 94 114 125 115 140 130 120 North Africa 143 78 67 214 131 116 293 179 163 353 203 181 Algeria 91 65 57 123 91 81 160 119 110 176 125 115 Egypt 41 8 5 68 26 23 93 33 28 122 38 28 Libya 11 5 5 23 14 12 40 27 25 55 40 38 W est Africa 22 12 11 54 38 21 136 105 38 171 130 45 Angola 1 0 0 8 7 0 9 7 2 17 14 4 Nigeria 21 12 11 46 31 21 127 98 36 154 116 41 Russia 641 223 139 690 265 166 776 369 196 890 446 207 Caspian 147 52 0 240 136 0 297 167 13 344 192 13 Azerbaijan 6 0 0 18 7 0 35 20 13 38 20 13 Kazakhstan 22 6 0 46 27 0 68 40 0 87 50 0 Turkmenistan 62 46 0 106 90 0 122 100 0 147 120 0 Uzbekistan 58 0 0 70 12 0 72 7 0 72 2 0 Arabo-Persian Gulf 203 49 7 394 177 44 711 340 108 901 405 143 Iran 101 4 0 165 43 0 298 106 35 358 114 35 Iraq 2 0 0 7 2 0 25 12 5 50 25 20 Oman 18 11 2 23 14 2 27 14 2 32 14 2 Qatar 44 27 5 142 102 36 278 188 60 355 232 80 UAE 40 7 0 47 8 0 69 12 0 86 12 0 Yemen 0 0 0 10 8 6 14 8 6 20 8 6 Latin America 56 14 1 86 38 6 123 63 6 134 68 6 Trinidad and Tobago 28 14 1 35 23 6 47 37 6 43 37 6 Venezuela 28 0 0 51 15 0 76 26 0 91 31 0 Total 1300 509 305 1783 883 447 2450 1348 639 2933 1574 715 (1) Russia exports in 2005 include 4 bcm from former FSU Republics (2) The assumption made in this study is that Kazakhstan, Turkmenistan an Uzbekistan will not be able to sell their gas directly to European markets but rather to Russia which could resell part of it to Europe. Central Asian gas exports have therefore been accounted for in the Russian export potential. Source: CEDIGAZ (2005 figures) and OME (projections)

14 Figure 6. Gas export potential to Europe-34 of the main producers

2005 304 bcm 2010 447 bcm NORW AY 120 115 94 81 2020 639 bcm 2030 715 bcm 207 196 RUSSIA 166

T& 39 T + 1 1 VE NE 6 Z. 6 6 AZERB. 13 13 TURKM ENISTAN A IC R F A . 5 20 35 W 35 11 IRAQ IRAN 21 38 57 81 110 115 45 ALGERIA 5 12 25 38 5 23 28 28 LIBYA 7 44 68 88 EGYPT QATAR/ UAE/ OM AN/ YEM EN

Source: OME

2.8. Supply costs of future gas deliveries to Europe

Technical gas supply costs to Europe-34 and the EU-15 have been assessed in Figure 7 and Figure 8. The methodology used is based on a long run marginal cost approach, including investment and operating costs (technical production cost, technical transport cost and transit fees where applicable) but exclude producing countries royalties. Infrastructures are supposed to work close to their economic optimum; when they are amortized, it is assumed that they will have to be replaced. Expected future technological development (2010-2020-2030) has been accounted for. Due to their low production cost and their proximity with Europe, North African exporters are the most competitive. Norway‘s supply cost is also low and has an undeniable advantage for supplying the huge UK market, while the bulk of Russia‘s additional supply (Yamal and Shtokman) is the most expensive option for Europe. It is interesting to notice that Middle Eastern and Caspian gas pipelines across Turkey and the Balkans are cheaper than the new Russian arctic sources. LNG appears more expensive than most pipeline options, except from Russia, but Russia benefits of existing amortised infrastructure. Timing of project realisation does generally not follow any merit order based on cost. This means that other considerations play an important role. These issues include i- Bottlenecks (for technical or political reasons (transit issue), some routes are difficult to develop); ii- Diversification of supply; iii-Strategic reasons (some exporters accept a lower economic rent for supplying Europe because they do not have other export alternatives); iv-Geopolitics; etc. Also, high gas prices make it possible to develop expensive projects. W hen prices are far above costs, the latter is no more a constraint in the competition between suppliers and, as the oil markets show, expensive supplies can compete with the cheapest. If, however, gas prices fall again to much lower levels, supply cost consideration become more important.

15 Figure 7 Supply cost* of new gas delivery to Europe-34 in $/M Btu

Pipeline Barents Sea LNG Norwegian Sea Yamal 4 .4 .9 5 2 2 8 .1 $ $ .8 2 $ 2 $ North 2 Nadym-Pur-Taz $ .9 3 Sea $3.11 .59 $2.53 $2

1 8

8 .0

5 $2 . .

. .

1 1

$ $

$ $ UK 9 $2.4 RUSSIA $1.9

$1.53 Volga- r Ural ta .1 a 8 2 $ .6 ia $ 2. Q 2 r 51 $ e lg 5 .2 A 2 $

& d $

a 1 AZERB.

d . i o 4 $1.6 in g 5 r a $ T b 2

o . TURKM EN. T 5 1 .4 2 $2. $2 2 5 $2.5 $ $ 1 .4 74 $ 2 . . . 2 $ $1 1 35 5 $2.27

$ 1 . 2 $ . 6 a 1. 1 2 $ 44 8 . i 8 $ 2 $ $ 1 r 2 $ 2 2 . e . 7 . 1 . 5 g 2 5 0 i 7 N IRAN

ALGERIA LIBYA EGYPT QATAR $2.6 $2.48 Gulf LNG * Excluding producing countries‘ royalties Source: OME Figure 8 Supply cost* of new gas delivery to the European Union-15 in $/M Btu

Pipeline Barents Sea LNG Norwegian Sea Yamal 4 .4 .9 5 2 11 2 8 .1 $ 3. $ .8 2 $ $ 2 $ North 2 $ .9 3 Sea .84 $2.53 Nadym-Pur-Taz

8 2.28

5 5

. . $

. .

1 1

$ $

$ $ UK $2.79 RUSSIA $1.9

$1.83

Volga- r 5 Ural 5 ta . 0 a 8 2 .7 $2 .6 ia $ 2 . Q 2 r 81 $ e $ lg 5 .2 A 2 $

& $ AZERB. d 1 .

a 4 d $2.05/2.2 i o 5 n g $ i a $ r 2 2 b .65 TURKM EN.

T 5 . o .4 1 $2

2 . T $2 80 .09 $ 3 4 5 $ $ .2 1 3 4 4 $ . $ 7 2 $ 1 . . 2 1 1 . 9 . $ 1

$ 1 . 7 2 $1. 8 6 $ 44 8 2 a $ $ i $ 2 . r . 2 1 2 1 e 5 . 7 . 3 g 2 i 2 7 N IRAN

ALGERIA LIBYA EGYPT QATAR $2.6 $2.48 Gulf LNG

* Excluding producing countries‘ royalties Source: OME

16 3. New gas corridor infrastructure needs and incentives for investment promotion

3.1. Gas corridor infrastructure needs

As Figure 3.7 shows, several gas corridors are in a stage of reinforcement or to be developed. The traditional routes to Europe are all being strengthened. Six new pipeline corridors are under development, from Norway to the UK (Langeled pipeline), from Russia to Germany across the Baltic (Nord Stream), from Algeria to Spain (Medgaz) and to Italy (Galsi). Another important route under development is the corridor from the Middle East and the Caspian across Turkey, further prolonged by pipelines across Greece (Turkey-Greece-Italy interconnection) or across the Eastern Balkan to Austria (Nabucco) which would allow Europe to diversify its supply sources. Several LNG gasification terminals are also under development or have been announced in several European countries. LNG penetration is particularly spectacular in the UK and is supposed to be important in Italy. However, some of these projects are exposed to administrative obstacles (especially in Italy). Figure 9 Ongoing and future gas corridors development to Europe

Pipeline reinforcement New pipelines New liquefaction terminals New gasification terminals Source: EC DG TREN and OME The assessed pipeline projects could provide an additional 100 bcm/yr of import capacity to Europe by the beginning of the next decade (see Table 3). Moreover, the announced LNG projects would represent an additional import capacity of about 100 bcm/yr by the beginning of the next decade. The number of proposed projects could therefore support the idea that there is no problem of investment in international gas infrastructure to Europe. It should be underlined, however, that many of these projects have been around for quite a while and there is often a long lead-time for project completion. There might also be a selection carried out among the projects and not

17 all might be realized. It remains therefore necessary to ensure that, at least, the required additional supply will be available in due time.

Table 3 M ain greenfield pipeline projects to Europe Capacity Investment Project Supplier From To Foreseen Start-up [bcm] [M ⁄] Medgaz Algeria Hassi R‘Mel Spain 8 to 10 1300 End 2008 GALSI Algeria Hassi R‘Mel Italy 8 to 10 1200 2009-2010 ITG-IGI Caspian Greece Italy 8 to 10 950 (IGI) 2011 Nord Stream Russia Vyborg Germany 2x 27.5 4000 2010 Langeled Norway Ormen Lange UK 22 to 24 1000 2006-2007 Nabucco Caspian Turkish border Austria 25 to 30 4600 2010 Total additional supply capacity to Europe 98.5 to 139 Source: OME

3.2. Investment barriers by type of import project At the heart of investment financing issue is the relation between uncertainty, cost of investments and profitability. The four examples presented hereafter show that some projects remain sustainable by themselves, while others are more difficult to achieve and may need a political or regulatory support. • The Nord Stream is a big offshore pipeline (27.5 bcm) across the Baltic Sea, directly linking Russia and Germany. W hile E.ON, W intershall and Gasunie are now official partners, it was designed and decided without any supply agreement with importers. Promoted by Gazprom, it aimed at bypassing transit countries like Ukraine. Supported a few big promoters, this project does not seem to face any important obstacle. • The M edgaz project (8 bcm) from Algeria to Spain was first proposed by CEPSA and Sonatrach to secure gas supply to Spain. Rapidly, several partners entered the project, including the main Spanish utilities as well as Total, GDF and BP. In fact, the Medgaz also targets France and the European market. Promoted by importers, the investment decision will be taken by the end of 2006 and the pipeline should be operational by 2009. • The Galsi pipeline (8 to 10 bcm) from Algeria to Italy via Sardinia, is a joint initiative of Sonatrach, Enel, Edison and several other partners, all booking a small part of the shipping capacity. The shipping agreements will decide of the timing of the project. Contrary to the Nord Stream, the Galsi does not benefit from the support of one or two big importers which could provide some guarantees about the future throughput. • The Nabucco project is a big pipeline (25-30 bcm) which aims at directly connecting the Caspian and Middle East gas resources to the EU gas markets. W hile the potential benefits of this project are very significant in terms of diversity of supply and stimulation of competition, it remains difficult to complete so far because of the complexity of transit issues and difficulties in coordinating investments in production and transit infrastructure. • Some LNG gasification projects advance rather easily when supported by incumbents or big producers (like the Fos terminal in the South of France developed by Gaz de France, and gasification terminals in Spain and the UK), while some promoted by new entrants (like the Brindisi terminal developed by British Gas as well as several other terminals in Italy) are regularly delayed because of administrative obstacles and commercial risks.

In sum, the level of barriers to investment can be estimated by the exposure of projects to different risks including market risk (uncertainty on price and volume), regulatory risk

18 (impact of market rules and regulation on new infrastructures profitability) and political risk (uncertainty relating to international relations and transit risk). Risk exposure and the investors‘ capacity to hedge them have a direct impact on long term projects‘ sustainability and investment incentives. As presented in Table 4, we have identified three categories of projects, more or less vulnerable to different risks: exporter promoted projects (e.g. Nord Stream), importer promoted (e.g. Medgaz, Fos LNG terminal) and midstream promoted (e.g. Nabucco, most LNG terminals). Exporter and importer promoted projects are relatively the least difficult to complete due to large market shares and financing capacity of investors.

Table 4 M ain characteristics of import projects by category M idstream Exporter promoted Importer promoted promoted Exporting companies Leader Partner Partner/ not involved Importers (incumbents) Partner Leader Partner/ not involved Private producers/shippers Partner (sometimes) Partner Leader/Partner Entrants Very rare Partner Leader/Partner Number of partners Small Small High Vulnerability to market risk Low Low High Type of regulatory risk Few risks Incumbent market share Third party access Main political dimension International relations Security of supply Competition Source: OME The most difficult to realise are ”midstream promoted‘ projects, both pipelines and LNG gasification terminals, which aim at penetrating markets rather than consolidating a downstream or upstream-based position. This category is more vulnerable to risk and may require a political support given that these projects promote competition and diversification of supply.

3.3. Incentives to promote investment in gas infrastructure In a competitive context, policy makers‘ action essentially relates to regulation: stabilising the investment climate, reducing regulatory risks and implementing the conditions for weakest projects to be more secured economically. It is also of key importance to consider that international gas infrastructures are only a part of gas chains which include producing fields. In fact, due to high technical risks, field developers cannot afford entirely carrying the market risk, which has to be charged to downstream operators. Regulation must therefore make it possible to develop commercial agreements in line with the following risk sharing: technical risks upstream and commercial risks downstream. The more projects are exposed to risks, the more they are difficult to implement. Therefore, to promote investment in gas corridors, political and regulatory initiatives should focus on three categories of actions: a) Market risk mitigation Unbundling the gas chain, reducing downstream market protections and developing competition have raised risks which have to be covered by operators. To facilitate that coverage, it is recommended to: − Allow long term agreements, including the classical long term contracts, between upstream/midstream operators and downstream companies: that involves the possibility to protect the upstream, in charge of technical risks, by having downstream wholesalers carrying the commercial risk.

19 − Provide a specific status to upstream arrangements such as joint ventures involving several partners. To facilitate gas commercialisation, such joint ventures should be considered as a unique gas supplier and not as a consortium of individual gas producers. − Completing the Internal M arket to help wholesalers and corridors developers hedging market risks. That involves a broader access to the national markets by developing interconnections and homogenising regulations in Europe. b) Regulatory risk mitigation Regulation is regularly adapted to the evolution of market conditions (third party access, pricing, etc.). Even if required, these changes introduce an additional uncertainty which can be an important barrier to investment. To support gas corridors development, it is therefore recommended to: − Address third party access regulation to new infrastructure on a case by case basis. Project developers take a risk and cannot afford opening the door to free riders. This risk must be recognised by regulators, providing third party access exemptions compatible with the internal market rules. Open season is a satisfactory solution, providing a compromise between protection for investors and the development of competition. − Clearly define the borders of the European internal gas market to address the regulation which is applied to the different operators involved in gas corridor development. It is notably important to address the status of the final parts of pipelines located inside the EU while part of international corridors. − M ake regulation more predictable and stable: frequent regulatory changes lead investors to anticipate on future changes which can lead them to delay their investments. It is therefore important to make regulation dynamics more transparent by clearly stating the political priorities (competition vs security of supply for instance). c) Political risk mitigation The international dimension of gas trade exacerbates its exposure to political risks, namely institutional instability in producing and transit countries, conflicts between governments, etc. A proper and friendly political framework improves hugely the investment climate. Also, some economic/institutional support should be considered for projects which increase security/diversification of supply and competition but which encounter important barriers. − Remove institutional and legal obstacles to new projects development: this is particularly true for gasification terminals, often delayed or postponed for administrative and political reasons. − Financial support to priority corridors: when investments considered as important for security and diversification of supply cannot be completed exclusively on the basis of market considerations (lack of throughput guarantees for example), they should be supported by institutional loans (EIB, EBRD) or sovereign guarantees. − International dispute settlement bodies: having credible referees to arbitrate international disputes provides additional security to investors. Further developing the action of the Energy Charter Treaty and other supra-national bodies should be promoted. − International stability and confidence. As the security of supply issue involves several complementary countries, all the potential partners need to work together. Hence, balanced positions taking into account the interest of producing countries and transit countries in international negotiations are recommended rather than exclusively focusing on the European security of supply.